July 10, 2017
Submitted via www. regulations.gov
W ater Division US Environmental Protection Agency, Region 6 1445 Ross Avenue, Suite 1200 Mail Code: 6EN Dallas, TX 75202-2733
RE: Joint Trades Comments Notice of Proposed NPDES General Permit Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Category for the Western Portion of the Outer Continental Shelf in the Gulf of Mexico (GMG290000) Docket ID No. EPA-R06-OW-2017-0217
The Offshore Operators Committee (OOC), the American Petroleum Institute (API), and the National Ocean Industries Association (NOIA), hereinafter referred to as "the Joint Trades," appreciate the opportunity to provide detailed comments on the above-captioned NPDES General Permit. Comments submitted on behalf o f the Joint Trades are submitted without prejudice to any m em ber's right to have or express different or opposing views. It is from this perspective that these comments have been developed.
The Joint Trades
API is a national trade association representing more than 625 member companies involved in all aspects o f the oil and natural gas industry. A PI's members include producers, refiners, suppliers, pipeline operators, marine transporters, and service and supply companies that support all segments o f the industry. API and its members are dedicated to meeting environmental requirements, while economically and safely developing and supplying energy resources for consumers. API is a longstanding supporter o f offshore exploration and developm ent and the process laid out in the Outer Continental Shelf Lands A ct ("OCSLA") as a means o f balancing and rationalizing responsible oil and gas activities and the associated energy security and economic benefits with the protection o f the environment.
NOIA is the only national trade association representing all segments o f the offshore industry with an interest in the exploration and production o f both traditional and renewable energy resources on the U.S. Outer Continental Shelf (OCS). The NOIA membership comprises more than 325 companies engaged in a variety of business activities, including production, drilling, engineering, marine and air transport, offshore construction, equipment manufacturing and supply, telecommunications, finance and insurance, and renewable energy.
OOC is an organization o f 41 producing companies and 53 service providers to the industry who conduct essentially all oil and gas exploration and production activities in the Gulf o f Mexico (GOM) OCS.
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Founded in 1948, the OOC is a technical advocate for the oil and gas industry regarding the regulation o f offshore exploration, development and producing operations in the GOM.
Comments
The Joint Trades' detailed technical comments are included in the attachment. The Joint Trades believe the information included in the attached comments is important and critical to providing a final permit that is protective o f water quality in the GOM, as well as a practical permit that allows the continued development o f our nation's energy resources. The attached comments are structured to include suggested edits to the proposed permit language and justification for the suggested change.
Cooling Water Intake Structure Entrainment Monitoring
One concern that the Joint Trades would like to highlight is the continued requirements for cooling water intake structure entrainment monitoring (see Comment 37 in the attachment for more details). The Joint Trades strongly object to the continued requirement to conduct ongoing entrainment monitoring. The Joint Trades request the removal of entrainment monitoring/sampling requirement and the addition of language requiring permittees to submit a SEAMAP data report annually.
40 CFR 125.137.a.3 provides the Director the flexibility to reduce the frequency of monitoring following 24 months o f bimonthly monitoring provided that "seasonal variations in species and the numbers o f individuals that are impinged or entrained" can be detected. The report on the 24 month industry entrainment study (1) documents that many important G ulf o f Mexico species were not detected at all in the regions where new facilities are expected to be installed so that entrainment impacts on these species will be zero; (2) provided documentation on the seasonal dependence o f species and number o f eggs and larvae available for entrainment, and (3) concludes that anticipated entrainment will have an insignificant impact on fisheries in any season; the Joint Trades believes that the intent o f 40 CFR 125.137 has effectively been met and that the requirement for ongoing entrainment monitoring can be removed.
Our request is based on the results o f the results o f the recently completed G ulf o f Mexico Cooling W ater Intake Structure Entrainment Monitoring Study and reinforced by the quarterly entrainment monitoring reports by individual operators. Industry believes that these results warrant removal of the entrainment monitoring/sampling because (a) the study showed that no meaningful impacts from entrainment are expected; (b) no meaningful impact was found, therefore, the seasonality o f the impact is a moot point; (c) the SEAMAP database provides a continually-updated source o f information that is functionally equivalent to permit-required monitoring for the purpose of estimating entrainment impacts.
The G ulf of Mexico Cooling W ater Intake Structure Entrainment Monitoring Study was conducted for the purposes o f informing policy and permit requirements with sound science. The conclusions o f the study are clear - there are no meaningful impacts. Yet, the science presented in the study is not being utilized to inform changes to permit requirements.
Regulatory Reform Initiatives
In addition to the detailed, technical comments included with this letter, the Joint Trades also plan to engage EPA Headquarters in discussions regarding the impact o f the recent Presidential Executive Orders 13771, Reducing Regulation and Controlling Regulatory Cost, and 13795, Implementing an America-First Offshore Energy Strategy, on the renewal o f NPDES Permit GMG290000. As presented in the attached detailed comments, the Joint Trades offer several positions that question the necessity of changes proposed
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in the draft permit. The proposed changes, taken in their entirety, do not appear to be in keeping with the intent ofE.O . 13771 and E.O. 13795. Therefore, it is our intent to engage EPA on the need for the proposed changes, whether the proposed changes provide any benefits for water quality o f the G ulf of Mexico, and if the proposed changes comply with the Executive Orders. Also, the Joints Trades, through OOC, will be contacting EPA Region 6 staff, after the comment period closes, to request a meeting to review the attached technical comments, and answer any clarifying questions the agency may have regarding the information provided here. The Joint Trades appreciate EPA 's efforts regarding the draft permit, and look forward to working with the agency on the important issues included in our comments as the permit is finalized. If you have any questions or require additional information, please contact Mr. Greg Southworth at greg@offshoreoperators.com, or Mr. James Durbin atjames.durbin@ c-ka.com.
Sincerely,
/! 1 LJ Greg Southworth Associate Director Offshore Operators Committee
Amy Emmert Senior Policy Advisor American Petroleum Institute
Tim Charters Senior Director National Ocean Industries Association
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cc (via email):
Environmental Protection Agency: Scott Pruitt, Administrator Samuel Coleman, Regional Administrator, Region 6 Bill Honker, Water Division, Region 6 Scott Wilson, Energy Coordinator, Industrial Branch/Water Permits Division Stacey Dwyer, Associate Director, NPDES Permits & TMDL Branch, Region 6 Brent Larsen, Permits & Technical Section, Region 6 Isaac Chen, Permits & Technical Section, Region 6 Mitty Mohon, NPDES Enforcement Officer, Region 6 Sharon Angove, NPDES Enforcement, Region 6
Bureau of Safety and Environmental Enforcement: Scott Angelle, Director Lars Herbst, Gulf of Mexico Regional Director TJ Broussard, Gulf of Mexico Regional Environmental Officer
Bureau of Ocean Energy Management: Walter Cruickshank, Acting Director Michael Celata, Gulf of Mexico Regional Director Gregory Kozlowski, Gulf of Mexico Deputy Regional Supervisor, Office of Environment
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Draft NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000)
GMG290000 May 11, 2017 Draft Renewal Permit, Docket # EPA-R06-OW-2017-0217 - The Joint Trades Comments
General Note - all permit text is shown in quotations. All suggested revisions to the proposed permit text are shown in red and st-r-i-keth-retigh-s within OOC's comments.
Comment No. 1
Type/Category Notice of Intent
Permit Section Ref. Part I.A.2
Current or Revised Permit Language /C!arifications/!ssue
"A Notice of Intent (NOI) must be filed 24-hew in advance to cover specific discharges prior to commencement of specified discharges."
Rationale The Joint Trades request that the 24-hour requirement of this condition be removed.
In certain situations, it is not always feasible for a permittee to file a Notice of Intent (NOI) 24hours in advance to cover a discharge.
Due to potentially sudden and unforeseen changes in operational priority, weather conditions, asset availability/functionality, an operator will not always know about commencement of discharging 24-hours in advance. For example, a lift boat conducting well work operations within a specific field is unexpectedly being reprioritized due to any, or all, of the unforeseen factors mentioned above. This requirement could result in additional costs for the operator up to, and including, the day rate for a drill ship or vessel, approximately $1 million per day.
The Joint Trades feels that removing the 24-hour notification is more feasible for compliance, while still obtaining proper NPDES coverage prior to discharging.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
2
Notice of Intent Part I.A.2 The primary operator must file an electronic Notice of Intent (eNOI) for
discharges directly associated with oil/gas exploration, development or
The Joint Trades request striking the red text language. There are instances where third-partv
production activities to be covered by this permit. A separate eNOI is
operators are in direct control of discharges which are directly associated with exploration,
required for each lease block and that eNOI shall include all discharges
development or production activities. There are also instances when third-party operators may
controlled by the primary operator within the block. Other operators or
be in direct control of the same type of discharges covered by the eNOI filed by the primary
vessel operators must file an eNOI to cover discharges which are directly operator. This requirement puts the liability burden on the primary operator for discharges in
under their control but-afe-n^&t-dfF-e&t4y-a-&so-i-ate4-with-&xpteratio-n7
which they have no direct control.
eevefed-by-e^JQ4s-fUed-fey44e-primafy-operatof. Individual coverage by this The draft permit language is more onerous on operators and the additional burden to the O&G
permit becomes effective when a complete eNOI is signed and submitted. Industry does not have any apparent additional protection to the environment.
3
Notice of Intent Part I.A.2
The Joint Trades request clarification on whv a separate NOI would now be needed for bridged
facilities with duplicate discharges.
BOEM and BSEE recognize bridged facilities as one complex with a single assigned ID
number.
Historically, operators have always reported the worst case for multiple discharges
within one permitted outfall or feature (PF), whether reporting by lease block or by
structure, (i.e. multiple types of miscellaneous discharges, or multiple outlets of one
discharge on stand-alone platforms are reported under a single PF number, and one
DMR).
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Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
The total number of permit exceedances will continue to be reported as required for one PF number limit set DMR, including all discharge points on the facility whether bridged or stand alone.
Covering and reporting multiple bridged facilities separately will generate more Permitted Feature numbers and additional DMRs to be managed by the electronic reporting system, not to mention additional costs associated with the additional coverage reporting.
Therefore, the Joint Trades request that the proposed requirement for separate NOIs be removed from the proposed permit language.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
4
Notice of Intent Part I.A.2 "Operators who filed eNOIs under the previous permit, issued on
September 28, 2012, (2012 issued permit) are required to file new eNOI
The Joint Trades are requesting changes and additions to the permit language to provide claritv
within 90 days from the effective date of this general permit. All existing
when eNOI system is unavailable and thus allowing a short paper NOI submittal. In addition, the
eNOIs under the 2012 issued permit expire 90 days after the effective date Joint Trades are requesting a 45-dav time-period for submittal of the official eNOI via the eNOI
of this general permit. If the eNOI system is unavailable D-ufmg-the-ctewn system in-order to provide clarity of expectations. The current language can imply as soon as the
tlme-of-the-eN-QI-system, operators may submit a short paper NOI which
system is available an eNOI must be submitted. Since submitting the short paper NOI will allow
includes information a) through f) listed below or via emails-to
for coverage under the permit, a 45-day period to submit the official eNOI is simply
R6_GMG29TEMPeNOI@epa.gov. The stamp date and time of the sent
administrative.
email is evidence of delivery for coverage. An oOfficial eNOIs shall be filed
within 45-days of when the eNOI system becomes available."
It is not clear as to the timeframe when EPA will update the applicable systems (i.e. eNOI and
NetDMR) with the information that is submitted. The Joint Trades request clarification and an
estimated schedule of when the applicable systems will be ready for use.
The Joint Trades are requesting an email address correction based on beta testing issues with EPA Region 6 where it was determined the wrong address was listed in the draft permit.
Not accepting the proposed permit language is onerous on operators and an additional burden
to the O&G Industry with no apparent additional protection to the environment.
5
Notice of Intent Part I.A.2 "Facilities which are located in lease blocks that are either in or adjacent to
"no activity" areas or require live bottom surveys are required to submit
The Joint Trades request striking out information such as "drills, installations, discharges...". The
both an eNOI that specifies they are located in such a lease block and a
information is covered in Part 1. A.2 (a through 1). The information regarding drills is covered in
notice of commencement of operations (e-;g.-r4ril-l-s7-mstaftet-io-R-&;'
the drilling permits to BOEM. Also, it is unclear how this information would be added to the
discharges,....)"
eNOI system. The eNOI system already keeps track of the types of discharges that are being
planned.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
6
Notice of
Part I.A.3 3. Termination of NPDES Coverage
The Joint Trades request a one vear time frame for submittal of NOTs following termination of
Termination
lease ownership. This request is to account for the many possible reasons a Permittee may be
Lease holders or the authorized registered operators shall submit a notice required to hold permit coverage following lease termination.
of termination (NOT) to the Regional Administrator within one year6Q days
of termination of lease ownership for lease blocks assigned to the operator Operators have up to 1-year from lease expiration to remove a facility. During this timeframe,
by the Department of Interior. (Request for time extension and justification there could be removal and/or abandonment operations that result in discharges authorized by
to retain the permit coverage beyond the one year 60-day limit shall be
the permit. A one year time period reduces the number of NOTs and NOIs, where an operator
sent to the address listed in the subsection 5 below.) In the case of
terminates coverage and then has to reapply for coverage of discharges with in a one year time
temporary operations such as hydrostatic testing, well or facility
frame.
abandonment or any other contractual or legal requirement the NOT shall
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Comment No.
7
Type/Category
Other Reporting Requirements
Permit Section Ref,
Part I.A.5
Current or Revised Permit Language /Clarifications/lssue
be submitted within one year 60-days of termination of operations. The discharge monitoring report (DMR) for the terminated lease block may be either submitted with the NOT, or submitted on the reporting schedule. The NOT shall be effective upon the date it is received by EPA. "All NOIs must be filed electronically. Instruction for use of the electronic Notice of Intent (eNOI) system is available in EPA Region 6's website at http://www.epa.g0 v/region6/ 6 en/w/offshore/hom e.htm .
Rationale The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades are requesting an email address correction based on beta testing issues with EPA Region 6 where it was determined the wrong address was listed in the draft permit.
Operators shall either mail all temporary paper NOIs, NOTs, notices of transfer agreements, notice of merger/acquisition, notice of commencement and all subsequent paper reports under this permit to the following address:
Water Enforcement Branch (6 EN-WC) U.S. Environmental Protection Agency Region 6 1445 Ross Avenue Dallas, TX 75202 or email pdf documents to an email address at R6 GMG29TEMPeNOI@epa.gov|r
If the eNOI system is unavailable, operators may submit a short paper NOI which includes information a) through f) listed in Part I.A.2 via email to R6_GMG29TEMPeNOI@epa.gov. The stamp date and time of the sent email is evidence of delivery for coverage. An official eNOI shall be filed within 45 days of when the eNOI system becomes available.
Additional information regarding these reporting requirements may be found at: http://www.epa.g0 v/region6/ 6 en/w/offshore/home.htm"
The Joint Trades are requesting the additional language to this section of the permit to provide clarity when eNOI system is unavailable and thus allowing a short paper NOI submittal. In addition, OOC is requesting a 45 day time for submittal of the official eNOI via the eNOI system in order to provide clarity of expectations.
Further, it should be noted that the EPA website listed is not currently active. The Joint Trades request that this website be activated prior to the effective date of the permit. Additionally, the Joint Trades request the ability to review the electronic NOI instructions prior to them being finalized to allow for clarification and edits as necessary.
It is not clear as to the timeframe when EPA will update the applicable systems (i.e. eNOI and NetDMR) with the information that is submitted. The Joint Trades request clarification and an estimated schedule of when the applicable systems will be ready for use.
The Joint Trades request that in addition to the electronic NOI instructions, a set of instructions also be made available for DMRs and NOTs. Similar to the electronic NOI instructions requested above, OOC further requests the ability to review the electronic NOT and DMR instructions prior to them being finalized to allow for clarification and edits as necessary.
See comment # 41 for additional information regarding NetDMR.
The lack of active website, email address and NOI, NOT and DMR instructions is very onerous on
operators and the burden to the O&G Industry does not have any apparent additional protection
to the environment.
8
Non-Aqueous Part
Base Fluids Retained on Cuttings.
Based Drilling
I.B.2.C.2
Monitoring shall be performed at least once per day when generating new The Joint Trades are requesting the changes to reference the correct section of the permit and
Fluid -
cuttings, except when meeting the conditions of the Best Management
the agency that replaced Mineral Management Service.
Retention of
Practices described below. Operators conducting fast drilling (i.e., greater
Cuttings and
than 500 linear feet advancement of the drill bit per day using non aqueous
BMP
fluids) shall collect and analyze one set of drill cuttings samples per 500
linear feet drilled, with a maximum of three sets per day. Operators shall
collect a single discrete drill cuttings sample for each point of discharge to
the ocean. The weighted average of the results of all discharge points for
each sampling interval will be used to determine compliance. See Part 1,
Section D.123 of this permit.
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b) BMP Plan Requirements
The BMP Plan may reflect requirements within the pollution prevention requirements required by the M-iftef-ajs-Maaagemeat-Se-rv-iee-Bureau of
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Comment No.
9
Type/Category Produced Water
Permit Section Ref,
Part I.B.4.a
Current or Revised Permit Language /Clarifications/lssue
Safety and Environmental Enforcement (BSEE) (see 30 CFR 250.300) or other Federal or State requirements and incorporate any part of such plans into the BMP Plan by reference. "The addition of dispersants or emulsifiers downstream of treatment system to the overboard produced water discharge lines is prohibited.-4G CFR 110.4."
Rationale
The Joint Trades agree that the use of dispersants or emulsifiers downstream of the treatment system for the purpose of preventing detection of a sheen is prohibited.
In the 1989 API Paper (attached as Appendix A): Chemical Treatments and Usage in Offshore Oil and Gas Production Systems, by Fiudgins, the use of dispersants is discussed. Dispersants are added to scale control agents and corrosion inhibitors to increase performance.
As proposed, EPA would inadvertently be limiting the use of scale control agents, corrosion inhibitors, and emulsifiers from being used both upstream and in the produced water treatment system. The Joint Trades do not believe this was the intent and request the requirement be clarified to only prohibit the addition of dispersants or emulsifiers downstream of the produced water treatment system.
The following is copied from the 1989 API paper mentioned above, from the "Emulsion Breakers" section on page 20 of the report.
"Fiowever, the use of emulsifiers in the treatment system are necessary in the separation phase. Emulsion breakers work by attacking the droplet interface. They may cause the dispersed droplets to aggregate intact (flocculation) or to rupture and coalesce into larger droplets. Either way, the density difference between the oil and water then causes the two liquid phases to separate more rapidly. In addition, solids present will usually tend to accumulate at the liquid level interface (between the bulk oil and water phases) and form a semi-solid mass. If these solids are not dispersed into the oil phase or water wetted and removed with the water, the interface detector in the control system will ultimately malfunction, causing water to be dumped into the oil pipeline or oil to be carried over to the produced water system. Proper selection and application of emulsion breaker will minimize this accumulation and the resulting problems" (Hudgins, C. M., Jr. (1989). CHEMICAL TREATMENTS AND USAGE IN OFFSHORE OIL AND GAS PRODUCTION SYSTEMS. Houston, TX).
10 Produced Water Part - Oil and Grease I.B.4.b.2
"2) Oil and Grease. Samples for oil and grease monitoring shall be collected
and analyzed a minimum of once per month. In addition, a produced water
sample shall be collected, within
two hours of when a
sheen is observed in the vicinity of the discharge or within two hours after
startup of the system if it is shut down following a sheen discovery, and
analyzed for oil and grease. The sample type for all oil and grease
monitoring shall be either grab, or a composite which consists of the
arithmetic average of the results of grab samples collected at even intervals
during a period of 24-hours or less. If only one sample is taken for any one
month, it must meet both the daily maximum and monthly average limits.
Samples for oil and grease monitoring shall be collected prior to the
addition of any seawater to the produced water waste stream. The
analytical method is that specified at 40 CFR Part 136."
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades strongly disagree with taking a sample within 30 minutes of a sheen. The first response by operators is determining the cause or source of the sheen and deciding if the system needs to be shut down. By taking a sample within 30 minutes, operators will be more focused on taking a sample instead of stopping the sheen. The uncertainty of the origin of the sheen could cause operations to be in a state of higher risk of uncertainty and may lead to unduly endangering the health and safety of the facility personnel, the facility, and the environment. Also, the PW O&G kits are not always located in areas that are easily accessible. It might take an operator over 30 minutes to grab a kit, collect ice, complete paperwork, and take a sample. By not taking a sample within the 30-minute time frame, this will now put operators in possible violation of the permit. The Joint Trades request that time allowed to take a produced water sample after a sheen is observed remain at two hours.
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Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
11 Produced Water Part
-Toxicity
I.B.4.b.3
"Toxicity. A 7-day toxicity testing shall be performed twice once per
The results for both species shall be reported on the next quarterly DMR following testing. See Part 1, Section D.3 of this permit for WET testing requirements."
Rationale
Additionally, the Joint Trades request the language for sample tvpe remain as is in the current permit. Some operators elect to collect grab samples over a 24-hour period and determine the arithmetic average for compliance with the daily maximum limit.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request the current produced water toxicitv testing frequency and language remain the same. The majority of operators test for produced water on an annual frequency. Therefore, we strongly encourage EPA to maintain the annual produced water toxicity testing frequency as there is not enough justification for an increased frequency of toxicity testing. Per EPA's proposed permit fact sheet, EPA is removing the frequency reduction allowance for toxicity testing based on the Bureau of Safety and Environmental Enforcement (BSEE)'s suggestion. BSEE's basis of "difficulty of tracking" is completely invalid as once per calendar year is much easier to track than twice per calendar year and at least 90 days apart.
EPA acknowledges in their proposed permit's fact sheet that the number of available, experienced, and qualified laboratories for this 7-day produced water analysis is limited. We agree with this statement. Given the number of facilities requiring testing, the available laboratories cannot handle doubling the number of 7-day toxicity analyses that EPA/BSEE is proposing. This in turn could cause false toxicity or quality control issues. Laboratories only culture so many test age organisms. Increasing the number of required testing in short time frame is not possible. With the current annual required toxicity testing there are issues collecting and analyzing 100% of samples due to limited laboratory availability. There are only 3 laboratories that can perform testing on offshore oil and gas produced waters. Inability to predict extended platform downtime periods (i.e. intermittent production), logistics issues for these specific monitoring and testing requirements, and weather (i.e. hurricanes and other tropical storms) can also be problematic with an increase in testing. Doubling the number of required toxicity testing samples would not only increase the burden on the operator and the testing laboratories, but it will increase the operator's risk for additional missed samples resulting in administrative non-compliances. An annual testing frequency allows operators and laboratories to work together on scheduling around shut-in, weather, organism availability and laboratory testing schedules.
Currently, the permit requires that the toxicity sample has to be representative of produced water discharges. Annual toxicity tests are inclusive to all activity performed on the facility; therefore, it is a representative sample. Daily production rate changes and additions of flow back fluids are not only unpredictable and hard to track, but these changes in production are monitored monthly by conducting a representative sample for an oil and grease analysis on produced water. The language throughout the permit requires representative samples be collected. As an example, Section II.C.2 of the permit requires "Samples and measurements taken for the purpose of monitoring shall be representative of the monitored activity."
This proposed frequency increase will be a significant economic burden for offshore operators currently on an annual frequency as well. These additional toxicity tests would be an increase for routine produced water discharges in operating expenses with negligible value. Considering the very low number of toxicity test failures based on actual lab results, there is no environmental benefit to justify this increased expense.
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Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
The Joint Trades request an effective date for produced water toxicitv testing of January 1, 2018 and continue on a calendar year basis. This assumes the permit will become effective on October 1, 2017. Operators have 90 days to apply for coverage under the new permit, and then can plan a reasonable schedule for testing.
See also Comments No. 12-13 for additional discussion and information.
12 Produced Water Part
-Toxicity
I.B.4.b.3
"Toxicity testing for new discharges shall be conducted within 90 days 30 days after the discharge begins and then continue on the appropriate calendar year follow the-twiee-pef-ealeada-r-year- schedule."
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
EPA has not provided rationale for decreasing the time to conduct toxicity tests for new discharges. The Joint Trades request the 90-day time period be left unchanged for the following reasons:
New produced water discharges typically occur early in the life of the facility. The PW discharge rates are typically very low and ramp up over time at a rate dependent on the reservoir(s).
At these low produced water rates, the produced water treatment system needs time to be fully commissioned.
The critical dilution is set based on the highest monthly average discharge rate for the three months prior to the month in which the test sample is collected. Testing within the first 30 days would not allow for even one monthly average discharge rate in which to base critical dilution.
See Comments No. 11 and 13 for additional discussion and information.
13 Produced Water Part
-Toxicity
I.B.4.b.3
"Toxicity testing for existing discharges under the 2012 issued permit shall conduct the first toxicity test within 6 months from the effective date of obtaining coverage under the permit."
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request the permit change to provide claritv and a more realistic approach with what we believe is the intent of the proposed permit language.
"Samples taken in Year 2017 prior to the effective date of this permit can be reported for 2017."
Operators have 90 days from the effective date of the permit to apply and obtain coverage under the new permit. Requiring existing discharges to conduct the first test within 6 months from the effective date of the permit is problematic. 6 months from the effective date of the permit would mean that first test for all existing discharges must be tested by the end of March 2018. Again, this is problematic for operators that do not apply for coverage until the end of the 90 days. Thus, nearly all of the produced water toxicity tests would have to be completed in a short time frame.
As discussed in Comment No. 11, there are a limited number of qualified testing laboratories that test offshore produced waters. The testing laboratories could become overwhelmed with that amount of produced water testing to be done in a short time frame. All existing produced water discharges would have to be tested in approximately 3 months. From a transportation and logistics point of view, this would be very problematic and cause a financial burden to both the operator and the testing laboratories. Thus, potentially leading to false toxicity results and quality control issues. Laboratories only produce so many test age organisms, increasing the number of required testing in a short time frame is not possible.
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Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
Additionally, the Joint Trades request the additional language to clarify that samples taken in 2017 during the transition period can be reported for 2017, as compliance with the existing permit.
See Comments No. 11-12 for additional discussion and information.
14 Produced Water Part
-Toxicity
I.B.4.b.3
"Samples also shall be representative of produced water discharges when hydrate inhibitors, scale inhibitors, corrosion inhibitors, biocides, paraffin inhibitors, well completion fluids, workover fluids, well treatment fluids, and/or hydrate control fluids are used in operations. The-e-pefatof-must
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request striking the requirement to conduct a new toxicitv test if the sample used for the previous test did not represent an application of TCW or hydrate control fluids. At some locations, hydrate control fluids are routinely used as production treatment chemicals. The current permit already requires that samples are representative. EPA did not provide rationale as to why hydrate control fluids should be treated differently from other production chemicals.
This new requirement is overly burdensome with the following challenges: The TCW study is not complete. OOC requests that TCW discharges planned to be commingled with produced water be included in the TCW study scope. For facilities with third-party wells tied back to the production system, there is the added challenge of the host facility knowing exactly when these fluids were commingled with the produced water discharge to determine when a representative sample can be obtained. Although it may be communicated by a third-party in advance, there is the uncertainty of how long it will take these fluids to reach the facility and be treated before impacting the produced water discharge. Toxicity testing timing is coordinated well in advance with testing laboratories. This enables the testing lab to 1). coordinate and send toxicity test kits to the facility in alignment with existing transportation schedules and 2). have organisms prepped and available for the toxicity test. The addition of samples for TCW and hydrate control fluids, which may not be known in advance, is overly burdensome and may result in non compliance due to inability to obtain samples and start the toxicity testing within hold times. Discrete instances of TCW fluids commingled with produced water are short in duration and careful planning would need to be in place in order to obtain a representative sample with no guarantee that can be accomplished. The permit language is very broad and lacks clarity. Operational scenarios frequently change. As worded, it will be almost impossible for an operator to determine daily whether the previous test was representative of current conditions and an additional toxicity test would need to be conducted.
For additional discussion and information, see Comments 19-21.
15 Produced Water Part
-Toxicity
I.B.4.b.3
and Part
I.D.3.e
Part I.B.4.h.3
"If a test fails the survival or sub-lethal endpoint at the critical dilution in any test, the operator must perform monthly retest until it passes. The operator shall take corrective actions which may include conduction of Toxicity Reduction Evaluation (TRE), adjustment of discharge rate, addition
Page 7 of 30
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades agree with Part I.B.4.b.3, once a test fails, the operator should conduct monthly retests until passing. To be consistent, the Joint Trades also request EPA change the language in Part l.D.3.e as indicated. Historically, when a facility passes the first toxicity test, they pass the second and third toxicity test as well. Performing three consecutive monthly toxicity tests adds no value and becomes redundant.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00011
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
of diffusers, or other remedy actions after the failure of the first retest. Failing the toxicity test is considered violation of the permit."
Part I.D.3.e
"If the effluent fails the survival endpoint or the sub-lethal endpoint at the critical dilution, the permittee shall be considered in violation of the WET limit. Also, when the testing frequency stated above is less than monthly and the effluent fails either endpoint at the critical dilution, the monitoring frequency for the affected species will increase to monthly until such time as compliance with the NOEC effluent limitation is demonstrated, fef^-a pefio4-Qf-thre-e-eeftseeyt-ive-mo-nths-,-at that time the permittee may return to the testing frequency in use at the time of the failure. During the period the permittee is out of compliance, test results shall be reported on the DMR for that reporting period."
Rationale
16 Produced Water Part -V isual Sheen I.B.4.b.4
17 Produced Water Part
and Other -
I.B.4.b.4&
Visual Sheen
Part I.C.7
reporting to NRC
Sierra Club v. EPA 18cv3472 NDCA
mvest-igatfen-of-lf a sheen is observed in the course of required daily monitoring, or at any other time, the Operator must record the sheen and assess the cause of sheen. The operator must keep records of sheens and findings and make the records available for inspector's review."
The Joint Trades request that the language be modified as indicated to provide clarification.
Operators are required to keep adequate records to assure proper reporting of produced water sheens under the permit per Part II.C and II.D. A produced water sheen may be easily attributed to a change in operations (e.g., well management) thus making an inspection of the system unnecessary. The proposed permit language is vague and overly burdensome.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
Part I.B.b.4
meani-ng-of-5i-y-.-S.-.--l-3-24{a-H-2-)-a-n4-(b-H-3-)7-aicvd-ffi-u-s-t-b6-feported-to-t-he Nat4Qftai-R-espQfi-se-C&ntef-(-N-RC-)-pufsaafit-tQ-46-FR--148-6"
The Joint Trade stronglv disagree that discharges from permitted outfalls should be reported to the NRC. Thus, the Joint Trades request deletion of the text from Part I.B.b.4 and Part I.C.7. Additionally, the Joint Trades request deletion of the term "discharges" from the text at Part I.C.7. The statements at Part I.B.b.4 and Part I.C.7 are contrary to law.
Part I.C.7 "This permit does not preclude permittees from reporting discharges/releases to the National Response Center (NRC).-A-vfsual
3i-UvS-C----li-2-l(aH-2-)-aad-{b)f3);-aad-m-ast-be-repQfted-te-the-Nat4Qftai-
Based on Congressional intent and prior interpretations by the EPA and USCG, NPDES discharges are covered by section 402 of the Clean Water Act and are not subject to reporting as oil spills under section 311. Therefore, requiring an operator to report sheens from permitted discharge points to the NRC is contrary to law, and this requirement must be removed from the proposed permit.
The following citations from 33 U.S.C. (the Clean Water Act), historical EPA and USCG documents, and EPA's current website are provided to support this conclusion.
Page 8 of 30
1. 33 U.S.C. 1321 Excludes Certain Situations from the Definition o f "Discharge"
Parts I.B.b.4 and I.C.7 include new requirements for an operator to report sheens from permitted discharge points to the NRC. The proposed permit cites 33 U.S.C. 1321(a)(2) and (b)(3) as the basis for such reporting. However, 33 U.S.C. 1321(a)(2) and (b)(3), are the exact paragraphs that explain that NPDES discharges are excluded from the definition of "discharge" and do not have to be reported to the National Response Center. Paragraph 33 U.S.C. 1321(b)(3) states,
Tiers 8&9
ED 002061 00130976-00012
Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permt Language /Clarificatons/lssue
Page 9 of 30 Tiers 8&9
Rationale
"The discharge of oil or hazardous substances (i) into or upon the navigable waters of the United States, adjoining shorelines, or into or upon the waters of the contiguous zone, or (ii) in connection with activities under the Outer Continental Shelf Lands Act [43 U.S.C. 1331 et seq.j or the Deepwater Port Act of 1974 [33 U.S.C. 1501 et seq.j, or which may affect natural resources belonging to, appertaining to, or under the exclusive management authority of the United States (including resources under the Magnuson-Stevens Fishery Conservation and Management Act [16 U.S.C. 1801 et seq.j), in such quantities as may be harmful as determined by the President under paragraph (4) of this subsection, is prohibited, except (A) in the case of such discharges into the waters of the contiguous zone or which may affect natural resources belonging to, appertaining to, or under the exclusive management authority of the United States (inciuding resources under the Magnuson-Stevens Fishery Conservation and Management Act), where permitted under the Protocol of 1978 Relating to the International Convention for the Prevention of Pollution from Ships, 1973, and (B) where permitted in quantities and at times and locations or under such circumstances or conditions as the President may, by regulation, determine not to be harmful. Any regulations issued under this subsection shall be consistent with maritime safety and with marine and navigation laws and regulations and applicable water quality standards."
The key term in the paragraph is "discharge" - which is defined in 33 U.S.C. 1321 (a)(2), "discharge" includes, but is not limited to, any spilling, leaking, pumping, pouring, emitting, emptying or dumping, but excludes (A) discharges in compliance with a permit under section 1342 of this title, (B) discharges resulting from circumstances identified and reviewed and made a part of the public record with respect to a permit issued or modified under section 1342 of this title, and subject to a condition in such perm it,,[l] (C) continuous or anticipated intermittent discharges from a point source, identified in a permit or permit application under section 1342 of this title, which are caused by events occurring within the scope of relevant operating or treatment systems, and (D) discharges incidental to mechanical removal authorized by the President under subsection (c) of this section;
This definition excludes from the definition of "discharge" sheens that occur from permitted discharge points, as these are covered by the exclusions described in 1321(a)(2) (A), (B), or (C). Therefore, sheens from permitted discharges are excluded from the definition of "discharge" under 33 U.S.C. 1321.
2. EPA Clarified the Reporting Requirem ents in the 1981 Perm it Fact Sheet - Sheens from Permitted Point Sources are Exem pt from Reporting
This position is further supported by a 1981 Federal Register Notice (46 FR 20284, April 3, 1981) regarding the Issuance of Final General NPDES Permits for Oil and Gas Operations in Portions of the Gulf of Mexico; Fact Sheet, hereinafter referred to as "the 1981 Fact Sheet." Paragraph J, Oil Spill Requirements, of the 1981 Fact Sheet states,
"Section 311 of the Act prohibits the discharge of oil and hazardous materials in harmful quantities. In the 1978 amendments to section 311, Congress clarified the relationship between this section and discharges permitted under section 402 of the Act. It was the intent of Congress that routine discharges permitted under
ED 002061 00130976-00013
Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permt Language /Clarificatons/lssue
Page 10 of 30 Tiers 8&9
Rationale
section 402 be excludedfrom section 311. Discharges permitted under section 402 are not subject to section 311 if they are: 1. In compliance with a permit under section 402 of the Act; 2. Resulting from circumstances identified, reviewed and made part of the public record with respect to a permit issued or modified under section 402 of the Act, and subject to a condition in such permit; or 3. Continuous or anticipated intermittent discharges from a point source, identified in a permit or permit application under section 403 of this Act, which are caused by events occurring within the scope of the relevant operating and treatment systems.
To help clarify the relationship between discharges under section 402 and section 311 discharges, EPA has compiled the following list of discharges which it considers to be regulated under section 311 rather than under a section 402 permit. The list is not to be considered all-inclusive.
1. Discharges from a platform or structure on which oil or water treatment eguipment is not mounted,
2. Discharges from burst or ruptured pipelines, manifolds, pressure valves or atmospheric tanks,
3. Discharges from uncontrolled wells, 4. Discharges from pumps or engines, 5. Discharges from oil gauging or measuring eguipment, 6. Discharges from pipeline scraper, launching, and receiving eguipment, 7. Spill of diesel fuel during transfer operations, 8. Discharge from faulty drip pans, 9. Discharges from well heads and associated valves, 10. Discharges from gas-liguid separators, and 11. Discharged from flare lines."
It is clear from the 1981 Fact Sheet discussion that EPA clarified, based on Congressional intent, that point sources covered by an NPDES permit are not subject to section 311 of the Clean Water Act; meaning such discharges are not reportable to the NRC.
3. USCG District 8 (1998) Issued a M emorandum Explaining Sheens from Perm itted Discharges are not Subject to NRC Reporting
Furthermore, in September 1997 members of the Offshore Operators Committee met with U.S. Coast Guard District 8 staff to clarify proper reporting procedures for sheens from permitted point sources (section 402 events) versus oil spills (section 311 events). The Commander of the Eighth Coast Guard District issued a memorandum (dated April 3,1998) that states,
"...It was agreed by all in attendance that Section 311 of the Clean Water Act does not define oil discharges from NPDES-permitted sources (whether the system is operating correctly or not) as reportable oil discharges. This conclusion is supported by Commandant Decisions on Appeal. The attendees agreed that the proper policy is for sources to report discharges in violation of their NPDESpermitted processes to the Environmental Protection Agency and Minerals Management Service (if appropriate) and not to the Coast Guard. Discharges of oil resulting from other activities not part of a NPDES process will still be reported to the Coast Guard National Response Center."
ED 002061 00130976-00014
Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permit Language /Clarifications/lssue
Page 11 of 30 Tiers 8&9
Rationale
This USCG memorandum, has not been rescinded and is still in effect. This District 8 policy is clearly in alignment with 33 USC 1321 and the 1981 Fact Sheet.
4. EPA Response to Comments fo r the 2007 GM G290000 Renewal
EPA Region 6 addressed the issue of reporting sheens to the USCG National Response Center directly in the Response to Comments when the agency issued the Final NPDES General Permit for Discharges from New and Existing Sources in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000). The following text is taken directly from the Response to Comments:
"Comment Number 1: The Offshore Operators Committee (OOC) requested clarification of the
permit's oil spill requirements to state that sheens resulting from permitted discharges are not defined as spills. Response:
EPA has previously worked with the U.S. Coast Guard to determine when a sheen would be considered a spill. Sheens from non-permitted discharges were determined to be spills which are under the jurisdiction of the U.S. Coast Guard. Sheens which result from permitted discharges were determined to be under EPA jurisdiction and are not considered to be spills. The requested clarification is consistent with that determination and has been made in the final permit."
It is apparent that EPA has reviewed this reporting issue in previous iterations of the GMG290000 permit and made the determination that sheens from permitted discharges are not oil spills. The permit and agency processes ensure sheens from permitted discharge points are reported through the Discharge Monitoring Reports.
5. EPA's Current Website Describes the Types o f Discharges Exem pt from 33 U.S.C. 1321
Finally, EPA's current website (https://www.epa.gov/oil-spills-prevention-and-preparednessregulations/oil-spills-do-not-need-be-reported) contains information on "Oil Spills that Do Not Need to be Reported" which includes a section on "NPDES-Permitted Releases" that provides yet another summary of the definition of discharge in 33 U.S.C. 1321 (a)(2):
"Three types of discharges subject to the National Pollutant Discharge Elimination System (NPDES) are exempt from oil spill reporting:
1. Discharges in compliance with a permit under section 402 of the Clean Water Act, when the permit contains: Either an effluent limitation specifically applicable to oil, or An effluent limitation applicable to another parameter that has been designated as an indicator of oil;
2. Discharges resuiting from circumstances identified and reviewed and made part of the public record with respect to a permit issued or modified under section 402 of the Clean Water Act, and subject to a condition in such permit. This exclusion addresses situation where the source, nature, and amount of a potential oil discharge was identified, and a treatment system capable of preventing that discharge was made a permit requirement.
ED 002061 00130976-00015
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
For example, if a discharger has a drainage system that will route spilled oil from a broken hose connection to a holding tank for subseguent treatment and discharge, the treatment system must be sufficient to handle the maximum potential spill from that source. Spills larger than those contemplated in the public record are not exempted; and
3. Continuous or anticipated intermittent discharges from a point source, identified in a permit or permit application under section 402 of the Clean Water Act, which are caused by events occurring within the scope of relevant operating or treatment systems. This exclusion applies to chronic or anticipated intermittent discharges originating in the manufacturing or treatment systems of a facility or vessel, including those caused by periodic system failures. Discharges caused by spills or episodic events that release oil to the manufacturing or treatment systems are not exempt from reporting."
The information above provides additional clarity on the intent of 33 U.S.C. 1321 (a)(2). Clearly, point source discharges in compliance with permit requirements are exempt from section 311 reporting. Also, limitations described for various point source discharges included in the GOM NPDES permit are part of the public record, including the fact that sheens may occur from these discharges. Lastly, Item 3 from the website description above makes it clear that episodic events caused by "periodic system failures," for example a sheen from deck drainage or the produced water treatment process, are also exempt from section 311 reporting.
6. Conclusion
Based on Congressional intent and prior interpretations by the EPA and USCG, it is clear that NPDES discharges are covered by section 402 of the Clean Water Act, and are not subject to reporting under section 311. Therefore, the requirement to report sheens from permitted discharge points to the NRC must be removed from the proposed permit. Reporting of sheens from permitted discharge points is managed through the Discharge Monitoring Reports, and such events will be reported to EPA as permit excursions/violations. However, sheens from permitted discharge points need not be reported to the NRC.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
18 Weil Treatment Part I.B.6.a
Fluids,
"Vendor eefttfleat-ion declaration or statement indicating t-hs-f-laids-eefstam The Joint Trades request rewording the first sentence to clarifv that the vendor declaration is
Completion Fluids, Workover
no the vendor does not add or has not intentionally added priority
that no priority pollutants are intentionally added to the materials added downhole as well
pollutants to the fluids is acceptable for meeting this requirement. In case treatment, completion, or workover fluid TCW. If priority pollutants were not intentionally
Fluids - Priority
erth&F-a-v&nd&F-ceftifeatlen-is-n&t-availabte-Qf-tfoe-pFesent-Qf-pffority
added to the formulation of the product, then they are considered to be in there only in trace
Pollutants
quantities.
E-of-tbe-per-m-it-r"
Further, the Joint Trades request the deletion of the last sentence.
The proposed EPA Region 6 language contradicts the 1993 ELG decision to regulate priority pollutants with oil and grease only. The documentation and the effluent limitation guidelines development document (in tables X-12, X-13, X14) clearly document that the EPA recognized trace amounts of priority pollutants in these fluids above the detection methods. Imposing MDL limits on all 138 priority pollutants will result in significant non-water quality impacts associated with transportation, discharge, disposal, and excess treatment. The method detection limits
Page 12 of 30
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00016
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
referenced in Appendix E are achievable for samples in clean water effluents but due to matrix effects may not be applicable to the analyses of products or TCW discharges.
A certification program would be burdensome and unsuitable for 138 priority pollutants and all products used in completion fluids systems. There is no apparent environmental benefit over the current system of regulatory control for the significant costs that this would entail. Consequently, an unintended certification program would result in non-water quality impacts which will result in additional treatment and discharges.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
19 Well Treatment Part I.B.6.b "When well treatment, completion or workover fluids are commingled and
Fluids,
discharged with produced water, the discharges are considered produced The Joint Trades request deleting the 7-dav toxicitv test requirement. As outlined in the
Completion
rationale in Comment No. 14 for Part I.B.4.b.3, this requirement is overly burdensome. Toxicity
Fluids, Workover
testing for these discharges should be included in the scope of the TCW study.
Fluids - Fluids
momtQf4ng-and-fepoftmg-pwposes."
Commingled
The draft permit language is more onerous on operators and the additional burden to the O&G
with Produced
Industry does not have any apparent additional protection to the environment.
Water
20 Well Treatment Part I.B.6.C Operators must conduct well treatment fluids, well completion fluids, and The Joint Trades request that anv requirements for disclosure of treatment, completion and
Fluids,
workover fluids
workover fluid compositional information be clarified as to the extent of disclosure required.
Completion
assessments whenever they apply those fluids. Such assessments shall be Proposed revision reflects a requirement for disclosure of composition as described on the SDS
Fluids, Workover
conducted for each
for relevant additives.
Fluids -
applicable well by operators either corporately or individually. The general
Characteristic
information of a
Additionally, the Joint Trades request that the disclosure requirement allow for the use of a
Assessments
specific well treatment, well completion or workover fluid could be used for systems-style disclosure of the chemical composition of all additives in a fluid (or fluids, in the
assessment purposes.
case of multiple disclosed applications) consistent with the approach that has been adopted for
Each fluid assessment shall include the following information:
use in some jurisdictions and by FracFocus. System-style disclosure would satisfy the objectives
of the permit revision while potentially reducing the necessity for companies to make
1) Lease and block number
confidential business information claims on such disclosures. The process known as system-style
2) API well number
disclosure lists all known chemical constituents in a fluid (or fluids, in the case of multiple
3) Type of well treatment or workover operation conducted
disclosed applications), but decouples those constituents from their parent additives, thus
4) Date of discharge
improving protection of the proprietary chemistry used in the applications while promoting
5) Time discharge of TCW fluids commenced
greater disclosure. At the same time, in order to protect the substantial investment of time and
6) Duration of discharge of TCW fluids
resources in developing proprietary products, it is critical that operators and service companies
7) Volume of well treatment
have the ability to protect proprietary information as Confidential Business Information even
8) Volume of completion or workover fluids used
when using a systems-style approach.
9) The identity, as listed on the applicable SDS, and nominal
concentration of each chemical constituent intentionally added to the well Also, the Joint Trades request that service providers be permitted to disclose the trade
treatment, completion, or workover fluid used. The-c-ommon-rvaffl-e-s-arvd secret/CBI information directly to EPA rather than requiring disclosure through the operators.
ehem-icak-pafamet&Ffr-fef-alj-additives-tQ-the-flufds
Such independent disclosure is necessary in order to protect the substantial investment of time
40)----- The-vofaffle-eTeac-h-aelcIftiv-e-
and resources that service providers make in developing proprietary products. Chemical
additives play a critical role in the safety, efficiency and productivity of offshore wells, and access
42)----- Co-ne&ntfat4&Fr-CFf-affaddft4v&&4n-the-eQmpf&t4Qnr-&F-wcFrk&ef-ffu4gl to newly-developed, ever-improving chemicals--be they "greener," more efficient or more
10) The No Observable Effect Concentration (NOEC) of 48-hour acute
effective--is in turn critical to continued improvements in offshore operations.
Whole Effluent Toxicity (WET)
Without these changes, this proposed requirement creates challenges for companies that may
manufacture products which contain proprietary components or trade secrets. Companies with
trade secrets could experience significant negative economic impacts if a proprietary additive
was "reverse engineered" based on information submitted to EPA as part of this requirement.
Page 13 of 30
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00017
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Operators shall use the following methods to perform the 48-hour Acute Whole Effluent Toxicity Test Method:
a) The permittee shall utilize the Mysidopsis bahia (Mysid shrimp) acute static renewal 48-hour definitive toxicity test using EPA-821-R-02-012. A minimum of five (5) replicates with eight (8) organisms per replicate must be used in the control and in each effluent dilution of this test. b) The permittee shall utilize the Menidia beryllina (Inland Silverside minnow) acute static renewal 48-hour definitive toxicity test using EPA-821-R-02012. A minimum of five (5) replicates with eight (8) organisms per replicate must be used in the control and in each effluent dilution of this test.
c) The NOEC is defined as the greatest effluent dilution which does not result in lethality that is statistically different from the control (0% effluent) at the 95% confidence level.
Information collected for this reporting requirement shall be submitted as an attachment to the DMR or in an alternative format requested by the operator and approved by EPA Region 6. Operators may submit this information marked as "Confidential Business Information" or other suitable form of notice or may have service providers independently submit this information marked as such, if necessary. The information so marked shall be treated as information subject to a business confidentiality claim pursuant to 40 CFR Part 2.
Rationale
The Occupational Safety and Health Administration (OSHA) has addressed similar challenges in its Hazard Communication requirements. Specifically, OSHA has provided criteria that allow manufacturers to deem a chemical component as a "trade secret" on a Safety Data Sheet (SDS) (see 29 CFR 1910.1200(i)). Under the OSHA Hazard Communication requirements, a proprietary chemical component that has been designated as a trade secret is listed on the SDS in a generic manner, such "Proprietary Component A."
Given the above, the Joint Trades are requesting that EPA Region 6 incorporate the OSHA Hazard Communication trade secret criteria by reference in the proposed GMG290000 permit.
Under this proposed change, EPA Region 6 would still have access to information that priority pollutants are present or not in a particular additive, and the proprietary nature of certain additives would be protected. This added language would also bring the two regulatory programs into alignment, making compliance straightforward and consistent. If a specific identity of a chemical compound can be withheld on an SDS while still communicating sufficient information to ensure the safe handling, use and disposal of the chemical compound, then it is reasonable to allow it to be withheld from the reporting of fluid discharges wherein the chemical compound is greatly diluted.
This approach aligns with the disclosure of hydraulic fracturing chemicals used in the onshore oil and gas industry. The FracFocus Chemical Disclosure Registry (www.fracfocus.org) allows chemicals in the registry to be designated as proprietary if the chemical has been determined to meet the OSHA trade secret criteria.
The Joint Trades request that TCW toxicitv testing be conducted on the total TCW job constituents prepared either by the company performing the job or the toxicity testing laboratory that is representative of all fluids used in the job in lieu of sampling the discharge. There are several challenges with collecting a representative sample during discharges.
1. In order to obtain an optimum dilution series, a range finder will likely be needed. Without a rangefinder, the NOEC may not be representative of actual NOEC. Due to the logistics of catching a sample, transporting to testing laboratories, conducting a rangefinder, and then setting up a testing with the optimum dilution series, the sample hold times will likely by exceeded. Due to the short duration of these types of discharges, pulling another sample may not be possible.
2. In the event that the sample is compromised in anyway during transportation or toxicity tests are inconclusive or invalid, having the opportunity of collecting another sample may not be possible. This is because these discharges are short in duration.
3. TCW jobs are performed in stages. The composition of the discharge varies throughout the TCW job.
The Joint Trades believe that testing the toxicitv of the total TCW job constituents would provide EPA with the data needed to assess the toxicity of TCW fluids without the burden of sampling the actual discharge.
The Joint Trades are also proposing to add clarifying language regarding when and how this information should be reported to EPA Region 6 and clarifying language on Fluid Assessment Information (below).
Sierra Club v. EPA 18cv3472 NDCA
Page 14 of 30
Tiers 8&9
ED 002061 00130976-00018
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale Fluid assessment Information, clarification:
3) Type of well treatment or workover operation conducted. The Joint Trades would like clarification on what information and examples regarding the type of well treatment or workover operations conducted EPA is requesting. 7 & 8) Clarify if this is the volumes of fluids discharged (not pumped downhole).
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
21 Well Treatment Part I.B.6.C "Industry-Wide Study Alternative: Alternatively, operators who discharge
Fluids,
well treatment completion and/or workover fluids may participate in an
1. The Joint Trades are requesting that "active" be struck. It is unclear what is intended bv
Completion
EPA-approved industry-wide study as an alternative to conducting
"active", and could, for instance, unintentionally exclude well jobs associated with initial
Fluids, Workover
monitoring of the fluids characteristic and reporting information on the
completion and with abandonment. It is enough to simply reference well jobs where
Fluids - Fluids
associated operations. That study would, at a minimum, provide a
TCW fluids will be discharged.
Commingled
characterization of well treatment, completion, and workover fluids used in
with Produced
a representative number of active-wells discharging well treatment,
2. The Joint Trades request striking "of varving depths (shallow, medium depth and deep
Water
completion, and/or workover fluids ef-vafyiftg-dep-ths-(-sha-llew7-friedium
depths)" and replacing simply with "discharging well treatment, completion, and/or
Well Treatment
depth-and-deep-depths). In addition, an approved industry-wide study
workover fluids".
Fluids,
would be expected to provide greater detail on the characteristics of the
Completion
resulting discharges, including their nominal chemical composition and the
Due to the current level of activity, all wells would probably have to be sampled as the
Fluids, Workover
variability of the nominal chemical composition and toxicity. The study area
jobs arise to ensure compliance with the study window. In other words, the study
Fluids - Industry
should include a statfstical-vatid representative number of samples of wells
participants would not have the luxury per se of picking and choosing well TCW jobs to
-W id e Study
located in the Western and Central Areas of the GOM and may include the
sample. * Therefore, specifying varying depths overly constrains the study from the
Alternative
Eastern Gulf of Mexico (GOM) under the permitting jurisdiction of EPA
start. Additionally, it is unclear what EPA means by this term (is it water depth, well
Region 4, and operators may join the study after the start of and
depth to reservoir, discharge depth?)
completion of the studydate. The study plan should also include interim
dates/milestones.
* This is the same approach EPA Region VI approved for the recent WBM dissolved
metals study i.e. sampling the WBM as each drilling job came along.
A plan for an industry-wide study pfarr would be required to be submitted
to EPA for approval within six-ment-fos 2 years after the effective date of this
permit. Once a permittee has committed financially to participate in the
3. The Joint Trades are requesting changes to the permit language to clarify that a financial
study it shall constitute compliance with the monitoring and reporting
commitment to participate in the Industry-Wide Study Alternative satisfies the chronic
requirements of Part I.B.6.C. If the Region does not approve the study plan or a permittee does not sign up to participate in the study, compliance with
and acute monitoring requirements and the Well Treatment, Completion, and Workover Reporting Requirements of the permit, and ensure consistency with prior approved
all the monitoring and reporting requirements for well treatment,
industry studies. Further, the change allows the option for new permittees to benefit
completion and workover fluids is required. If the Region approves an
from the industry-wide study after initiation and completion of the study.
with-these-m-&nitQfi-ng-re|ti4fem&nts-fQf-pefmftte&&-wh&-paft44pate-fn-&ueh the-i-R4u-&tfy-wfde-s-tudy-.- Once approved, the study plan will become an enforceable part of this permit. The study must commence within six months of EPA's approval. The final study report date is to be determined. The portion which is achievable by March 30, 2022 must be identified in the plan. must-be-submitted-no-4atef-than-MaF&h-i0>-2023.
Page 15 of 30
4. As stated above the Joint Trades request that TCW toxicitv testing be conducted on the total TCW job constituents prepared either by the company performing the job or the toxicity testing laboratory that is representative of all fluids used in the job in lieu of sampling the discharge. The Joint Trades believe that testing the toxicity of the total TCW job constituents would provide EPA with the data needed to assess the toxicity of TCW fluids without the burden of sampling the actual discharge.
5. Change the planning time from 6 months to 2 years. The goals and objectives of the proposed TCW characterization are not transparent. To be technically sound, effort should be first focused on a problem formulation phase where diverse set of subject matter experts (SMEs) for various affected organization (e.g., suppliers, operators, Region 6, Region 4, testing laboratories, etc.) come together to clarify the intent, the goals and the objectives of such a study. This should be followed by a data gap analysis
Sierra Club v. EPA 18cv3472 NDCA
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ED 002061 00130976-00019
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
and information gathering phase. The working group could then reconvene and consider the findings, identify and resolve how to address the difficult aspects of the study and agree upon how to address the "simpler aspects of the study". After taking time to consider how to tackle the difficult tasks another meeting could then be convened to reach general agreement on a path forward with the difficult aspects. Though three meetings have been identified, quite possibly more will be needed. Once the problem formulation phase is completed then 6 months for plan development seems reasonable.
Depending on what comes out of the problem formulation phase, a hard date of March 30, 2022 may not be realistically achievable for completion and reporting. The portion of the study that is decided by the SMEs, during the problem formulation phase, as reasonable to achieve by March 30, 2022 should be all that is due and can be written into the plan.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
22 Sanitary Waste Part I.B.7.a "Solids. No floating solids may be discharged to the receiving waters.
(Facilities
Observation must be made daily during daylight in the vicinity of sanitary The Joint Trades are requesting this change to provide clarification with the requirement and for
Continuously
waste outfalls. If floating solids are observed at other times in addition to consistency with the requirements outlined in Appendix F, Table 1 of the permit.
Manned for 30
the daily monitoring, it must be recorded. Qksefva&on-ofTiea&frg-sel+ds
or more
consecutive
The number of days solids are observed must be reported."
days by 10 or
More Persons) -
Prohibitions
23 Sanitary Waste Part I.B.7.b "Residual Chlorine. Total residual chlorine (TRC) is a surrogate parameter
(Facilities
for fecal coliform. Discharge of TRC must meet a minimum of 1 mg/l a4
The Joint Trades request that the exception for the MSD be added back to the permit. The
Continuously
removal of the MSD exception creates an additional burden on the regulated community. The
Manned for 30
sample must be taken once per month and the concentration recorded. The regulated community should be able to demonstrate proper operation and maintenance as
or more
approved methods are either Hach CN-66-DPD or EPA method specified in required by the permit.
consecutive
40CFR part 136 for TRC."
days by 10 or
The language for TRC limitation "and shall be maintained as close to this concentration as
More Persons) -
"[Exception] Any facility operator which properly operates and maintains a possible" is vague, and the Joint Trades request that it be struck.
Limitations
marine sanitation device (MSD) that complies with pollution control
standards and regulations under section 312 of the Act shall be deemed in For MODUs, The US Coast Guard conducts annual inspections of MSDs in order to issue the
compliance with permit prohibitions and limitations for sanitary waste. The MODU a Certificate of Compliance. During this inspection, the Coast Guard confirms that the
MSD shall be tested yearly for proper operation and the test results
MSD is properly operational and fully functional. Additionally, an overwhelming majority of
maintained for three years at the facility or at an alternate site if not
MODUs are internationally flagged. As such, their Class Society on behalf of Flag State conducts
practicable."
MSD inspections as a requirement for the International Sewage Pollution Prevention Certificate
(ISPPC) pursuant to MAR POL, Annex IV [Regulations for the prevention of pollution by sewage
from ships].
The Joint Trades requests that industry be able to demonstrate proper operation and maintenance via maintenance logs/records and any other records of annual inspections by Coast Guard. The monthly TRC requirement increases administrative and financial burden to operators by requiring purchasing additional test kits, training personnel in the use of test kits, and added recordkeeping burden.
Page 16 of 30
Additionally, some MODUs have MSDs that do not utilize chlorine as a disinfectant, for example some use bromine biological treatment systems due to reduced usage of chlorine based
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00020
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
treatment systems in other parts of the world. The Joint Trades request a similar approach to demonstration of meeting the requirement via US Coast Guard approval, annual inspections, Class/Flag State inspections and/or the ISPPC and maintenance logs/records.
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
24 Sanitary Waste Part LES.8.a "Solids. No floating solids may be discharged to the receiving waters.
(Facilities
Observation must be made daily during daylight in the vicinity of sanitary The Joint Trades are requesting this change to provide clarification with the requirement and for
Continuously
waste outfalls. If floating solids are observed at other times in addition to consistency with the requirements outlined in Appendix F, Table 1 of the permit.
Manned for
the daily monitoring, it must be recorded. Observation of floating solids
thirty or more
mrj-s-t-be-fec-orded-w-hefiev-ef-floating-SQjfds-efe-ob-sefved-dijfiftg-the-da-yv
Additionally, the Joint Trades request that the exception for the MSD be added back to the
consecutive
The number of days solids are observed must be reported."
permit. The removal of the MSD exception creates an additional burden on the regulated
days by 9 or
community. The regulated community should be able to demonstrate proper operation and
Fewer Persons
"[Exception] Any facility operator which properly operates and maintains a maintenance as required by the permit.
or Intermittently
marine sanitation device (MSD) that complies with pollution control
by Any Number)
standards and regulations under section 312 of the Act shall be deemed in The draft permit language is more onerous on operators and the additional burden to the O&G
compliance with permit prohibitions and limitations for sanitary waste. The Industry does not have any apparent additional protection to the environment.
MSD shall be tested yearly for proper operation and the test results
maintained for three years at the facility or at an alternate site if not
practicable."
25 Domestic Waste Part I.B.9.b "Solids. No floating solids may be discharged to the receiving waters.
- Monitoring
Observation must be made daily during daylight in the vicinity of domestic The Joint Trades are requesting this change to provide clarification with the requirement and for
Requirements
waste outfalls. If floating solids are observed at other times in addition to consistency with the requirements outlined in Appendix F, Table 1 of the permit.
the daily monitoring, it must be recorded. Observa^oR-of-fleating-solids
The number of days solids are observed must be reported."
26 Miscellaneous Part I.B.lO.i (i) Filtered and Slurry: Desalinization Unit Discharge, Diatomaceous Earth
Discharges -
Filter Media, Mud, Cuttings, and Cement (including cement tracer) at the The Joint Trades request that discharges of cement used for testing be authorized bv striking this
Discharge List
Seafloor, and Excess Cement Slurry [ No-tec-PIseharges-of-eement-sfafry-rj-sed "Note" and adding clarifying language under Miscellaneous Discharges: "Unused Cement Slurry".
Rationale included in Comment No. 30 for Part I.B.lO.a.
27 Miscellaneous Part
Discharges -
I.B.lO.iv
Discharge List
"(iv) Subsea Discharges:-BteweuTPfev6atef-Contfel-Fkjfd, Subsea Wellhead Preservation Fluid, Subsea Production Control Fluid, Umbilical Steel Tube Storage Fluid, Leak Tracer Fluid, Riser Tensioner Fluid, and Pipeline Brine (used as piping or equipment preservation fluids)."
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request that Blowout Preventer Control Fluid discharges not be confined to only the "subsea discharges" re-categorized portion of miscellaneous discharges. OOC requests that Blowout Preventer be categorized as stand alone. This request also provides clarity.
"QBIowout Preventer Control Fluid
Blowout Preventer Control Fluid is discharged subsea, but can also be discharged at the surface
(such as when required function tests are being conducted).
28 Miscellaneous Part I.B.10 - "Net&"2v-Gpefatofs-ffitrst-ttush-3d-eaptwe-tfoe-eh&mteals-(e-gvr foy4rate
Discharges -
Notes
w c 9 u 9 < c l *4 < ^
9
y v*. ? < t*.
9 y y y c * , ^ w < q c *,4 < t* .
yq y
y c * , y 9 y 9 1* * ^ c u 9 y y y ^ y 9 y in . % .y y ^ q j j c u 9 y 1 v . 9
The Joint Trades request that the proposed language in Part 1.B.10 "Note 2: Operators must
Discharge List
flush and capture the chemicals (e.g., hydrate control fluids or pipeline brine) contained in
pipelines, umbilical, or jumpers before or at the time of abandonment" be deleted from the text.
EPA has reviewed toxicity data and information regarding hydrate inhibitor use submitted by
OOC in the past and determined that the hydrate control fluid permit limitations in place in the
current permit are appropriate for these types of operations.
Page 17 of 30
In Part l.A .l under Operations Covered discharges relating to abandonment and decommissioning operations are covered. "This permit establishes effluent limitations, prohibitions, reporting
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00021
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
29 Miscellaneous Discharges Discharge List
Sierra Club v. EPA 18cv3472 NDCA
Part I.B.10 - "(vii) Non-specified Discharges: Any discharge that is not specified in this
Notes
permit is not authorize."
Page 18 of 30
Tiers 8&9
Rationale
requirements, and other conditions on discharges from oil and gas facilities, and supporting pipeline facilities, engaged in production, field exploration, developmental drilling, facility installation, well completion, well treatment, well workover, and abandonment/decommissionina operations." Discharges of hydrate control fluids (ethylene glycol and methanol) or chemically treated seawater occur during pipeline, umbilical, and jumper decommissioning and installation processes and are covered under the NPDES permit as miscellaneous discharges of hydrate control fluids or chemically treated seawater miscellaneous discharges. Such discharges must comply with the applicable permit limits. After a pipeline or umbilical has been abandoned in place, any leak or spill of hydrate control fluid from that pipeline or umbilical would not be covered under the NPDES permit as stated under Part II Section B.7 "This general permit does not authorize discharges, including spills or leaks, caused by failures of equipment, blowout, damage offacility, or any form of unexpected discharge."
The Joint Trades do not feel anv changes to the current permit are necessarv to address discharges of hydrate control fluids or chemically treated miscellaneous discharges that occur during pipeline, umbilical, and jumper decommissioning and installation processes. The permit GMG290000 recognizes and authorizes the discharge of hydrate inhibitors in these types of operations as a "Miscellaneous Discharge - Hydrate Control Fluid" (part I.B.10). The permit limit for these discharges is "no free oil" and monitoring required is sheen observations. This provision was added to the permit in the 2004 renewal (69 FR No. 194, p. 60150). Any discharges of methanol greater than 20 bbls or of ethylene glycol greater than 200 bbls within a 7 day period would have to meet the current additional toxicity testing requirements. On April 8, 2011, the OOC Environmental Sub-Committee provided to EPA summary information regarding hydrate inhibitor use in GOM during oil and gas operations at EPA's request. It addressed the discharge of hydrate inhibitors (methanol, glycol, LDHI, and brine) when disconnecting subsea equipment.
On May 7, 2012, the OOC submitted comments on the proposed general permit GMG290000. Attachment A of the comments providing supporting information on the regulation of hydrate inhibitor discharges and included toxicity information on methanol and ethylene glycol. On page 18 of EPA's Response to Comments dated September, 28, 2012, regarding the draft reissued NPDES permit publicly noticed in the Federal Register on March 7, 2012, EPA in responding to the OOC's comments in (e), EPA states: Commenter requested that the permit allow discharges of methanol and ethylene glycol less than 200 bbl/d and waive toxicity test requirements for hydrate control fluids. Response: The models were re-run and the concentrations calculated and compared to the NOEC's for growth and mortality listed for methanol and ethylene glycol in the submitted comment addenda. The modeling runs submitted to justify the 200 bbl/d value, model an exceedance of the NOEC In case 21 of the submitted modeling package for methanol. Further, the actual density of methanol cannot be input to CORMIX. In addition, the subsequent concentrations and possible synergistic effects posed by discharges of produced water and hydrate inhibitors are not substantiated by the comment. Therefore, based on the Agency's review of the modeling submitted and a suitable margin of safety, the Agency will waive toxicity test requirements for neat methanol less than 20 bbl/d and neat ethylene glycol less than 200 bbl/d. All other hydrate control fluids will meet the requirement of the permit as stated.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request the additional language be added to the permit.
ED 002061 00130976-00022
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Add to this section:
"Small quantity discharges not addressed elsewhere in this permit, may be discharged after a notification to EPA that includes the following:
Proposed date(s) of activity Description of activity (e.g., connection of flowline to structure) Expected materials and quantities to be discharged Description of potential impacts on the environment"
Rationale
There are activities that might result in a small quantity discharge to enter the water. Many times, the quantities are hard to estimate and are very small, but however there doesn't appear to be method for these to be reported or addressed under the permit.
Potential activities included but are not limited to: Application of materials subsea that might migrate into the receiving waters (e.g., connector fluid/gel to ensure proper connections to minimize possible discharge of operational or production fluids). Non-oil materials that migrate from a line when being connected to another part of the structure. An example is connecting a (preserved) flowline to a tree. The removal of a cap may result in the inadvertent mixing of contents of the wet-parked line with the ambient water of the receiving water.
Not accepting the proposed permit language is onerous on operators and an additional burden
to the O&G Industry with no apparent additional protection to the environment.
30 Miscellaneous Part I.B.lO.a
Discharges -
1. The Joint Trades support the addition of unused cement slurrv as a new discharge under
Unused Cement
cement slurry discharge is limited to once per cementing job .ealendaf-year
Miscellaneous Discharges: "Unused Cement Slurrv". The Joint Trades propose that the
definition below be added to Part II.G. The addition of these discharges is critical to
mitigating well control issues if the cement system cannot be returned to service quickly.
etth&r-eas&;- The operator shall report date, identification of well or facility,
volume of cement, and cause of the discharge in their NetDMR."
"Unused cement slurry- cement slurry used for testing of equipment or resulting from cement
specification changes or equipment failure during the cementing job."
Summarizing the details of OOCs recent submittals to EPA Region VI related to this issue are as follows:
a) Equipment testing is critical to proper operation and maintenance of drilling systems. Without adequate testing, well control concerns (among others) can arise. Equipment that is not properly tested has the potential for a catastrophic environmental event. EPA must consider equipment testing/commissioning as "proper operation and maintenance" since if permittees do not test/commission equipment then a permittee cannot truly say that they are complying with this permit requirement,
b) The discharge of such fluids would meet all monitoring and limitations of the permit for those fluid types, and since such fluids had not been used" they would have a lower pollutant potential than the used fluids (which are authorized for discharge),
c) Prior EPA determinations have been received which authorized such discharges (and the draft fact sheet does not now provide a substantive justification for now prohibiting such discharges), and
Page 19 of 30
d) Authorizing discharge will avoid substantive safety risks for managing bulk fluids back to shore including lifting large, heavy containers at sea; transportation risks at sea and onland and; tank/container cleaning associated with solidified cement (It is difficult to inhibit cement from setting up. Therefore, transport to shore is expected to be solidified blocks in their containers). This also consumes limited onshore disposal facility capacity for essentially benign materials. Finally, the transport of these materials will involve environmental consequences including increased air emissions from marine and road transport.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00023
Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permit Language /Clarifications/lssue
Page 20 of 30 Tiers 8&9
Rationale
The Joint Trades present here additional information on the discharge quantities to support approval of these discharges. The following are typical volumes of cement for the subject issue:
1. New drilling units (MODU or platform rig) commissioning/equipment testing: 100-200 bbls per ship. This is slurry used to test pumping functions and verify flow paths. Assuming 3-7 newly constructed drilling units per year enter the Gulf (1), this is equivalent to 600-1400 bbl/yr of slurry that may be discharged annually.
2. Other Discharges of Unused Cement Slurry o Repairs: when a cement system malfunctions or equipment must be upgraded or changed out for specific job, the existing cement must be removed, repairs made and testing conducted to ensure proper operation. There are two concerns in this case with a prohibition against the discharge:
o If the malfunction occurs during a cementing job, the existing cement must be washed out quickly (before it sets), the repair made, the testing performed and then new cement mixed. Discharge is the most effective means to support rapid repair since typically weight and space constraints prevent holding empty containers offshore for such a contingency. This can involve potential well control issues if the cement system cannot be returned to service quickly.
o More generally, even if no cement job is in progress, the testing after repair is critical to assure all systems work as designed and provide cement that can comply with well design requirements.
Estimated volumes are 5-100 bbls per event. The Joint Trades estimate this occurrence is rare on a per rig basis. In 2012, a high activity year, there were ~ 99 rigs working in the GOM (2) (as of June 23, 2017 there were only 22 rigs active in the GOM). Using the 2012 rig count and assuming one event per year per rig this equates to ~500-10,000 bbls/year of slurry discharged.
o Cement not meeting the specifications for a well job: 20-100 bbls. OOC expects this to also be a rare occurrence. Note- if this occurs when a well is in a productive interval, the cement must be washed out of the unit to prevent setting. Then a new batch needs to be quickly mixed to prevent well control issues. Discharge is the most effective means to support rapid response since typically weight and space constraints prevent holding empty containers offshore for such a contingency. This can involve potential well control issues if the cement system cannot be returned to service quickly
A review of BOEM data (3, 4) indicate > 100 wells per year are drilled in the Gulf during high activity cycles. Assuming one event per well per year yields 2000-10,000 bbls/yr of slurry discharged.
In summary, annual expected discharges of the proposed "Unused Cement Slurry" could be on the order of:
Commissioning of new drilling units s= 600-1400 total bbls/year
Repairs=
500-10,000 total bbls/year
Off spec cement
2000-10,000 total bbls/year
ED 002061 00130976-00024
Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permt Language /Clarificatons/lssue
Page 21 of 30 Tiers 8&9
Total=
Rationale 3100 - 21,400 total bbl/year
Compare this to a single well's discharge of authorized Excess Cement Slurry (as authorized and defined in the permit): though highly variable depending on many factors, this is on the order of approximately 100-400 bbis (including pit cleanouts after a job). The majority of this is associated with riserless operations.
Assuming 100 wells/year are drilled in the Gulf, this yields approximately 10,000-40,000 bbis of Excess Cement Slurry already authorized by the current permit (and continued for authorization in the proposed permit) for discharge. The volumes shown above for the proposed Unused Cement Slurry are of the same order of magnitude as existing authorized excess cement slurry discharges (and are probably lower). Given this, and typical discharge at or near the surface with immediate dispersion into the water column, the environmental impacts are expected to be insignificant.
As an alternative, the Joint Trades request a joint industry study be performed to assess the overall environmental and safety impacts of this discharge to better inform the decision before considering a prohibition, in the next permit cycle.
References
1. Personal communication, Kuehn - Rigzone, 4/23/12.
2. Rigzone- Rig Report: Offshore Rig Fleet by Region http://www.rigzone.com/data/rig report.asp?rpt=reg
3. http://www.boem.gov/uploadedFiles/BOEM/Newsroom/Offshore Stats and Facts/Gul f of Mexico Region/OCSDrilling.pdf
4. http://www.gomr.boemre.gov/PDFs/2009/2009-016.pdf
2. The Joint Trades request that Unused cement frequencies included: "such discharges are limited to per calendar year per facility" and "one discharge per well" should be removed and the statement should read,
Unused Cement Slurry - Each type of unused cement slurry discharge is limited to once per cementing job. The operator shall report date, identification of well or facility, volume of cement, and cause of the discharge in their NetDMR.
The language proposed in the draft is overly burdensome and introduces complexity for tracking and assuring compliance with a once per facility and once per well limitation. These restrictions may also limit the operator from mitigating well control issues if the cement system cannot be returned to service quickly during each cementing job. Each facility has multiple wells flowing to it and each well may require multiple cementing jobs.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
ED 002061 00130976-00025
Comment No. 31
Type/Category
Miscellaneous Discharges of Seawater and Freshwater which have been chemically treated
Permit Section Ref, Part I.B .ll
Current or Revised Permit Language /Clarifications/lssue
Revise and reword section as follows:
Excess seawater which permits the continuous operation of fire control and utility lift pumps, Excess seawater from pressure maintenance and secondary recovery projects, Water released during training of personnel in fire protection, SeawWater used to pressure test piping and pipelines, Ballast water, Once through non-contact cooling water, SeawWater used as piping or equipment preservation fluids, and SeawWater used during Dual Gradient Drilling.
Rationale
The Joint Trades request that a change be made to the Title and list for "Miscellaneous Discharges of Seawater and Freshwater which have been chemically treated". This will be a word change from "Seawater" and "Freshwater" to "Water". This change will ensure that both "Seawater" and "Freshwater" are included in the chemically treated discharge list.
Not accepting the proposed permit language is onerous on operators and an additional burden to the O&G Industry with no apparent additional protection to the environment.
Water includes both seawater and freshwater discharges.
32 Miscellaneous Part I.B .ll.a "a. Limitations
The Joint Trades request the addition of the note to provide clarification that the chemical
Discharges of
concentration limits are based on each constituent that make up the treatment chemical in the
Seawater and
Treatment Chemicals. The concentration of treatment chemicals in
discharge.
Freshwater
discharged seawater or freshwater shall not exceed the most stringent of
which have been
the following three constraints:
chemically
Additionally, the Joint Trades request EPA provide clarification regarding the following related to
treated -
1) the maximum concentrations and any other conditions specified in "Treatment Chemical Concentration" :
Limitations
the EPA product registration labeling if the chemical is an EPA
registered product
What if a treatment chemical degrades over time or is reacted away (e.g., acid, biocide)
2) the maximum manufacturer's recommended concentration
before discharge occurs? Would the discharge be considered as chemically treated?
3) 500 mg/l
Not accepting the proposed permit language is onerous on operators and an additional burden
[Note: The above concentration limits are based on each constituent that to the O&G Industry with no apparent additional protection to the environment.
make up the treatment chemical in the discharge.]
33 Miscellaneous Part I.B .ll.a "[Note: Discharges treated by bromide, chlorine, or hypochlorite or which
Discharges of
contain only electrically generated forms of chlorine, hypochlorite, copper The Joint Trades request revising the text to include copper, iron, and aluminium ions to account
Seawater and
ions, iron ions, and aluminium ions are not required for toxicity tests.]"
for the fact that not only is electric current used to generate active chlorine from seawater, but
Freshwater
also there are systems which use sacrificial anodes to generate other anti-biofouling ions (such
which have been
as, iron, copper and aluminium). Examples of several systems and related information can be
chemically
found at the following links:
treated -
Limitations
http://www.farwestcorrosion.com/cathelco-marine-pipework-anti-fouling-svstems-for-
fpsos.html
https://cathodicme.com/mgps-svstems/marine-growth-prevention-svstem/
http://www.cathelco.com/mgps-overview/how-a-marine-growth-prevention-svstem-works/
http://www.blumeworldwideservices.com/
Additionally, the Joint Trades are providing a current Copper Ion system installation and maintenance document in use (see attachment Appendix B).
Page 22 of 30
The Joint Trades do not expect the discharge will have a toxic impact on the environment as these systems operate in the part per billion concentration range. It is also noted that these
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ED 002061 00130976-00026
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
systems are in use in the marine industry. Based on review of the manufacturer information, these systems operate with a copper in solution of less than 2 ppb. At less than 2 ppb in solution, a 100% effluent discharge would have a copper concentration that is lower than that of the EPA marine chronic and acute criteria. When compared using the existing critical dilutions and NOECs from recent testing, the copper concentration is even lower than at 100% effluent discharge and thus would be lower than the EPA marine chronic and acute criteria.
Further, it should be noted that there is no marine water quality criteria for Aluminium. However, it is expected that the concentration of aluminium in solution will be less than the copper concentration, based on manufacturer information.
The Joint Trades are submitting toxicitv testing information to support no toxic impact from these systems. Data collected from electric current generated ion treated seawater discharges under current general permits GEG460000 and GMG290000 demonstrate no reasonable potential for toxicity at the critical dilution and should be excluded from the monitoring requirement. These data include electric current generated copper, iron and aluminium ions and are hereby submitted as Appendix C.
Additionally, the Joint Trades are requesting this change be made to be consistent with the Draft Region 4 permit GEG4600000. This permit includes the exemption for electrically generated forms of chlorine, hypochlorite, copper ions, iron ions, and aluminium ions.
Ref.: Notice of Proposed National Pollutant Discharge Elimination System (NPDES) General Permit for New and Existing Sources in the Offshore Subcategory of the Oil and Gas Extraction Category for the Eastern Portion of the Outer Continental Shelf (OCS) of the Gulf of Mexico (GEG460000), Public Notice No. 16AL00001.
Not accepting the proposed permit language is onerous on operators and an additional burden
to the O&G Industry with no apparent additional protection to the environment.
34 Miscellaneous Part I.B .ll.b "Flow Volume. Once per quarter-month, an estimate of total flow (bbi/day)
Discharges of
The Joint Trades request clarification on the reason for the change of ChemicallyTreated
Seawater and
reported recorded. (The-epecateesfoaFI-keep-reeerds-ordrsefoarge-evefttSr)" Miscellaneous Discharge volume from highest "Monthly Average per monitoring period"
Freshwater
(quarter) to "Total volume per quarter" when all other permit requirements for chemically
which have been
treated volume (i.e. frequency and critical dilution) remain and are based on "highest monthly
chemically
average".
treated -
Monitoring
Discharge volume reported on toxicity lab reports currently reflects the volumes needed
Requirements
to determine critical dilution and frequency of testing, providing a clear record of why
the test was conducted at the frequency and applicable critical dilution (as determined
by the current required volume limitations).
Keeping track of two different types of measurements could potentially cause confusion
and possibly result in testing done at an incorrect frequency or critical dilution.
This reporting requirement has not changed since ChemicallyTreated Miscellaneous
Discharge requirements were added to the permit in 1998.
And historically, the discharge volume reporting requirement has remained the "highest
monthly average" for all discharges requiring volume reporting (and toxicity testing).
Page 23 of 30
The Joint Trades request that the proposed change to chemically treated volume reporting not be incorporated into the reissued permit and remain as stated in the current permit.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00027
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarificatons/lssue
Rationale
35 Cooling Water Part Intake Structure I.B.12.a.l Requirements Information Collection
"New fixed facilities must have submit source water baseline biological characterization data, source water physical data, cooling water intake structure data, and velocity information:"
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades are requesting this change to provide consistency with the first sentence found under Part l.B.12.a and Section VILE of the proposed Fact Sheet.
Part I.B.12.a states "The owner or operator of a new offshore oil and gas extraction facility must retain [emphasis added]_the following information with the facility and make it available for inspection.".
Section VILE of the proposed Fact Sheet states "EPA also proposes to reduce application information collections from new facilities as identified in the current permit Part LB. 12. a. Instead of submitting such information to EPA, the new facility operator shall keep those information (either paper or electronic document) accessible for inspection. The operator of new facility still shall report basic information, such as facility location, design intake capacity, and intake velocity, in NOI as reguired in permit Part LA.2, but shall keep the records of details and all calculations or drawings with the facility and make it available for inspection. New facilities which have any intake structure with a designed intake velocity greater than 0.5 ft/sec are not authorized to discharge cooling water under this permit."
The draft permit language is more onerous on operators and the additional burden to the O&G
Industry does not have any apparent additional protection to the environment.
36 Cooling Water Part
Part I.B.12.C.1.N
Intake Structure I.B.12.C.1. "ii. Velocity monitoring. The operator must monitor intake flow velocity
The Joint Trades are requesting a tiered approach to velocity monitoring versus the current daily
Requirements - Part
across the intake screens to ensure the maximum intake flow velocity does monitoring requirement. Namely,
Velocity
I.B.12.c.2.iii not exceed 0.5 ft/s. The intake flow velocity shall be monitored daily
Monitoring
Part
quarterly if the most recently reported intake flow velocity is less than 0.30 If the Most recent intake flow Then Monitoring Frequency
Requirements I.B.12.C.3. ft/s; monthly if the most recently reported intake flow velocity is 0.30 to
velocity (ft/s)
Should be
0.38 ft/s; and daily if the most recently reported intake flow velocity
<0.300
Quarterly
exceeded 0.38 ft/s. A downtime, up to two weeks, for periodic
0.300-0.38
Monthly
maintenance or repair is allowed and must be reported in the DMRs. When replacement parts cannot be obtained within the two-week time period,
>0.38
Daily
the down time can be extended in increments of two weeks until the replacement parts or equipment can be obtained by the facility. In addition to the initial two-week downtime allowance, each additional two-week increment for downtime must be reported in the DMRS indicating reasons
Velocity monitoring consists of a demonstration requirement based on the facilities' proposed design and a compliance monitoring requirement that verifies the velocity limitation is being met. There is agreement with the purpose of inspection, but not the frequency.
why the additional increment(s) was needed."
The tiered velocity monitoring approach is based upon a statistical analysis of six separate CWIS
Part I.B.12.c.2.iii "ii. Velocity monitoring. The operator must monitor intake flow velocity across the intake screens to ensure the maximum intake flow velocity does not exceed 0.5 ft/s. The intake flow velocity shall be monitored da+fy quarterly if the most recently reported intake flow velocity is less than 0.30 ft/s; monthly if the most recently reported intake flow velocity is 0.30 to 0.38 ft/s; and daily if the most recently reported intake flow velocity exceeded 0.38 ft/s. A downtime, up to two weeks, for periodic maintenance or repair is allowed and must be reported in the DMRs. When replacement parts cannot be obtained within the two-week time period, the down time can be extended in increments of two weeks until the
operated in the GOM during 2015. The analysis is based on the rate-of-change in daily velocity monitoring data (attached as Appendix D). An ANOVA indicates no statistical difference in the rate of change in intake velocity among the five intakes (P < 0.05). The data are approximately normally distributed with a mean change in velocity equal to 0.0001 (ft/s)/day and a standard deviation equal to 0.0106 (ft/s)/day. Based on these data, there is a 95% probability that the mean velocity increase over any 30-day period will be less than 0.11 (ft/s)/day; and a 95% probability that the mean velocity increase over any 90-day period will be less than 0.20 (ft/s)/day. Therefore, 95% of all monthly intake velocity measurements will be less than 0.5 ft/s provided that the previous month's velocity measurement was less than 0.39 ft/s. Similarly, 95% of all quarterly velocity measurements will be less than 0.5 ft/s provided that the previous quarter's measurement was less than 0.30 ft/s.
Page 24 of 30
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ED 002061 00130976-00028
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
replacement parts or equipment can be obtained by the facility. In addition to the initial two- week downtime allowance, each additional two-week increment for downtime must be reported in the DMRS indicating reasons why the additional increment(s) was needed."
Rationale
We note this data makes sense relative to visual inspection information presented elsewherethe rate of biogrowth on intakes is quite low and so the rate of change of intake velocity would also be expected to be quite low, hence allowing for reduced monitoring frequencies (using a tiered approach to ensure compliance with the 0.5 fps standard for any CWIS design).
Part I.B.12.C.3.N "ii. Velocity monitoring. The operator must monitor intake flow velocity across the intake screens to ensure the maximum intake flow velocity does not exceed 0.5 ft/s. The intake flow velocity shall be monitored daily quarterly if the most recently reported intake flow velocity is less than 0,30 ft/s; monthly if the most recently reported intake flow velocity is 0.30 to 0.38 ft/s; and daily if the most recently reported intake flow velocity exceeded 0.38 ft/s. A downtime, up to two weeks, for periodic maintenance or repair is allowed and must be reported in the DMRs. When replacement parts cannot be obtained within the two-week time period, the down time can be extended in increments of two weeks until the replacement parts or equipment can be obtained by the facility. In addition to the initial two -week downtime allowance, each additional two-week increment for downtime must be reported in the DMRS indicating reasons why the additional increment(s) was needed."
Further, the Joint Trades are requesting the additional language be included to account for times when replacement parts and equipment cannot be obtained from a manufacturer in a two-week time frame. Sometimes these items are on backorder and require additional time to receive.
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
37 Cooling Water Part
Intake Structure I.B.12.c.2.ii ii. The permittee must submit a SEAMAP data report annually to meet the The Joint Trades strongly objects to the continued requirement to conduct ongoing entrainment
Requirements -
requirements of 40CFR125.137. iBtFamment-moBitering/safRplmg-.--Th&
monitoring.
Entrainment
Monitoring
The Joint Trades request the removal of entrainment monitoring/sampling requirement and the
Requirements
tb&4fttake-stw tw 6f
addition of language requiring permittees to submit a SEAMAP data report annually.
Jfrt-ak-&-Sef&efi-0f Q p e n ifig-L-e eate s
*******
< %tw. |j^* y v yy
< ~ 4 .& Q
2 Q Q -M -
pef-Year-
ApF4lr 0ftd J0ftey-afi4
and-lim e
-2 0 Q --M
Qne-Sampl-e-pereaf
40 CFR 125.137.a.3 provides the Director the flexibility to reduce the frequency of monitoring following 24 months of bimonthly monitoring provided that "seasonal variations in species and the numbers of individuals that are impinged or entrained" can be detected. The report on the 24 month industry entrainment study (1) documents that many important Gulf of Mexico species were not detected at all in the regions where new facilities are expected to be installed so that entrainment impacts on these species will be zero; (2) provided documentation on the seasonal dependence of species and number of eggs and larvae available for entrainment, and (3) concludes that anticipated entrainment will have an insignificant impact on fisheries in any season; the Joint Trades believes that the intent of 40 CFR 125.137 has effectively been met and that the requirement for ongoing entrainment monitoring can be removed.
Our request is based on the results of the results of the recently completed Gulf of Mexico Cooling Water Intake Structure Entrainment Monitoring Study and reinforced by the quarterly entrainment monitoring reports by individual operators (attached as Appendix E). Industry believes that these results warrant removal of the entrainment monitoring/sampling because (a) the study showed that no meaningful impacts from entrainment are expected; (b) no meaningful impact was found, therefore, the seasonality of the impact is a moot point; (c) the SEAMAP database provides a continually-updated source of information that is functionally equivalent to permit-required monitoring for the purpose of estimating entrainment impacts.
The following is a brief summary of key findings of the industry entrainment monitoring study:
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Comment No.
Type/Category
Permit Section Ref,
Sierra Club v. EPA 18cv3472 NDCA
Current or Revised Permit Language /Clarifications/lssue
Page 26 of 30 Tiers 8&9
Rationale 1. Study results provide data for enumeration of entrainment losses by species and for total egg and larval losses as required by the Permit.
2. Estimated entrainment impacts on ichthyoplankton are insignificant.
A. Entrainment monitoring/sampling is required during the primary period of reproduction, larval recruitment, and peak abundance for each species, specifically, identified as part of the Source Water Biological Baseline Characterization Study (SWBBCS); however, the SWBBCS found no evidence to suggest CWIS would impact selected species of socioeconomic and ecological importance.
B. In this study, catches of SWBBCS selected species were too low to statistically model (all exhibited >90% zeroes across tows; some 100% zeroes).
C. Thus, no meaningful impacts from entrainment on these species are expected to occur.
D. Daily entrainment was extremely small compared to the corresponding daily reference abundances drifting past each facility; thus, no meaningful impacts are expected for any species.
3. Temporal and environmental influences on ichthyoplankton densities.
A. While no impacts are expected to occur at any intake depth, the most prevalent influence was sampling depth, whereby densities declined exponentially with increasing depth.
B. In general, the lowest densities occurred during the fall and greatest densities during the spring.
4. Using SEAMAP data to estimate entrainment loss.
A. Ichthyoplankton densities also declined exponentially with total water column depth; all study sites were deeper than the shallower depths (about < 200 m) where sharp increases in densities began in the shoreward direction.
B. For each of the study sites and across months, forecasted densities based on SEAMAP data were consistently VA to 2 times greater than those observed during this study.
C. No impacts are expected based on densities estimated from either dataset.
D. Thus, SEAMAP data appear adequate for future estimates of impacts on the ichthyoplankton community.
The results of recent quarterly on-platform entrainment monitoring studies conducted (attached as Appendix E) are fully consistent with the results of the Entrainment Monitoring Study. The concentrations of larvae of key socioeconomic and ecological important species were typically zero in these measurements. This is consistent with industry's views that (1) cooling water
ED 002061 00130976-00030
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permt Language /Clarificatons/lssue
Rationale
intake structures on offshore facilities present an insignificant risk to fisheries, (2) the quarterly monitoring requirement is providing no new useful information and (3) the requirement should be dropped entirely.
Platform-specific monitoring in the Gulf of Mexico shows that data collected from actual cooling water systems indicates that fish egg and larval concentrations are equivalent to or much lower than those in the SEAMAP database for the same fishery zones (See Appendix F).
The Joint Trades believe that a requirement for periodic reports based on the updated SEAMAP database are appropriate to the risk as demonstrated in the SWBBCS and entrainment monitoring studies. Using the SEAMAP database for entrainment risk assessment is actually preferable to platform specific monitoring because:
Data are collected and maintained over the long term, using consistent methodology for all sites, ensuring comparability of data over time
The existing SEAMAP database already provides an assessment of seasonality of entrainment risk (as required by 40CFR125.137) which can be periodically updated as new data are added to detect changes in risk over time.
SEAMAP larval data could be selected for most common species in each region Approach is cost effective and appropriate to the low level of risk demonstrated in the
24-month Entrainment Monitoring Study and in a peer-reviewed study of entrainment risk from much larger water volumes in depths of 20-60 m where egg and larval densities are much higher.* *Gallaway, B.J., W.J. Gazey, J.G. Cole, and R.G. Fechhelm (2007); "Estimation of Potential Impacts from Offshore Liquefied Natural Gas Terminals On Red Snapper and Red Drum Fisheries of the Gulf of Mexico: An Alternative Approach" Transactions of the American Fisheries Society (2007) 136:655-677
Given this finding, use of existing SEAMAP system for monitoring entrainment is a much more comprehensive, cost-effective mechanism for gauging the seasonality of entrainment potential over time. Such SEAMAP reporting could be done by the Agency's review of this data set or by a permit requirement for industry to submit annual reports on the SEAMAP data.
Although striking this requirement in its entirety is the Joint Trades' preference, should EPA Region VI continue to insist on platform entrainment monitoring, The Joint Trades are requesting that the entrainment monitoring be no longer required after two vears' entrainment data demonstrates the number of entrained species is lower or close to SEAMAP data.
Suggested alternate wording would be:
"Facilities with two years of entrainment data demonstrating that the number of entrained species is lower or close to SEAMAP data are no longer reguired to conduct entrainment monitoring. Permittees shall submit a certification that the entrainment data is less than or close to SEAMAP data prior to discontinuing entrainment monitoring."
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ED 002061 00130976-00031
Comment No.
Type/Category
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Rationale
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment.
38
Other Discharge Part I.C.l
"Floating Solids or Visible Foam or Oil Sheen"
Limitations -
Floating Solids
or Visible Foam
The Joint Trades are requesting the deletion of "or Oil Sheen" from this section. The deletion is requested for the following reasons:
The permit already restricts oil sheens from discharges through the various requirements for no "Free Oil".
Section 311 of the Clean Water Act prohibits the discharge of oil. Listing "Oil Sheen in the title of this part leads to confusion on the intent of the part. The
Joint Trades believe it was not the intent to allow the discharge of "trace amounts" of oil and/or oil sheen.
Not accepting the proposed permit language is onerous on operators and an additional burden
to the O&G Industry with no apparent additional protection to the environment.
39
Other Discharge Part I.C.3
Part I.C.3
Limitations -
The Joint Trades agree with the comments in VILJ on pages 26 and 27 of the fact sheet that
Dispersants,
And Part
"The discharge of dispersants, surfactants, and detergents is prohibited
surfactants should not be added to the produced water discharge to prevent detection of a
Surfactants, and I.B.4.a
except when it is incidental to their being used to comply with safety
sheen on the receiving water and circumvent the permit's produced water sheen monitoring
Detergents
requirements of the Occupational Safety and Health Administration and the requirements. However, the Joint Trades are concerned that the proposed changes to the
Bureau of Safety and Environmental Enforcement."
permit language regarding the discharge of dispersants, surfactants, and detergents may have
unintended prohibitions on the use of surfactants (detergents, dispersants) in the context of the
Part I.B.4.a
use of surface active substances in the formulation of chemicals used in the offshore oil and gas
industry to impart specific properties to the formulations (see attached document Surfactants in
"The addition of dispersants or emulsifiers to produced water discharges is Oil & Gas Drilling provided as Appendix G and also API's Offshore Effluent Guidelines Steering
prohibited when used for purposes that could circumvent the intent of the Committee paper Chemical Treatments and Usage in Offshore Oil and Gas Production Systems,
permit's produced water sheen monitoring requirements. 4Q-FR-44Q-.-4-.-" Hudgins, October 1989) (attached as Appendix A).
The Joint Trades recommend keeping the current permit language in Section I.C.3.
The Joint Trades request the changes to the proposed language in Part I.B.4.a as noted in the proposed red text. See Comment No. 8 for additional information and discussion on this requested change.
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ED 002061 00130976-00032
Comment No.
40
Type/Category
Spill Prevention Best Management Practices
Permit Section Ref,
Current or Revised Permit Language /Clarifications/lssue
Part II.B.7
"This general permit does not authorize discharges, including spills or leaks, caused by failures of equipment, blowout, damage of facility, or any form of unexpected discharge. If a permittee seeks a conditional exemption to the discharge restrictions of this permit, the permittee must demonstrate to the Regional Administrator the potential environmental impacts and/or benefits of the proposed discharge. Approval from the Regional Administrator must be obtained prior to commencement of such discharge and the Regional Administrator will establish appropriate discharge limitations based upon the evidence provided by the permittee,"
Rationale
The draft permit language is more onerous on operators and the additional burden to the O&G Industry does not have any apparent additional protection to the environment. The Joint Trades request adding the suggested language in red text to provide a mechanism for EPA to approve unique and novel discharges that may not be covered by the existing permit conditions, but may be necessary for a variety of operational reasons. By adding the attached language, a permittee and EPA can evaluate such situations based on sound science and information. EPA can then make an appropriate decision after completing a review.
Not accepting the proposed permit language is onerous on operators and an additional burden to the O&G Industry with no apparent additional protection to the environment.
41 Reporting
Part II.D.4 "If for some reason the electronic submittal is not accepted or the NetDMR
Requirements -
system is not available, the permittee would be required to submit the
The Joint Trades are requesting the additional language to:
Discharge
paper DMR. The permittee has up to 60 days to submit paper DMRs.
Provide clarity when the NetDMR system is not available
Monitoring Reports (DMR)
"NOTE: As soon as NetDMR is available, the permittee must file their DMRs electronically. The paper DMRs serve as evidence the permittee attempted
Provide an official address for submittal of the paper DMRs.
and Other Reports
to meet their submission deadline when NetDMR was not available. The evidence will be the mail receipt (e.g., FedEx, UPS, USPS, etc.) showing EPA received the paper DMRs."
Additionally, the Joint Trades are requesting a set of instructions for completing DMRs in accordance with the requirements of the permit the effective date of the permit. The instructions should utilize the permit requirements first and provide clarification when there are
"Operators shall mail all paper DMRs and all paper DMR attachments to the following address:
Water Enforcement Branch (6 EN-WC) U.S. Environmental Protection Agency Region 6 1445 Ross Avenue Dallas, TX 75202"
limitations or input variables with the electronic system and DMRs. The Joint Trades cannot stress the importance that the instructions and DMR be built around the permit requirements and not vice versa. The permit requirements are what an operator is held accountable to and not the limitations and data inputs of the electronic system. These detailed instructions would eliminate multiple DMR errors and create more consistency and should eliminate most of the BSEE inspector's questions and confusion during offshore inspections.
"Instructions for completing DMRs in accordance with the permit requirements are available in EPA Region 6's website at http://www.epa.g0 v/region6/ 6 en/w/offshore/hom e.htm ."
The instructions should include information on DMR reporting during the transition of coverage from the 2012 permit to the new 2017 permit. An operator has 90 days from the effective date to submit an NOI for coverage of existing permit coverage under the 2012 permit. It is unclear which timeframe and how to properly report on DMRs between each permit once a NOI is
"Other required reports shall be submitted electronically with NetDMR.
submitted within the 90 days for coverage under the new permit.
EPA may request a paper copy of any report in addition to the electronic report."
Since the NetDMR system encompasses many different permit types, not all of the No Data Indicator Codes (NODI) are applicable to the Region 6 DMRs. Therefore, the Joint Trades are
requesting the instructions also include guidance and clarification on which NODI codes are "If discharge is not applicable for a facility, "no discharge" must be reported applicable and in what context they should be used in accordance with the permit requirements. for that facilityk until an NOT is submitted. "
The Joint Trades request the ability to review and comment on the DMR instructions prior to
them being finalized to allow for clarification and edits as necessary.
The Joint Trades are requesting that the DMR be corrected to reflect the correct permit requirements outlined in the permit for each parameter. The current DMR contains numerous typos and inconsistencies with the permit requirements. OOC has outlined several of these in the attachment provided in Appendix H.
The Joint Trades are also correcting a typo that was found in the last sentence.
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ED 002061 00130976-00033
Comment No. 42
43
Type/Category
Reporting Requirements Signatory Requirements (Certification)
Reporting Requirements Electronic Signatures
Permit Section Ref, Part II.D.lO.c
Part II.D.lO.d
Current or Revised Permit Language /Clarifications/lssue
" 1certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gathered and evaluated the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. Thave-ne-p-efsonal
complete-. 1am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations." "Electronic Signatures: Please visit http://www.epa.g0v/region6/6en/w/offshore/home.htm for instructions on obtaining electronic signature authorization to sign eNOIs, eNOTs, and NetDMRs."
Rationale
The lack of active website, email address and NOI, NOT and DMR instructions is very onerous on operators and the burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades are requesting the deletion in the certification statement because it is not consistent with the certification statement found at 40CFR 122.22.d. The correct certification statement found in the regulations is: "1 certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the Information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. 1am aware that there are significan t penalties for submitting false information, including the possibility offine and imprisonmen tfor knowing violations."
The Joint Trades request that this website be activated prior to the effective date of the permit and that all applicable instructions be uploaded to it. The EPA website listed is not currently active.
44 Section G. Definitions
Part II.G
Unused cement slurry- cement slurry used for testing of equipment or resulting from cement specification changes or equipment failure during the cementing job.
The lack of active website, email address and NOI, NOT and DMR instructions is very onerous on operators and the burden to the O&G Industry does not have any apparent additional protection to the environment.
The Joint Trades request adding this definition for "Unused Cement Slurrv". The rationale for this addition is included in Comment No. 30 for Part I.B.lO.a.
45 Section G. Definitions
46 Appendix F Table 1
Part II.G.86
Appendix F -Table 1
"Uncontaminated Freshwater" means freshwater which is discharged without the addition or direct contact of treatment chemicals, oil, or other wastes. Included are (1) discharges of excess freshwater that permit the continuous operation of fire control and utility lift pumps, (2) excess freshwater from pressure maintenance and secondary recovery projects, (3) water released during training and testing of personnel in fire protection, arr (4) water used to pressure test or flush new piping or pipelines, and (5) potable water and off-specification potable water. Appendix F -Tab le 1
Not accepting the proposed permit language is onerous on operators and an additional burden to the O&G Industry with no apparent additional protection to the environment.
To provide clarification, the Joint Trades request adding the addition of "potable water and offspecification potable water" to the definition for "Uncontaminated Freshwater".
Not accepting the proposed permit language is onerous on operators and an additional burden to the O&G Industry with no apparent additional protection to the environment.
The Joint Trades request that once all edits and changes to the permit text language is complete, Table 1, Appendix F requirements should be updated accordingly to match. The Joint Trades would prefer that Table 1 be removed completely from the permit because EPA has historically stated that the permit text holds precedent over Table 1, and because of potential inconsistencies between the permit language and Table 1.
Not accepting the proposed permit language is onerous on operators and an additional burden to the O&G Industry with no apparent additional protection to the environment.
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Page 30 of 30 Tiers 8&9
ED 002061 00130976-00034
APPENDICES
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ED 002061 00130976-00035
APPENDIX A COMMENT NO. 9 & 39
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00036
CHEMICAL TREATMENTS AND USAGE IN OFFSHORE OIL AND GAS PRODUCTION SYSTEMS
Prepared for AMERICAN PETROLEUM INSTITUTE
Offshore Effluent Guidelines Steering Committee
by Charles M, H udgins, Jr. Petrotech C onsultants, Inc.
October, 1989
13910 Champion Forest Dr. Suite 104 Houstoo, Texas 77069 U.SA,
Telephone: (713) 444*5719 Telefax: (713) 444*1457
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00037
TABLE OF CONTENTS
ACKNOWLEDGEMENT
ABSTRACT
in t r o d u c t io n
OBJECTIVE SCOPE APPROACH
Interview Chemical Suppliers Interview Operating Companies Literature Review'
DEFINITIONS, USAGE OF TERMS
PRODUCTION TREATING CHEMICALS Treatment Purpose Generic Chemical Types Formulations, Additives Multipurpose Formulations
GAS PROCESSING CHEMICALS Hydrate Inhibition Chemicals Dehydration Chemicals
STML lATT? AND W ORKOVER CHEMICALS Acids and Additives Workover Fluids and Additives
TYPICAL SYSTEMS
PRODUCTION PROCESS FLOW SCHEMES SINGLE COMPLETE PLATFORM CENTRALIZED PROCESSING PLATFORM ONSHORE PROCESSING GAS PROCESSING W A T E R FL O O D IN G STIMULATION AND WORKOVERS
PRODUCTION TREATING CHEMICALS
SCALE INHIBITORS
(Typical discussion outline) Problem Description Chemical Treatment'Alternate Solutions Chemical Description
Basic Generic Types ModificationsFormulations Solubility Application
Treatment Methods ' Concen trations ' Practice
CORROSION INHIBITORS BIOCIDES EMULSION BREAKERS REVERSE BREAKERS
fN r-i
Page
1 2 2
3 3 3 4 4 4 4 5 5 5 5
6 7 8 8 8 9 10
12
14 18 20 22
Sierra Club v. EPA 18cv3472 NDCA
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ED 002061 00130976-00038
COAGUIANT S , FLOCCUIANTS
23
ANTIFOAM
24
SURFACTANTS
25
PARAFFIN TREATING CHEMICALS
26
SOLVENTS AND ADDITIVES
27
GAS PROCESSING CHEMICALS
HYDRATE IN H IB m O N CHEMICALS
27
Naturai Gas Hydrates
27
Prevention of Hydrates
28
M ethanol
28
Ethylene Glycol
29
DEHYDRATION CHEMICALS
29
Triethylene Glycol
29
Other Glycols
29
STMU1ATION AND WORKOVER CHEMICALS
ACIDS
29
Hydrochloric Acid
29
Hydrofluoric Acid
30
O ther Acids
30
Additives
30
DENSE BRINES AND ADDITIVES
31
Chloride Brines
31
Bromide Brines
31
Brine Additives
32
ENVIRONMENTAL ASPECTS
GENERAL CONSIDERATIONS
32
Prediction of Environmental Impact
32
Laboratory Toxicity Testing
32
Solubility
33
Chemical Characterization
33
Biodegradability
33
AQUATIC TOXICITY DATA
33
Production Treating Chemicals
33
Gas Processing Chemicals
35
Stimulation and Workover Fluids
39
PRACTICAL ASPECTS
39
System Effects
39
Production Treating Chemicals
39
Gas Processing Chemicals
42
Stimulation and Workover Chemicals
42
SUMMARY
REFERENCES
Sierra Club v. EPA 18cv3472 NDCA
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ED 002061 00130976-00039
U .K M .m i KDGEM KVF
The author would like to express his gratitude to the companies and individuals who have contributed so much in helping to make this report an accurate and broad perspective of current practic es in offshore opera tions . Many cooperated in the original 1985 survey, some were only involved in updating and expanding the survey in 1989 ("), and others contributed to both efforts (#). The following companies and individuals were interviewed regarding the chemical properties and applications:
Conoco, Inc,:#
D.D. Caudle#, D. Barber, A.L.G, Bisso, M. Williams#, W.K Kewley, F. Laskowski"
Exxon Co., USA:#
T. Michie, F.P.H, LeBlanc, M. Parker", M. Barrilleaux", D, Brown", D.KalZ"
Shell Offshore, Inc.#: R J. Redweik, B, Gordon, V. Edwards, T, Randolph", G. Doucei". B. Stringfield", K, Myers", L, Crane
Texaco Inc.#:
M.T. Stephenson#, U.M. Corso# , F. Fraker
Dowell Schlumberger" : e. Crowe"
Exxon Chemical#:
SJ.Wangerin. M.W. Eiser. M. Fefer, W.e. Whiteside, R.F. Richter", K.T. Allford#
Halliburton" :
J. Chatterji", R. Bechtel", M. Misak"
Nalco Chemical Co,#: M. Lillman, D. Kroll. G. Chappel#, D. Deshazo, S, Alleasoa, R.K. Gable'
NL Treating Chemicals: K. T. Allford#
Petrofite Corporation#: TJ . Robichaux#, G. Cary#. DRorstmann, T.E. Gerst, D. Zienty, E. French. H.M. Hilliard#, K. Barker", F. E. Mange"
Union Carbide C o rp J : S.E. Foster, W.M. Snellings", R. Jarvis"
Welchem, [ne.#:
D.V. Agafon. H.S. Carson#, e.FI. Johnson, NJ. Mtmdhenk'
In addition some information and data was obtained horn the following suppliers through operating
companies: Ashland Chemical Co., Baker Performance Chemicals; Inc,, B J - Titan Services, Champion Chemicals, Inc., Coastal Chemical Company, DataChem, [nc.. OSCA, Tetra Resources, [ne., Western Compa ny of North .America, X-Chem.lnc.
The helpful suggestions of the review committees and their respective coordinators are also greatly appre ciated:
1985, Offshore Operators Committee. Industrial Technical Advisory Group. Dan Caudle. Coordinator 1989, American Petroleum Institute. Offshore Effluent Guidelines Steering Committee,
Michael Stephenson, Coordinator.
The financial support of these two organizations is also gratefully acknowledged.
While the assistance and information provided by all of the above parties is expressly acknowledged, (he final responsibility for the selection, organization, and interpretation is the author's.
Charles M, Hudgins. Jr. Petrotech Consultants, jnco 13910 Champion Forest Dr., Suite 104 Houston, TX 77069, U.SA.
(713) 444-5719. FAX (713) 444-1457, Telex 792831
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ABSTRACT
This report reviews the chemicals used to help control many operating problems encountered in V.S. offshore oil and gas production. The discus sions cover all chemicals used, including production treating chemicals, gas processing chemicals, and stimulation and workover chemicals. Each topic includes problem description, genetic chemical types, solubility and treatment methods and concen trations.
A portion of these chemicals will dissolve in the produced water. Most of the water produced with oil and gas in offshore operations in the V.S. is treated to remove dispersed oil and grease, then discharged to the sea. The discussion on environ mental aspects provides information on the aquatic toxicity, solubility, and treatm ent practices for chemicals used for each purpose. Actual environ mental impact must include site specific factors, such as water depth, current, temperature, elC'., which are outside the scope of this report.
Acute aquatic toxicity and solubility information was provided by the chemical suppliers for the production treating chemicals, including biocides, scale and corrosion inhibitors, emulsion breakers, etc. Aquatic toxicity data for the gas processing chemicals (methanol, glycols) was primarily ob tained from the literature. No aquatic toxicity data was obtained for the stim ulation and workover chemicals from the suppliers. Typical treatment methods and system configurations were obtained from operators and chemical suppliers. No assess ment of the quality of this data is included.
INTRODUCTION
OBJECflVE
The objective of this report is to examine the purpose, chemical nature, properties, and treatment methods for the broad range of chemicals used in offshore oil and gas production in the U.S. An important part of this examination will be a summa rization of the available data on acute aquatic toxici ty of those chemical constituents which are likely to end up in produced water being discharged to the ocean. Evaluation of environmental impact involves factors other than the nature and concentration of chemicals added in production operations and is beyond the scope of the study. The report is not primarily a literature search, but data references and illustrative articles and books are listed.
Considerable attention continues to be focused on the effects of offshore oil and gas producing operations on the marine environment. One aspect being examined is the discharge of produced water into the ocean. Removal of produced oil from water has long been recognized as an essential step with
strict standards having been established by the Environmental Protection Agency 1.2. The 1976 re
quirements for best practical technology (BPT) had been scheduled to expire on June 30, 1984 but were extended. Proposed revisions for best professional judgm ent/best available technology published for reviesv in 19852did not alter the reg u la tio n s on produced water discharge. Revised New7 Source Performance Standards (NSPS) were included in the revised National Pollutant Discharge Elimination System (NPDES) permits for the G ulf of Mexie03 issued in 1986. The regulations concerning oil co ntent o f the produced w ater were modified. Present EPA permits do not limit treating chemicals hi the produced water discharges. Governmental and intergovernmental agencies in other areas of the world (e.g. North Sea, Baltic Sea, M editerranean Sea, etc.) are considering preapproval of treating chemicals hi produced water discharges.
Constituents of produced water have previously been evaluated. Studies by Middleditchf Zimmer man and DeNagyS, the A.P16, the Offshore Opera tors Committee (OOC)q and othersS have consid ered various aspects of the treating chemicals in produced water streams. This study is an update of the 1985 OOC report, but expanded to include the broad range of chemicals used in offshore oil and gas production operations in the U.S.
Table 1 provides a concise overview of the off shore oil and gas industry in the V.S. All of these numbers were co n sid ered p relim in ary by the sources, subject to revision. The water production
data probably has the greatest uncertainty. Howev er, even these data are sufficiently accurate to give a good perspective of the industry. It is apparent that the Gulf of Mexico is the major offshore producing area by any of the statistics. Corresponding empha sis lias been placed on that area in this survey.
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SCOPE
Chemicals that may be used in routine offshore producing operations in the United States are in cluded in the scope of this report. For purposes of discussion, these chemicals have been arbitrarily placed into three groups. The production treating chemicals are those routinely added to the produced fluids or to seawater or other source water that is injected for waterflooding. These chemicals are added for various purposes (such as corrosion or scale inhibition). The gas processing chemicals discussed are those used for freeze point depression of gas hydrates or for dehydration of produced gas. Hydrogen sulfide and carbon dioxide are not nor mally removed from gas offshore and these sweeten ing chemicals and processes are not covered in this report. The third group consists of the stimulation and workover chemicals, including the acids and dense brines, along with their associated additives. Each o f these groups will be defined more fully in the following section and examined in greater detail isi later sections,
APPROACH
The objectives of this paper can only be met by utilizing a variety of sources of information. The nature o f the problems and control methods have been discussed in the technical literature from time to time but are constantly undergoing change as products and treatment methods are improved. Most of the production treating chemicals are highly complex mixtures rather than pure compounds and are usual!} c & y ered proprietary, with the best descriptions often being found in the patent litera ture. Actual treatment methods and concentrations vary substantially between operators, fields, and even wells within a field. Results of aquatic toxicity tests on the proprietary formulations are not rou tinely published or reported. On the other hand the gas treating chemicals are relatively pure chemical compounds. Aquatic toxicity of these chemicals are available in the literature for a few species. The acids are also relatively pure, but there is considera ble uncertainty in the concentration of unreacted acid remaining in the discharged fluids.
It was decided that the best overall results could be obtained using a three faceted approach: inter viewing chemical suppliers and operating companies plus a literature search.
Interview Chemical Suppliers. Discussions were held with technical specialists with three major suppliers of production treating chemicals. Compo sition of products, recommended application proce dures, water vs oil solubilities, and the aquatic toxici ty of products in the marine environm ent were
discussed. Further discussions were held with other suppliers with respect to aquatic toxicity informa tion. Their contributions and review of the paper have supported the general points or brought: out: additional information. Information on acids and workover fluids and additives was obtained from several suppliers. Aquatic toxicity data on the gas treating chemicals were obtained primarily from the literature, plus one supplier.
interview Operating Companies. Discussions were held with representatives of four major operating companies. Technical specialists concerned with environmental factors and engineers re,ponsible for operations and treatment of oil and gas production offshore were interviewed. Application, treatm ent and monitoring procedures for the treating chemi cals were discussed as well as methods of disposing of produced water, [n the 1985 survey these four companies operated 2223 (34%) of the 6525 wells in the OCS and state waters in the Gulf of Mexico (1983)12 and produced approximately 42% o f the liquid hydrocarbons <1984)13. jn 1988 these compa nies operated 3844 (36%) of the 10,614 wells and produced 36% of the liquid hydrocarbons and 49% of the produced water in the Gulf of Mexico. Two of the companies also have operations offshore California and Alaska. While this experience direct ly reflects actual operating practices for about one third of the US offshore operations, review of this paper by representatives from o th er operating companies has confirmed the general conclusions or brought out other practices.
LM&ratare Review, Computer searching of several data bases indicated that general searching for offshore pollution and toxicology was impractical due to the large num ber of references pertinent to oil spills and cleanup. The cited references resulted from more specific searches and/or were provided by the technical specialists in the various fields. Relatively little information on aquatic toxicity of production treating chemicals was found in the liter ature. Useful inform ation was found for the gas treating chemicals.
At the outset of the 1985 study, it was apparent that it would neither be feasible nor necessary to try to list the properties o f every production treating chemical sold for offshore use. That conclusion is still valid, including the gas processing, stimulation and workover fluids. Many of Ihe products within the various suppliers' lines for a specific purpose are similar (though not necessarily identical) and are built around the same basic chemical structures, [n some instances these generic chemical types are specific chemical compounds, e.g., methanol. The general consensus was that the study should focus on the relatively few generic chemical types o f materials
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that are used for the various purposes in offshore operations. Consequently, most of the discussions will be directed at generic chemical types on an individual basis. However, the aquatic toxicological studies were performed on specific product formula tions. These data are considered to be indicative of the properties of a particular generic type, but it should be recognized that the additives in a formula tion can have significant effects of their own.
DEFINITIONS, USAGE OF TERMS
PRODUCTION TREATING CHEMICA1S
Treatment Purpose. Any treating chemical used in
producing operations will be added for a specific
purpose, to reduce or mitigate some type of operat
ing problem. Unless that problem becomes signifi
cant, the chemical will not be added for obvious
economic as well as technical reasons. None o f the
operating companies interviewed encountered such
a broad range of problems that all types o f treating
chemicals listed below were necessary'. However, it
was often necessary' to add more than one treating
chemical in a system. Alternate technology can be
and often is used to control the various problems,
either alone or in conjunction with chemical treat
ments.
Chemical treatments are often the only effective
and / or economical method for some types of prob
lems. The following listing o f problem areas and
treating chemicals are generally accepted nomencla
ture. However, there are some variations between
companies and individuals. For example, 'water
clarifiers' was used for the reverse breakers,etc.
Each o f the se problem areas will be discussed
separately later.
Problem
Treating Chemical
Mineral scale deposits Equipment corrosion
Bacterial fouling Water-in-oil emulsion Oil-in-water emulsion
Solids removal Foaming, oil or water Paraffin deposits
Scale inhibitor Corrosion inhibitor Oxygen scavengers Biocide Emulsion breaker Reverse breaker Coagulants, flocculants Coagulants, flocculants Antifoam Paraffin inhibitor, or solvent.
Generic Chemical Types. Virtually all oilfield treat ing chemicals are complex mixtures manufactured from impure raw materials. There can be dozens of different molecular compounds of similar chemical and/or biological activity in a batch of reaction
product. These individual compounds will differ slightly in the number of carbon atoms or perhaps in branching in a long chain, factors which usually have little effect on the chemical activity. Minor amounts . of unreacted raw materials and reaction byproducts may also be present. Yet within this complexity, there is a central chemical functional group that imparts the primary properties of the specific mix ture. It is this central chemical functional group that will be used to define the generic c h em ica l type.
These generic chemical types are sub-classes within the chemical families used in the oilfield. Undoubt edly many other chemicals can contain this same chemical functional group, yet have totally different properties resulting from other parts of those molecules. Those chemicals are not used in the oilfield and are excluded from tins definition.
The specific mixture obtained from the reproduc ible but impure raw materials under carefully con trolled reaction conditions is often called a co m p o u n d for convenience. [Italic c o m p o u n d will be used to differentiate this usage from the norm al chemical definition.] For example, the simplest form o f a corrosion inhibitor c o m p o u n d may be
suitable in one type of production system (e.g., high gravity'- paraffin crude with low water content) but may be much less efficient at higher water content even in the same field. Thus, the c o m p o u n d will often be modified to change the phase distribution behavior somewhat to allow the c o m p o u n d to be 'effective over a broader range of water/ oil ratios. A common way to adjust this distribution is the reac-1
tion of the com pound with ethylene or propylene oxide. Ethylene oxide increases water solubility of a c o m p o u n d with low water solubility, Propylene oxide increases the hydrocarbon solubility o f a compound with low oil solubility. The oxides may be reacted into the com pound during its initial forma tion or by reaction with an intermediate compound.
Solubility is an extremely im portant factor in oilfield treating chemicals. In some cases the chemi cal can only work to fulfill its purpose at the inter face between two of the phases, i.e., the com pound must be surface active. This surface activity can often be enhanced by limiting the solubililty o f the com pound in the oil and in the water phases to the minimum that is still adequate to carry the co m p o u n d through the bulk fluids to the interface. Various ratios o f ethylene and propylene oxide are commonly used to accomplish tins goal, resulting in the desired oleophilic hydrophilic balance. These balancing factors are critical in emulsion breakers, for example; even though virtually ail of the emul sion breakers end up in the oil phase. The balance is not important for chemicals with other purposes, such as biocides and scale inhibitors, which have high solubilities in water and stay in the water phase.
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Formulations, Additives. The products sold by the chemical supply companies, which we will call formulations, usually contain materials other than the one compound. Any materials in the formula tion other than the com pounds for the primary purpose will be considered additives in this paper. As a minimum there will be a solvent, as most, of the compounds would be extremely viscous, solid, or even unstable at concentrations approaching 100%, The other materials may be different compounds for the same spcifi purpose, small amounts of com pounds for another purpose, other solvents, or other chemicals added for specific reasons to allow-' better achievement o f the primary purpose. For example, a surfactant may have a substantial beneficial effect on the efficiency o f a corrosion inhibitor compound hut will he considered an additive, it should he noted that most chemical suppliers consider the active content of a formulation to include everything except totally inert solvent(s). Important exceptions are tbe paraffin solvents, which are essentially 100% solvent compound plus a small amount of surfactant.
Tbe objective of tbe more detailed listing of tbe components in this paper is to allow estimation of tbe ranges of concentration of various compounds and additives in the treated fluids and in the water discharged to tbe ocean. In many instances, tbe formulation will include more than one compound from tbe same generic chemical type or compounds from two or more generic chemical types for the same purpose. This approach is often necessary to obtain optimum effectiveness, sucb as better emul sion breaker efficiency. For example, from a dozen intermediate compounds of three generic chemical types, a chemical supplier could prepare a hundred different fonnulations by blending different ratios of different compounds. Perhaps a tenth of these formulations have relatively broad application to many oilfields with the remainder being more or less formulated for one, two, or a lew specific oilfields.
Additives are placed in tbe formulation for spe cific purposes. Solvents, usually tbe major additive, are required to provide fluidity for tbe normally viscous compounds. Water is tbe obvious choice for water soluble com pounds, with refinery cuts of hydrocarbons (heavy aromatic naptha, etc.) used for oil soluble compounds. Methanol, isopropyl alcohol and ethylene glycol are other common additives used to provide cosotveneYJ freeze protection,: lower vis cosity and/ or pour point, etc. They may be essential to maintain a uniform, stable, and usable formula tion in the drum. Typically other additives function after the formulation is in tbe system. For example, addition o f a surfactant to a biocide or corrosion inhibitor allows better penetration through deposits. A small amount of emulsion breaker or antifoam may be added to a corrosion inhibitor to minimize adverse effects on tbe oil or gas separation process.
Multipurpose Formulations. Often there are two or three problem s in a producing system which require chemical treatment. Tbe operator may add three formulations independently, allowing each chemical to be optimized separately. Alternately, a single formulation containing all three chemicals for the three purposes may he added with a single pump. Both technical and economic factors must be
considered in choosing the best approach. In either approach, it is important that the compounds for tbe various purposes do not interfere with each other, by direct: reaction or otherwise. Tbe need for compati bility is even more stris.gg.st in multipurpose formu lations because the components must all be mutually soluble and non-reactive in the drum.
An example of a multipurpose formulation for treating water for injection could include an oxygen scavenger and a quaternary amine for corrosion control and a pbospbonate for scale control. The percent of each compound is likely to be lower than in tbe comparable single purpose formulation but
the overall treating concentration probably will be higher to achieve about tbe same concentration of active compound in the system.
The effect of tbe individual components of the multipurpose formulations on and in the environ ment will be similar to tbeir effect in single purpose formulations. Hence, these types of formulations will not be discussed separately. It is important to note again, however, that aquatic toxicity tests are normally conducted on actual formulations as sold to tbe operating companies. Tbe test results will reflect any interaction effects on the test species.
GAS PROCESSING CHEMICALS,
The high cost of space and operations on off
shore platforms greatly restricts the amount of gas
processing done offshore. Only processing or treat
ment. is done that is required to get tbe gas to shore
safely. It is sometimes necessary' to add a chemical
to reduce tbe freezing point of gas hydrates. In
some instances operators choose to remove virtually
all of the water from tbe gas on tbe platform before
sending it through tbe pipeline to shore.
.
Hydrate Inhibition Chemicals. Natural gas hy drates are ice-like solids consisting of a mixture o f water, hydrocarbon gas molecules, and particularly carbon dioxide and hydrogen sulfide gases if present. These solids can form in equipment under certain conditions, blocking or breaking; lines similar to frozen water pipes. However, they differ from ice in that they can form above 32 F, even above 80 F, depending on the gas composition and pressure. Solidification temperature increases with higher pressures, higher molecular weight hydrocarbon
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gases, and higher acid gas concentrations. Some liquid water must be present for hydrates to form. Condensed water vapor is usually sufficient, but produced formation brines can also result in hydrate formation. However, a high salt concentration hi produced water lowers the hydrate freezing point, similar to the way salt lowers the freezing point of water.
Freezeups can be prevented by adding chemicals when required. These chemicals are called hydrate inhibitors or freeze point depressants. The two most common chemicals are methanol and ethylene gly col. However, in many instances the gas remains too warm for hydrates to form and no treatm ent is required, in other instances, hydrates may form seasonally during cold weather, requiring continuous treatment only during part of the year. Batch treat ments may be required during shutdowns. In a few instances hydrates are a serious problem at all times. Continuous treatment may he required as part of a low temperature process to remove heavier hydro carbons from gas. In this instance or for large systems, the hydrate inhibitor may be recovered and recycled. For most cases it is not economical <o recover the chemical.
Dehydration Chemicals. A large fraction of the water vapor can be removed from natural gas by absorbing it into a solvent. Triethylene glycol is the most common chemical used in natural gas dehydra tion. The gas contacts the glycol in a tali absorption, column at high pressure and ambient temperature. The dry gas is sent to the pipeline with a water dew point typically below 20 F. The wet glycol is heated and sent to a low pressure desorber. The water is flashed off and the glycol is cooled and pumped back to the absorption column. Some makeup glycol has to be added to compensate for volatility and spray losses, but there is no continuous discharge. Side stream filtration and purification allow the glycol charge to be regenerated almost indefinitely. Occa sionally it may be necessary to discard a batch of glycol because of severe contamination or degrada tion,
% 1Ml i.tlU lN WORKOVER CHEMICALS
Acids and Additives. During the life of a producing or injection well it may become necessary- to stimu late flow by removing deposited accumulations from the wellbore, perforations, and formation. The accumulations may be due to scale deposits of calci um carbonate or various corrosion 'products such as iron sulfide, oxide or carbonates. These solids can partially block the flow paths through the formation rock. These materials are all soluble in hydrochloric acid, the most commonly used oilfield acid. Since
calcium carbonate is also a common companeol of reservoir rock, the acid may also increase the size of the original flow channels. Acidizing is also fre quently used during the initial completion, o f the well if the formation composition and permeability are appropriate. Fm& sand or clay particles may migrate through the formation until they lodge at some point, also blocking flow. A mixture of hydrochloric acid and hydrofluoric acid (mud acid) is used to dissolve these solids. Other acids are sometimes used.
There is always at least one additive used in an acid stimulation job, the corrosion inhibitor. All of these acids are severely corrosive to the steels used in wells, piping and production equipment. Other chemicals may also be dissolved in the acid or in fluids used in conjunction with the acid on the stimu lation job. Surfactants are often used, especially if the oil gravity is low or paraffin deposits are likely. Paraffin solvents may be required in severe cases. Clay stabilizers are sometimes required, as are iron sequestrants or scale inhibitors. Chemicals to prevent emulsification of oil and acid or sludging of the oil may be necessary.
Workover Fluids and Additives. Brines are often used during workovers and completion operations. The density of the brine must be high enough for the hydrostatic head of the fluid column to contain the formation pressure. Clear brines are preferred to muds so that the solid particles will not cause perm anent plugging of the formation around the wellbore. Seawater (8.4 lb/ gal) is sometimes used for flushing or for low- pressure formations. Densi ties to 10 lb/gal are available with sodium chloride brines, and to about 11.5 Iblgal with calcium chlo ride. These systems provide adequate density for most wells (perhaps 95% or more). Mixtures of calcium chloride and calcium bromide extend the range to about 15.4 Iblgal. Calcium bromide and zinc bromide mixtures up to 19 Iblgal are available for those last few wells with extremely high pres sures,
A wide range of additives can be used, depending on the operation. Untreated seawater may be used to flush, the bulk of the fluid from the tubingl casing annulus when the well is reopened. Corrosion inhib itors and bactericides may be added to brines that are to be left in the annulus as packer fluids. Thick ening agents and dissolvable particles (e.g,. salt, calcium carbonate) may be added to prevent exces sive volumes of brine from draining into the forma tion during the workover. Thickeners may also be used to help suspend sand being pumped into the well during gravel packing. These sand grains are too large to enter the formation but restrain UDconsolidated formation sand during production.
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T Y P IC A L S Y S T E M S
PRODUCTION PROCESS FLOW SCHEMES
The process flow scheme, equipment, and oper ating conditions can and do vary widely, depending on the properties o f the hydrocarbon fluids and the size and producing rate of the reservoir. While no one system is truly typical, there are similarities. The highly simplified diagram in Figure 1 shows a scheme with many of the components that are typi cal of offshore oil production systems, although most systems will not contain all of the equipment shown. This figure is intended to provide a general guide to terminology used in the paper as w'ell as illustrate some of the system factors which affect the chemical treatments and disposal of produced water.
Several producing wells are connected to produc tion manifolds which carry the produced fluids to the appropriate separators. Those wells with the highest pressure are routed through the high pressure manifold to the high pressure separator (e.g., 1500 psig). Most o f the gas is separated and the com bined oil and water stream is sent to the intermedi ate pressure separator. Wells with intermediate pressure flow-' through the intermediate manifold directly to the intermediate separator (e.g., 500 psi). Much of the remaining dissolved gas is flashed as it enters this separator. The combined oil and water then flow to the low pressure separator (e.g., 50 psig), often called a free water knock out (FWKO). Most o f the rem aining gas is flashed and the free w ater is separated. The oil, still containing a few percent of water as a dispersed emulsion, flows to the bulk oil treater (e.g., !.5~3flfssg) where the water content is reduced to sales/pipeline specification. A high pressure separator may not be required in all fields, with the manifolds then connecting to the intermediate and FWKO respectively. Later in the life o f a field, the operating pressures o f the high and/or intermediate pressure separators may be reduced to maintain the desired deliverability from the wells. Electrostatic grids may be incorporated in the bulk oil treater to improve the removal of water from the oil. Occasionally, the oil is sent to the pipeline directly from the bulk oil treater (with or without pumping) while in other instances an atmospheric pressure tank is used to release more gas (with pumping obviously being required).
The high pressure gas may flow directly through dehydration facilities into a pipeline to shore. Compression is required for the intermediate and low pressure gas aad must often be added for the high pressure gas as the field gets older and the pressure decreases. Some of the gas is usually used as fuel on the platform and/or to gas lift low pres sure oil wells. Glycol dehydration is the most common method for removing water from the gas.
The gas flow's upwards through a tower, contacting a falling stream of dry' glycol on trays. The water in the gas is absorbed into the glycol, usually triethyl ene glycol (TEG). The w?et TEG is heated and sent to a second low pressure tower. The water is flashed off and the TEG is cooled and pumped back to the contactor tower. The TEG is not consumed, but is continuously recycled in a closed loop.
Produced water is collected from the free water knock out (sometimes from the high pressure sepa rator and any atmospheric pressure tanks) and sent to the produced w-ater treating system. The first vessel in the system is often a surge/skim tank co collect free oil and smooth out flow variations. This tank may allow discharge specifications to be met in some instances, especially with very light oils or condensate. Further processing equipment varies, e.g., a corrugated plate in terceptor (CPI) unit
and/or a multistage flotation cell are sometimes used. This equipment will reduce suspended solids and oil concentration to low-' levels to meet require ments but have essentially no effect on water soluble materials. Offshore, produced water is discharged to the sea after this treatmenr.
Most production systems will include a test separator(s). Since measurement of two or three phase flow' is extremely difficult, manifolding and valving is included so that production from any one well can be isolated to the test separator(s) and each phase measured separately. The fluids are then
recombined. Even this simplified scheme can have several
variations, depending on the nature of the field. All of the wells may be on the same platform (or bridgeconnected) with the processing equipment. In some cases, however, the design concept calls for produc tion from several multi-well platforms to be sent to a central processing complex, with only a test separa tor on the wellhead platforms. This situation has also developed late in the life of some fields when production rates become too low to justify operating costs for the separation equipment for an outlying platform. The equipment was bypassed and the fluids were sent to the central facilities. In other instances, the design calls for the water to be sent to shore along with the oil, with final oil-water separa tion performed at the shore facility. This approach eliminates the platform space and weight require ments for the water treating and oil treating equip ment but requires additional pipeline capacity. Final ly, some recent systems for very deep water have used a captive tanker to provide processing space and interim storage, with il shipment to market via shuttle tanker. This la tter approach is not yet common and has no additional impact on produced water disposal. The first three do have a significant impact on the disposal of treated produced water and will be discussed in more detail.
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Figure 1. Simplified typical process diagram for an offshore platform in an oilfield.
Processing of gas wells (from gas fields or gas wells in an oil field) is similar yet different. Most of the gas wells operated by the companies surveyed produce relatively little liquid. The entrained liquids are removed in separators. If ali welis do not pro duce at pressures above pipeline pressure, an in termediate separator and gas compressors are re quired. The gas may be dehydrated in a glycol unit and sold to a gas transmission pipeline compam a! the platform. The liquids (light oil isdr-w. 'iqor, condensate, and small amounts of wafer t aie some times processed and sent to shore separately from either the gas or oil from the area, depending on technical and contractual lactors. In other instances the gas, oil and produced water are sent to shore in the same pipeline for all processing. In the 1985
survey one o perator noted that only one of their twenty-three gas platforms had a waiter discharge. The other platforms had no water production or the water went to shore with the hydrocarbon conden sate to three receiving plants, which injected a total of about 5500 BPO water into disposal wells. On the other hand, another operator had produced waiter
discharges on all twenty-six of its gas platforms. These situations have not changed substantially in the intervening four years,
SINGLE COMPLETE PLATFORM
If the field is geographically compact, it may be feasible to drill all of the wells from one platform. Locating the processing equipment on the same or a bridge-connected platform allows all operations to be done with minimal boat support, etc. Usually there will be ten or more producing wells on a plat form. Platforms in deeper water are generally more expensive and have more producing wells, with more than fifty being provided for in some instances. Any batch treatment or slug treatment of the production from any one well will be diluted with the production from the remaining wells, reducing the effective concentration of the treating chemical in the pro duced fluids flowing to the separators and, hence, in the discharged water. All or even most of the wells could not be treated sim ultaneously because o f excessive pump and/or manpower requirements and
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the adverse effects on overall production rates. Even if these restraints were not present, all wells would not be treated simultaneously because of the increased risk of high concentrations of treating chemicals causing an upset o f the separation equip, ment.
In some circumstances, outlying single wells are brought directly to the processing platform. This approach was more common earlier in shallow water with shallow reservoirs. Directional drilling could not reach the edge of the reservoir and free standing wellheads were feasible. Subsea completions are notv feasible for deeper water. In either case, the concentration of treating chemical fiOlfl any kind of batch- or squeeze-type treatment will still be diluted in the processing equipment by the production from the remaining wells. A separate line may be re quired to send hydrate inhibitor to remote wells continuously or intermittently to prevent hydrate plugging.
CENTRALIZED PROCESSING PLATFORM
Large fields may require several drilling/production platforms to provide adequate access to all areas of the reservoir. Processing equipment on these platforms can range from a high pressure test separator through a complete processing system. In most such fields, however, it has been common for most of the processing to take place on the produc tion platform, essentially the same as the previously described system. As some platforms in a field approach their economic Barit, equipment on outly ing platforms is being bypassed and production sent to a central platform for processing and for shipping of the oil and gas to shore. The produced water is also treated and discharged at this central facility.
In this configuration, a high concentration of treating chemical from anyone well will not only be diluted with the production from other wells on that platform but also by the production from other platforms. High concentrations of corrosion inhibi tor or biocide used in treating gathering lines from an outlying platform will be diluted by production from other platforms. Multiple platforms make it even less likely that a high percentage of the wells sending water to a common discharge could undergo batch or squeeze treatments simultaneously.
ONSHORE PROCESSING
There are several systems where all or pan o f the processing is performed after the produced fluids are brought to shore. The most common scheme is to separate the gas offshore and send it to shore through a different pipeline. Oil and produced water are not separated offshore but flow to shore in a common pipeline. Chemical concentrations in the
liquids resulting from well treatm ents would be diluted by the total production. One such system has over 150 producing wells, which would dilute chemicals used in anyone well by about two orders of magnitude. For example, a concentration of 1500 ppm corrosion inhibitor at the w ellhead after a squeeze treatment might be reduced to 10-15 ppm by the time it is discharged from the central facili ties. Even batch treatm ent o f equipment on any platform would be diluted by at least one order of magnitude.
Sending the oil and water to shore increases the risk o f problem s in the pipelines. Pigs are sent through the lines to prevent accumulation of solids, paraffin, or corrosion product in the lines, all of which could contribute to pitting-type corrosion as well as reduce throughput capacity. Chemical treatment Is used to minimize corrosion. In one system, a dose ofbiocide is used behind the pig to kill sulfate reducing bacteria, with a subsequent slug of corrosion inhibitor supplementing a low continu ous treatment. The batch treatment of chemicals are diluted by a factor o f five to ten as it moves through the water treating equipment on shore.
GAS PROCESSING
It is sometimes necessary to add a hydrate inhibitor to prevent solid natural gas hydrates from forming in high pressure gas lines. The ice-like solids can form at tem peratures well above 32F. The inhibitor, normally methanol, is usually added continuously at the wellhead to prevent the hydrate from forming in the system until the water can be removed from the gas stream. Addition may be required only in the winter when temperatures of air and seawater are lower.
Dehydration is normally the only gas processing performed offshore. Primarily this choice is necessi tated by the high cost of platform space and much higher operating costs than onshore facilities. Dehydration is desirable to reduce the risk of corro sion and hydrate formation in the pipelines to shore. However, in some instances untreated gas is sent to shore, with corrosion and hydrate inhibitors added to prevent problems. However, there is at least one offshore location where gas is sweetened (H2S and 0 2 removed).
Glycol dehydration using triethylene glycol (TEG) is the only process used to remove water from gas in offshore operations (Figure 2). In some systems the hot produced gas will be cooled prior to entering the glycol unit. Some o f the water will be condensed and then separated in the inlet knockout vessel, reducing the size of the glycol facilities. The knockout vessel greatly reduces the risk, of any produced liquids being carried into the contactor, where it could contam inate the TEG. The gas
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.**AA'iR
DRY GAS
GLYCOL DEHYDRAT I ON SYSTEM
-Yj `f
r
-4 r^f &* ;- 0 -!
SURGE
L- - , !
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enters the bottom of the tall contactor tower. As it flows upwards through a series of trays the gas is intimately mixed with a falling stream o f TEG. Some water is absorbed into the TEG on each tray and the gas becomes progressively drier. The gas exiting the top of the contactor has been dried suffi ciently so that liquid water will not condense as the gas flows to shore.
The TEG leaving the bottom of the contactor is rich in water and saturated with natural gas. The TEG flows through a heat exchanger, flash tank, and filter before it enters the regenerator tower. The water is boiled from the TEG in the regenerator, reducing the water content to 0.2% or less. Heat is normally supplied from waste heat recovery units on offshore platforms to eliminate the safety risk of direct fired heaters. The hot, dry TEG flows back through the heat exchanger to a surge tank. A recy cle pump sends the TEG through a cooler back to the top of the contactor.
In addition to providing consistently dry gas economically, a key factor in the acceptance of this process is the low' consumption rate for the TEG. Very little TEG is lost with the dry gas flowing to the pipeline. An entrainment separator minimizes spray carryover and the TEG is used because of its low vapor pressure. Similarly, vary little TEG is lost in the regenerator overhead.
WATERFLOODING
W aterfloods are not as common in offshore operations as in US onshore operations but neither are they unusual. The water comes from source wells in many instances, but seawater is also use si Source wells completed in non-hydrocarbon aquifers are desirable because very little surface equipment and treatment is required. However the aquifer must be sufficiently large to provide all of the re quired water and should be highly permeable to minimize the number of source wells. Whenever possible, a source w ater will be selected that is chemically compatible with the formation water in the oil zaneCs), minimizing scaling problems in the producing wells. Since high concentrations of barium, strontium and calcium are frequently present in produced water from the Gulf of Mexico and offshore California, source w aters with low sulfate ion concentrations are preferable. The advantages of source wells must be balanced against their cost, uncertainty in their delivery' capacity, and ongoing lifting costs.
Seawater is an obvious water soar* for water flooding, with unlimited capacity. More processing equipment and chemicals are needed but well costs are eliminated and injection costs may be lower. Corrosion control and prevention of injection well
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plugging are the primary process objectives. Rigor ous oxygen removal (mechanical deaeration by gas stripping followed by chemical oxygen scavenging) provides corrosion protection for most of the system. Corrosion resistant materials are used in that por tion of the system handling aerated seaw ater. Removal of suspended solids by filtration is usually required, but cartridge filters are often adequate in river outfalls or deep water remote from shore where suspended solids concentration may be less than 1 mgj L. Scale inhibition is usually not re quired. Biological control to prevent corrosion and fouling o f the equipm ent and injection wells is accomplished by a combination of chlorination, deaeration, and biocide treatment. Essentially all of the processed seawater is injected into the oil reser voir. However, seawater is not widely used in the Gulf of Mexico and offshore California because of probable severe scaling in producing wells. The high
c o n c e n tra tio n o f sulfate in se a w a te r e n te rin g the
wellbore via more permeable reservoir streaks will re a c t w ith barium, s tr o n tiu m o r calciu m e n te r in g from less permeable streaks.
In the G ulf o f Mexico w aterflooding is not normally required. Even when it is needed, pro duced water is not normally used for waterflooding offshore for three main reasons:
1 In the early life of the field when water injection can usually achieve maximum recovery, there is often little or no produced water to reinject; hence, an alternate source must be developed,
2 Later in the life when quantities o f produced water become more substantial, it is very' expen sive to retro fit dr add additional processing equipment. Mixing of produced water with any original supply water greatly increases the risk that scale will be formed and plug the injection wells.
3 Any dispersed oil interferes with solids removal processes, making it very difficult and expensive to reach low concentrations of either material. Concentrations of 5 ppm or less solids and oil are often necessary to avoid wellbore plugging.
STIMULATION AND WORKOVERS
Stim ulation and workover operations entail several kinds of activities designed to maintain or increase production from an existing producing zone in an existing well. Recompletions to a new zone normally involve drilling operations and are beyond the scope o f this report. This discussion will be directed to those operations and practices related to fluids and byproducts that might end up in the water streams. For clarification of the scope of this report, it will helpful to describe a "typical" scenario for com pleting an offshore well. The discussion is
necessarily general, with specific practices varying with the individual wells and areas. For example, the gen eral practices d escribed by W edell4 are representative of practices for most wells in the Cook Inlet of Alaska. Higher density fluids must be used in geopressured gas wells in the Gulf of Mexi co. Otherwise, many of his comments are equally applicable to the Gulf of Mexico.
Figure 3 is a simplified diagram o f a typical offshore producing well. After tbe well is drilled to total depth, the production casing string is cemented in place. Excess cement is drilled out and tbe inside of the casing cleaned with casing scrapers, etc. Completion begins with the drilling mud and solid debris with seawater andj or dense brine, which is called the completion fluid. The completion fluid is often circulated and filtered for many passes until the fluid is free of solids. It is very' desirable that the com pletion fluid be very' clean, as solid particles could plug the formation around the wellbore. Tbe hydrostatic head of this completion fluid must be high enough to contain the formation pressure when perforating guns blow boles in the casing into the producing zone (A). This requirement often neces sitates using a dense brine.
If the producing formation is unconsolidated, as is common in the Gulf of Mexico and sometimes off California, it is necessary to control sand production. A gravel pack is a very common practice for this purpose. A sl urry of coarse grained sand or manu factured ceramic or synthetic plastic granules is pumped down the well and into the perforations. The -packer' at tbe bottom of the tubing string is then set. isolating the tubing-casing annulus from the
producing zone (B). Several /.ones may be perforat ed and gravel packed during the completion opera tions to facilitate changing to another zone after tbe initial zone is depleted. With suitable downhole
hardware, it is possible to displace tbe completion fluid from the annulus with another fluid. The fluid remaining in the annulus during production is called the packer fluid and mayor may not be the same as the completion fluid.
After the well is completed it may be desirable to stimulate the well so that the production rate will be higher. Stimulation is normally accomplished off shore by pumping acid into the well. The acid dis solves solids and opens or increases the size of flow
paths. Hydraulic fracturing, another type of stimula tion, is extremely rare in offshore operations. The unconsolidated sands in the Gulf of Mexico are not amenable to this type of stimulation. The enormous logistic problems of assembling the pumping equip ment and supplies usually preclude it in other off shore areas as well.
The brines used as completion or packer fluids are seawater, sodium chloride, calcium chLoride, calcium bromide, zinc bromide, and mixtures of
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(A )
.....
ssi *
x. ,s<
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v
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.pr Tie**TM. 4-^iw. , '
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s T i Il 5 w % - s ^ ^ P . S 5. v _ s - S
COMPLETION FLUID
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K;i:;f>p- ;|#' f-lc"2^s . PRODUC INC,
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P E R F O R A T IO N S GRAVEL PACKIN
C A S I N S ............
e u . co P t.e it3 N ano pr o d u c t io n
Figure 3, Simplified well diagram illustrating components in well completion operations.
these suits. [0 c e rta in circum stances, potassium
chloride or am m onium chloride may also be added
to the above. Zinc bromide .is almost always used m
conjunction with calcium brom ide and .is rarely left
in the annulus as a packer fluid, it is more corrosive
and expensive and is usually circ u lated o u t and
returned to shore for later use in other high pressure
wells.
"
A fter the well is producing, further stim ulation
operations may be as simple as jetting accum ulated
sand from a producing well, but m ore com m only
involve pum ping acid into the producing zone to
dissolve accum ulated solids. Workover operations
may re q u ire pulling the tubing string to rep lace
defective downhole com ponents or perform ing a
new full gravel pack to control sand production. la
many eases, however, several operations will be
done, especially if it is necessary to bring a pulling
unit to the platform . The costs of the unit are so
high that any an ticip ated preventive work will be
performed while the pulling unit .is on location.
The acids used for stim ulation are prim arily
hydrochloric and hydrofluoric acids. The hydro
chloric acid dissolves most corrosion products and
calcium carbonate, while the hydrofluoric acid can dissolve fine particles o f clay and sand. A pre-flush and post-flush o f ammonium chloride is often used to prevent precipitation o f calcium fluoride. An a d d stimulation is often an integral part o f a sand control job, to insure maximum production rate. The larger sand grains in the gravel pack are usually pum ped down dispersed in thickened brine
F or many workovers it will be necessary for the fluid m the wellbore to be dense enough to contain form ation pressure, i.e., kill the well. The sam e brines listed above are used for this purpose. However, it is im portant to note that as the forma tion'pressure decreases during the life o f the zone, the req u ired density will decrease. It is possible to pump down a "pill" o f thickened satu ra te d sodium chloride brine containing a dispersion of solid sodium chloride particles. The solid salt will prevent the dense brine from seeping out. into the formation during the w orkover, but will readily dissolve in form ation w ater when the well is re tu rn e d to pro duction. Fine particles o f calcium carbonate are also used, but require an acid wash to unblock th e Row channels.
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Mechanical workovers include such things as pulling the tttbiag to replace a leaking joint, down hole components such as gas lift mandrels, or a leaking packer. In some instances gas lift valves, subsurface safety valves, and other small items may be retrieved through the wellhead with a wireline unit, avoiding the necessity o f killing the well and pulling the tubing.
PRODUCTION TREAT! G C H EM IC A L S
Chemicals can be and are used for a wide variety of purposes in oil and gas production. It cannot be overemphasized, however, that these uses are normally in response to actual problems. The direct cost o f the chemical is only a part of the cost of using them, Purchase of injection equipment, trans portation, contracting for application services, proportional cost of employee time for application and monitoring, and value of deferred or lost pro duction for some types of treatments are all major parts of the real cost of chemical treatments. The cost of the space for pumps and chemical storage may be the largest single factor on some offshore platforms. Treatments are not normally initiated unless the costs or risks for the problem are signifi cant or expected to become significant. Because conditions are continually changing during the life of a field, any treatments should be frequently reviewed to determine if they are necessary and cost effective. Treatments will be modified or even discontinued to keep overall costs and problems at a minimum.
All types of chemicals used in treating offshore production are discussed in the following sections. 'None of the operators interviewed used all these chemicals in their operations, much less all on one platform or system. On the contrary, addition of only one or two chemicals on anyone platform or in a system is far more commoo, with many instances where no treatment is performed on a platform.
SCALE INHIBITORS
Prnblem Description, Deposition of inorganic compounds from the produced water associated with hydrocarbon production can have a severe impact on operations. These deposits can actually seal off a producing form ation and stop all production. Deposition can occur within the pores in the forma tion itself, in the perforations, or in the tubing. D eposits in su rface flow lines can reduce the throughput: capacity or require higher inlet operating pressures to maintain the same throughput. Depos its on healer tubes reduce heat transfer, requiring higher fuel consumption and increasing the risk of corrosion failure o f the tube element itself and a
resulting fire. D ep o sits in valves can p rev en t movement or complete closure which can interfere with proper control or cause major equipment fail ure. Such valve failures would pose a serious risk to personnel or cause oil spills. Clearly it is necessary to control scale deposition for safe and proper offshore operations.
Fortunately, there are only a few common types
of scale deposits in oilfield operations. The type of scale (if any) found in a particular field will depend on the composition of the water(s) and the system characteristics. Calcium carbonate is probably the most common scale. It is less soluble as the pres sure decreases, even above the bubble point, if the pressure drops below the bubble point, some C02 flashes off, increasing the pH and causing more
deposition. Mixing of incompatible waters (one high in calcium, the other high in carbonate) causes deposition. In addition, increasing the temperature causes calcium carbonate to deposit. Fortunately, calcium carbonate is very soluble at low pH and can be dissolved by acidizing.
Calcium sulfate (gypsum) will deposit when the pressure decreases or Incompatible waters are
mixed. It has a maximum solubility around 105F, with deposition possible at higher or lower tempera
tures. Strontium sulfate is most commonly formed when incompatible waters are mixed. The solubility
decreases at higher temperatures and lower pres sures. Barium sulfate also commonly occurs if incompatible waters are mixed. It has a lower solu bility at lower temperatures and pressures. Deposi tion can occur as temperature and pressure decrease when the water flows up the tubing.
The actual solubility o f any o f Ihfi&e scale compounds is a complex function of temperature, salinity, pressure and composition. Fortunately, reasonably good solubility calculation methods are available: calcium c a r b o n a t e 16, calcium sulfate (gypsum)]?, barium sulfate A and strontium sul
fate19. These methods suggest whether scale deposi tion is possible and the most likely places where deposits will form. These calculation methods are based on experimental data showing the effect of temperature, pressure, and concentration o f dis solved salts and gases in the water. Coupled with experience, the calculation methods allow many scale problems to be anticipated. The iron com
pounds (iron carbonate, iron sulfide, and iron oxide) are usually related to corrosion problems and are controlled with corrosion inhibitors or other corro sion control methods.
In most instances, nothing can be done to modify the conditions causing scale deposition. The scale compounds o f interest are all less soluble at lower pressures. A water saturated with calcium sulfate or
calcium carbonate in the reservoir can start to deposit scale in the formation as the pressure de-
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creases20. A water saturated with barium sulfate will start to deposit scale as it cools off]8. 'However, there are occasions when system design and operat ing procedures can reduce or even eliminate scale problems. As an example, scale problems associated with incompatible waters (e.g., one containing high barium and a second with high sulfate concentra tions) can sometimes he avoided by using subsurface
supply wells instead o f seawater. Fortunately, most produced -waters on anyone platform in the Gulf of Mexico are compatible. Electrostatic separators can be used to aid in separation of water from oil, elimi nating the hot heater tube surface where scaling could occur. Nevertheless, chemical treatment can he required to control scaling problems.
Chemical Description. All of the chemicals used to control scale deposition in oil and gas production systems work by interfering with crystal growth. The two most, commonly used compounds are based on organic phosphorus chemistry, with a polymer type comprising the remainder, inorganic phosphate inhibitors are no longer used in offshore operations. Treating concentrations for ail these types are about the same, with 1-10 ppm usually providing satisfacto ry scaie control. Higher concentrations may be required for more severe scaling tendencies. Higher concentrations may be encountered in produced water after a squeeze treatment. However, squeeze treatments are unusual in U.S. offshore operations
except for the few seawater floods. Phosphate esters. This generic chemical type
contains the phosphate esler functional group, the carbon-oxy gen-phosphorus linkage:
II II
R -N -C -C --0 - P ( 0 H ) 2
! H H
I
R1
0
Typical phosphate structure
A variety of raw materials can be reacted with the phosphate but most compounds involve an amine nitrogen. The exam pie show n is a disuhstituted ethanolamine. The selection of the raw material is based on the final effectiveness o f the compound as a scale inhibitor and the cost of the raw material. The R groups may be identical or different. In many instances, the R groups will contain functional groups such as amine or alcohol which contribute to high water solubility. The acid groups are normally partially neutralized with caustic, ammonium hy droxide, or other inorganic base. These materials can not normally be used above 200F because the ester linkage hydrolyzes at high temperatures and the hydrolysis products are poor scale inhibitors.
Phosphonates. The key functional group in this generic type is the direct carbon-phosphorus bond. Almost all o f the raw m aterials contain amine groups, with the generalized structure being similar to that shown below :
C H 2-P (O H )2
ill
O
H H
T s T '----------- + - c - c - i s r
H H
CT12-P(OH)2 (OH)2P-CH2
H
C -P ((.)H )2
H I O
O
0
x
Generalized phosphonate structure
Carlberg's21 studies on ethylene diam ine tetra (methylene phosphonic acid), the active ingredient in several commercial scale inhibitors, indicate farther that multiple active chemical functional groups can be present within the same compound.
Polymers. Acrylic acid polymers and/or copoly mers are the normal base m aterials. The com pounds have the generalized structure shown, where the Rs may till be different or identical. All the Rs
are H in acrylic acid polymers.
R
R2
I
I
H 2 - e - + -+- C112 -C
0=C0R1 x
OCOR3 y
Substituted acrylic acid copolymer
The scale inhibitor compounds are usually not modified by oxyalkylation, etc. as is common with
emulsion breakers, as will be seen later. Formulations can contain 10-50% active com
pound of one of these three generic chemical types in a water solvent. Ethylene glycol or methanol can be present from 0-20% to reduce the viscosity and/or to prevent freezing. There are normally no other additives. Some un reacted phosphoric and/or hydrochloric add may be present also.
Solubility. Alt of the scale inhibitor compounds and additives are highly water soluble, in excess of 30 40%. The solubility or dispersibility in oil is ex tremely low. It is reasonable to expect that all of the
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formulation produced from a well or added to the fluids on the surface will be separated from the oil in the separators or slrim tanks and be retained in the aqueous phase except for Ihm contained in the small amount o f water emulsified in the oil phase.
Application. To work properly, scale inhibitor must be present in the water at effective concentrations when scale first starts to form. The minimum effec tive concentration is usually in the 3-10 ppm range but can be higher in severe eases. Only two applica tion methods are used offshore - continuous injec tion or squeeze treatments. The scale inhibitor remains with the water phase in both methods.
In co.ntin.uous injection, chemical is added with a pump at a constant dosage rate to achieve the de sired concentration. In some instances., the chemical will be pumped down a small diameter capillary or macaroni tubing string to the bottom of the well to prevent sealing in the producing tubing as well as the surface equipment. Often, the scale inhibitor is added just upstream of the choke at the wellhead, w hich is especially effective against the most common scale, calcium carbonate. Alternately, the inhibitor will be added on the manifold if the prob lem is due to mixing of waters. Only the surface equipment is protected in the latter two methods but that is often the only problem area.
Squeeze treatm ents must be used when scale deposition is occurring in the producing formation,
in perforations, in the wellbore below the tubing, or in the producing tubing string (when a macaroni string is not available). In squeeze treatments, a relatively large volume of scale inhibitor (diluted in water to 2-10%) is pumped into the formation, followed by more excess water. Some of the inhibi tor is absorbed onto the formation surface and/or otherwise retained in the pores within the formation When the well is returned to sendee, a part of the inhibitor is produced back quickly within a few days as a slug. The remainder is produced back slowly at much lower concentrations over a period ranging from two to twelve months, providing protection until the concentration drops to the 3-10 ppm minimom and the well is resqueezed.
Scaling problems bave not been widespread in offshore operations for the operators interviewed, with most systems not requiring treatment. Fortu nately, downhole scale problems are rare. Squeeze treatments are not conimOD, with tbe operators having much concern about formation damage in the relatively unconsolidated Miocene bands in tbe Gulf of Mexico. One of the squeeze applications was in a gas well producing considerable formation water (an unusual situation). Normally, continuous treatment on tbe surface was only used in tbe water processing
equipm ent in tbose cases where the scaling was serious enough to warrant continuous treatment.
Periodic (e.g., quartedy) removal of scale from flota tion equipment was used in several instances.
CORROSION INHIBITORS
Problem Description. Control of corrosion is one of the most serious problems in offshore operations. Coatings, cathodic protection, and materials selec tion are used to control external corrosion, with corrosion inhibitors supplementing these same three methods for internal corrosion. All of the corrosion inhibitors used in treating produced fluids are organ ic compounds that form protective layers on the metal surface.
The use o f various grades o f low alloy carbon steel as the material of construction is an economic necessity for most of the production system. Differ ent grades would be selected for fabricating vessels, tanks, or piping on the platform, with still other grades (primarily differing in strength level) being selected for pipeline and downhole tubular goods. All of these steels bave very similar corrosion resist ance with tbe exception that higher strength downbole tubular goods (and other high strength materi als) can be susceptible to sulfide stress cracking. Small accessories such as instrum ents, valves, pumps, etc. are often fabricated from high alloys or bave bigh alloy trim to prevent corrosion o f critical surfaces wbich would impair the function. Vessels, tanks, flowlines, and downhole tubular goods can be coated to reduce the risk of rupture due to excessive metal loss over large areas. However, there is still concern about corrosion at defects in the coatings.
The corrosivity of produced fluids is usually related to dissolved gases - oxygen, hydrogen sulfide, and carbon dioxide. Produced fluids from the wells normally do not contain oxygen and every effort, is made to keep air out of the treating equipment. Fortunately, tbe hydrogen sulfide content of pro duced fluids in most offshore fields is usually very low and H2S is not a significant factor, providing that bacterial generation of H2S is minimized. Production from recent developments in the Mobile Bay area does contain considerable hydrogen sul fide, with essentially all processing being perforated onshore. Corrosion control and monitoring are vesv important design aspects of those systems. Carbon dioxide is the most commoo and serious corrodent, although naturally occurring organic acids can be a contributing faclOr.
The experience of the operators Interviewed Is that corrosion bas been much less severe in oil wells (ban in gas wells probably due to tbe oil phase providing an inherent protective oily film on tbe steel. In both eases, corrosion is more likely io become a problem when water production increases.
Even if corrosion resistant alloys and/or coatings are utilized in parts of a system, corrosion inhibitors
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may still be required to protect some bare steel areas. By temporarily adsorbing ontO the surface, the inhibitor can drastically reduce the corrosion rate, often by more than 90%. Hence, corrosion
ksMbttors me widely used in preventing or minimiz ing internal corrosion in offshore production sys tems.
Chemical Description. The corrosion inhibitors tised in petroleum production operations generally contain nitrogen in the key functional group. The nitrogen-containing material is usually reacted with a carboxylic acid under different conditions to form a compound with properties optimized for various types of applications. While the carboxylic acid may have a low molecular weight for greater water solu
bility (e.g., acetic, propionic, or maleic), it is more frequently a complex mixture of higher molecular weight m aterials. Tall oil mixtures of variable compositions are often used, because of superior corrosion inhibido properties and low raw material cost. Table 2, from an NACE publication2 gives an example of the complexity of a typical carboxylic half of inhibitor compounds, with the nitrogen-containing
half potentially having comparable complexity. it is readily apparent that the corrosion inhibitor
compounds are extremely complex mixtures. Fur ther complicating the situadoo, different compounds can often be formed from the same raw materials by
varying the reacting conditions, quite distinct from modifications such as ethoxylation. Testing of spe-' cie compounds and formulations is normally re
quired to define inhibition properties but general trends with m olecular structures can be made.
Similarly toxicity testing is likewise normally con ducted on defined compounds as intermediates or on final formulations.
Oilfield inhibitors can be grouped in several different fashions but a common generic chemical classification similar to Bregman's23.24 is useful for
our purposes. Amidesllmida zoline s. Perhaps the single HlOst
common generic cbemical type used in the petrole um industry is formed by condensing a long chain iaHy acid with a primary amine, often a diamine or polyamine. The fatty acid is often derived from raw
or refined tall oil and is composed primarily of fatty and resin acids as shown in Table 2. As an example, consider that the reacting amine is a substituted
H
H
I
O
NH2
H R -C -N
!! ) CH2 N-CH
Ri.
Amide
Imidazoline
(R i}ethylene diamine. The amide would be formed under less severe conditions (lower temperatures, shorter times, etc.) with tbe imidazoline predomi nate under more severe coIMitions, Some of each compound may be present as a product in a single batch reaction. An imidazoline can hydrolyze to the corresponding amide on exposure to water under the proper conditions.
Amines and Amine Salts. Amines (primarily monoamines) with long chains (e.g., CIO-C1S) also have corrosion inhibiting properties. Howeveiv beHer inhibitors can usually be obtained by reacting the amine with a long chain iaHy acid (e.g., stearic acid), but often the dimer or trimer acid. Reaction, conditions are milder than amide/ imidazoline condi tions and the salt is formed:
CHS (C H 2) 11NH2
Oodecyl Amine
+
[C H 3( C H 2) 11N H 3] [CH3 (CH2) 1 6 C 0 2 ]
Oodecyl Ammonium Stearate
If tbe acid bas a long tail of carbon atoms, ionization will be very slight and tbe inhibitor com pound is essentially oil soluble. Water solubility can be substantially increased by using a low m olecular weight acid (e.g., acetic acid) if the system pH is also low. Etboxylating active sites increases tbe water solubility irrespective o f tbe pH. O iam ines and dicarboxylic acids can also be used.
Quaternary Ammonium Salts. Replacem ent o f all of tbe hydrogen on tbe ammonia njtrogen with carbon or R groups results in a quaternary ammoni um compound:
CHS
IH tl-C H i I
CHS
Trinietbylalkyl ammonium chloride
in the example, a long chain amine (e.g,. R is CIS mixture) is reacted with methyl chloride as the quaternizing agenl. Other alkyl balides or mixtures can be used to obtain more complex quaternary ammonium compounds. All quaternary ammonium salts are highly ionized, with resulting high solubility in water and low solubility' in oil. However, etboxylatlon is sometimes used to improve solubility In concentrated brines.
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Gomi>otio %by Gas
Anar's1'!)
Fassy A d d
C&dxm No . Double Bonds
Source Coco Soya Tsitow
Tal! Oil
Rosin A c id s^ /
1t
cl
3
J u
j
l
.a
i a
1 s
8
10 "2
14 16
8
18 18
0
0
0
0
0
0
8
7 48 18
9
5
5
"
1 4
6 24 50
-
-
"
3 27 17 47
4
60-70% F atty Acids. 30-40% Rosin Acids
CH,
m
CH,
I%
18 3
5 i
A biotic A cid 2S-OS%
CH,
CO O H
R em ain in g U ssi A cids a m A b icti A cid D*ri**t<** Sh<s Below
Atwitia O e rs *
%
?*1i flection
Bond
Hy<3r<3gero3tiori
tkm
tkm
PJhistrk:
12-17
K
7*13
X
*hydFabste
10-14
O shydroabietk
2-12
X
Tetrahydroa bec
2-12
%
LvfiMfTtrM
1
D exifsfrarta
3-13
X
s
s&<dxfo p k n a r ic
3-13
3
K
(J ) Emery Industries, Spcifications and Characteristics o r Fatty Acids
(2) T . Uoyd-Jones, Cartosiott Inhibitors, Cor. Prove and Control, jt.11 ( 1966) A u gust
Table 2, Composition of fatty and rosin acids.
Nitrogen Heterocvelics. The nitrogen may also he incorporated into an aromatic or aliphatic ring structure. A typical example is pyridine, with substi tution on the ring being possible also. The ring nitrogen in pyridine can be quaternarized, while aliphatic nitrogens may also form amides.
Formulations of corrosion inhibitors are among the most complicated of oilfield treating chemicals, perhaps second only to emulsion breakers. The total composition depends on the relative amounts of the fluids being treated (oil, water, and gas) as well as the nature of the corrodents (COz, HzS, Oz, and/or organic acids). The presence of dissolved oxygen will sharply reduce the effectiveness of these inhibi tors. Oil soluble inhibitors are used most frequently because they normally give better corrosion inhibi tion. The concentration o f the compound is usually in the 30-40% range. A heavy aromatic naphtha
(HAN) refinery cut is a common solvent (40-60%), although other hydrocarbons can be used, depending on the compound. Oil soluble sulfonates can be included to improve oil dispersibility of compounds with limited oil solubility into a high gravity paraffin
ic crude for example. Dispersants such as nonyl phenol ethoxylates may be used to disperse the compound in high w ater-cut systems so the com pound can be transported to the oil phase. Isopropyl alcohol, ethylene glycol, etc. may be added to reduce the pour point for cold weather applications. Emulsian breakers may be incorporated to minimize emulsion separation problems^ similarly, antifoam: chemicals may also be included. These latter two m aterials are added, especially if the inhibitor is primarily applied with batch, squeeze, or tubing displacement methods. They counteract effects of high concentration inhibitor slugs, rath er than
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treatment of ongoing emulsion or foaming prob lems.
Water soluble inhibitors may be used in water injection systems, gas transmission lines, and wet oil lines with high water content. Quaternary' amines and amine (or amide) acetate sails are most commonly used. Compound concentration is in the 10-50% range, with water as the primary' solvent (30 50%). Methyl or isopropyl alcohol may also be included (5-20%) to improve stability in the drum and/or iow temperalUre handling characteristics. A surfactant (0-10%) such as nonyi phenol ethoxylate may be included to help the inhibitor reach the metal surface and to clean solids from the system. Water soluble inhibitors may be effective in gas systems where water may be produced or condensed and little hydrocarbon liquid is present. For gas gathering and trunk lines to shore, the corrosion inhibitor may consist o f m ore th an one type of compound: a quaternary ammonium salt for any liquid water that might collect and flow along the bottom, an amide "oil soluble" type for better long term effectiveness, and even a low molecular weight amine (e.g., ethylene diamine) to neutralize some of the acid gases. Triethylene glycol or a similar sol vent with low volatility is necessary in these gas lines to assure that the inhibitor formulation remains fluid and is carried along to shore.
Solubility. The distribution of corrosion inhibitors between the oil and water phases is highly variable. Most of the corrosion inhibitors used in the petrole um production offshore are oil soluble and are expected to follow the oil to the refinery. Some small fraction will be carried into the water in oil carryover but would constitute a negligible fraction of the allowable hydrocarbon concentration in the disposal water. On the other hand, the quaternary ammonium compounds would essentially all end up in the water phase.
Application. Different treatment methods are used to apply corrosion inhibitors in offshore operations.
Continuous treatments are used ia some wells (especially gas wells) where a small d iam eter macaroni or capillary line is available25, similar to the scale inhibitor. In fact, multipurpose scale and corrosion inhibitor form ulations have been de veloped for this specific circumstance. Continuous treatments at the wellhead or surface facilities are also used if downhole corrosion is negligible and/ or if supplemental surface protection is deemed neces sary. If corrosivity measurements indicate protec tion is needed, water soluble inhibitors can be added continuously to waterflood injection water. Recom mended treatments for waterfloods are typically in the 5-15 ppm range. Treatments for gas wells are usually higher, perhaps up to 100 ppm based on total
liquid production rate. Concentrations in the liquids may range up to a thousand ppm in unusual wells with very high gas volumes and very low liquid volumes. Some oil pipeline systems receive 10 ppm.
Displacement-tvpe treatm ents are the most common method for downhole treatment of produc ing wells. With a liquid displacement for an oil well, a calculated volume of inhibitor (e.g.. 55 gal) is diluted with sufficient hydrocarbon solvent (crude, diesel) to fill the tubing string down to the forma tion. The mixture is pumped in, allowed to contact the tubing for a short time, then produced back as the well is returned to service. With gas wells, the inhibitor may only be diluted to 5-10%, pumped in, and allowed to fall to the formation. The downtime for treatment and risk of killing the well with exces sive hydrostatic head has led to increased use of nitrogen in the treatments. Typically, the concen trated inhibitor (perhaps slightly diluted with sol vent) is atom ized into a nitrogen stream and dis placed to the formation face with m ore nitrogen. Displacement is usually much faster and the wells are usually returned to service almost immediately. In all types of displacement treatments, a substantial fraction of the inhibitor is retained on the tubing walls, with some part being produced at relatively high concentrations when the well is first returned to service. Experience of one operator indicated that only very minor amounts of the inhibitor were re turned with the initial production after a treatment.
Squeeze treatments have also been used, similar to those described for scale inhibitors. The inhibitor is diluted to 5-10% in an organic solvent and inject ed into the formation. While there will be an initial return slug of several thousand ppm concentration in the oii for a day or tw026, most of the inhibitor is produced back at a much lower concentration (less than 100 ppm ) over periods up to six months. Squeeze treatments are becoming less common because of concern for permeability damage around the wellbore, down-time, and risk o f killing the wells.
Concentrations of the oil soluble inhibitors in the produced water discharged to the ocean are expect ed to be quite low and would be included in the total hydrocarbon measurement The highest concentra tion in the discharged water would follow displace ment or squeeze treatments. All wells on a platform or in the system will not be treated simultaneously for four reasons:
The treatm ents will normally be effective for different durations. Treatment of all wells simultaneously causes major upsets in the separation equipment. Sufficient equipment and operating personnel are not available. Shutting in many wells simultaneously has an adverse effect on total production.
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Typically, no more than 10-20% of the wells feeding intO a separation system would be treated with a batch or squeeze treatment simultaneously. Thus, the peak concentration in the composite oil would only be a few hundred ppm. As an example, a carryover o f 40 ppm of oil containing 500 ppm of inhibitor following a batch or squeeze treatment would only lead to 0.020 ppm inhibitor in the water. Even allowing a 20X concentration o f the inhibitor due to possible accumulation at the oil/water emul sion interface, the concentration of 0.4 ppm is still very low, even prior to the immediate dilution at the point of discharge.
Oxygen Scavengers. One other type of chemical is used in production operations to control corrosion. Corrosion caused by dissolved oxygen in produced fluids is often controlled by reacting the oxygen with an oxygen scavenger. The scavenger does not form a protective layer. All of the scavengers in use are a form o f sulfite, with ammonium bisulfite being commonly used offshore because it is available as a concentrated (60%) stable aqueous solution. The reaction with oxygen is:
2 N H 4H SO J + 02 - 2 NH4HSQ4
The sulfate product is also highly water soluble, although the sulfate ion can react with high concen trations of calcium, barium, or strontium to form a solid deposit. N either the scavenger nor the produclS will end up with the oil. At use concentra tions (< 100 ppm added), neither the reactants nor the products pose any pollution risk to marine life (seawater already conlams about 2700 ppm sulfate). Furthermore, the most important application is for treating injection waters, which are not normally discharged to the sea.
C o rro sio n inhibition practices for the four companies interviewed had similarities and differ ences. None were adding corrosion inhibilOr to waterflood injection Water. Three did not normally treat oil wells downhole. However, one o f these three did continuously add 10 ppm corrosion inhibi tor to a large wet oil pipeline to shore, augmented by periodic batch trealmeni associated with pigging and biocide treatment. Another company regularly treated many of 150 oil wells feeding into a single pipeline (75-80% water), with 8-10 ppm o f a water soluble corrosion inhibitor being continuously added to the line. Gas wells were treated on a selective basis by aii operators, depending on resuilS of corro sion monitoring programs and experience. Nitrogen displacement was becoming the preferred trealmeni method for one operator, but liquid displacements were more common for the other three. Squeeze treatments were being used in some Instances but were becoming less commQD
BIOCIDES
The purpose and use of biocides in the offshore petroleum industry has been previously discussedS-?, This section will review those papers briefly to add perspective to this paper. A few additional points will be included as well.
Problem Description. Of the varions kinds of biological problems encountered in offshore produc tion, sulfate reducing bacteria (SRB) are of primary concern. These bacteria reduce sulfate ion to hydrogen sulfide, which contributes to corrosion damage to the system and fouling of equipment with iron sulfide. The corrosion damage most commonly encountered is pitting of steel which can cause leaks and failures. Sulfide corrosion cracking can also lead to sudden catastrophic failure of high strength carbon steels and many high strength alloys. The iron sulfide presence increases the need for frequent vessel cleanout and also causes problems in oil and water separation. The iron sulfide particles become oil-wet, stabilizing emulsions and snaking it more difficult" to obtain pipeline quality oil. Also, the oil carryover into the water is increased, making it more difficult to remove the oil from the water, fron sulfide can spontaneously ignite if allowed to dry in the air, increasing the risk of fire during shutdowns, workovers, etc. SRB can also be a problem in pipe lines connecting platforms or in the main pipelines to shore, especially since pitting corrosion can lead to oil leaks. Of course, hy drogen sulfide can be a severe safety hazard to operating personnel if vented or if contacted during maintenance of equipmen!. Control of bacterial, growth can clearly be necessary for safe and efficient operations. Biocides were used from time to time on approximately one fourth of the platforms in the Thirty Platform Study4,
Biocides may also be required in waterflood operations to prevent SRB growths from causing corrosion of the equipment and/or plugging of the injection wells. Slug treatments are the normal treatment method, whether source wells or seawater is used. One aspect nOt considered in the EPA5 or AP16 biocide survey papers is the treatm ent o f seawater for injection (or utility) use. Such systems often use electrochemically generated sodium hypochlorite to control marine and microbial growth in the intake portions of the water treatment or utili ty systems handling aerated seawater. Dissolved oxygen must be removed from the seawater prior to injection in w aterfloods by m echanical an d /o r chemical means. Since chemical oxygen scavengers also react with any residual hypochlorite, sulfate reducing bacteria then must he controlled with organic biocides in injection systems downstream of the treatm ent section to prevent corrosion and plugging of the reservoir rock, in eith er case
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(source wells or seawater), essentially all of the biocide is injected into the formation.
Alternate biological control methods have had limited application, but chemical treatment has the best success ratio. Copper-based alloys can be used in some limited situations (e.g., intake screens) to reduce or prevent accumulations of marine growth but are economically and technically unsuited for most of the equipment. Removal of bacterial depos its can be difficult and is usually incomplete. Scrap er pigs may remove most of the growths from pipe lines, for example, but are usually used in conjunc tion with a biocide program to obtain more effective results when bacteria are known to be a problem.
Chemical Description. The biocides commonly used in offshore producing operatioos can be broken into four generic chemical types.
Quaternary amme salt and amine acetate. These two types of generic compounds are similar and have the following general structures:
R1 - +
H oA
M2
H J
Quaternary amine salt
Amine acetate
The base amine may be a primary-, secondary, or tertir/ amine. One of the R groups is usually a long chain alkyl group, CIO-C2Q. The other R groups are usually Cl or Cz, formed by reacting with low molecular weight alkyl halides. The variation in chain length and ratios of the halides are the major modifications in the generic compounds. Quater nary amine compounds remain ionized and highly waiter soluble at all pH values. If there are three or fewer carboos bonded to the akregea, an amine salt can be formed by reaction with an acid, e.g,. acetic acid in the example shown. The salt is ionized at low pH, but the V i [ bond breaks at higher pH, forming the free amine, which is less water soluble and usual ly less effective as a bactericide. The forrnulatioos of these amine salts are usually relatively simple, a 10 50% solution of compound in water. Alcohols may be added for freeze protection or viscosity reduction.
A1deh.vd.es. Three types of aldehydes are used as biocides in the oilfield. These materials are much purer than most other oilfield treating chemicals, with w-ell defined properties. All are highly water soluble and very reactive chemically. The formulatioos usually contain an inhibitor to prevent polymer ization. Formaldehyde and giutaraldehyde are sold as 20-50% concentrated aqueous solutions. The acrolein is sold as an anhydrous liquefied gas under a pressurized nitrogen blanket and is fed directly
O H -C-H Forma1dehyde
O C H 2= C H -C H
Acro!ein
0
0
H C ~( C H 2) 3 - CH
Giutaraldehyde
from the cylinders. It should be noted that use of formaldehyde and acrolein has decreased in the last two years due to coneeros for personnel safety.
Other. Organic-sulfur compounds such as thiocarbarnates, isothiazolin, etc. and one halogenated organic compound (2,2 dibromo-3-nitrilo-propionamide) are used in offshore producing systems to some extent. The use of electro lytically generated sodium hypochlorite in seawater systems has already been mentioned.
Solubility. The biocides are all highly water solu ble, w-ith very limited solubility- in the oil. Hence, the biocides are expected to remain with the water.
Application. Biocides are used in production opera tioos to minimize operating problems hy controlling growth. It is not feasible nor is it necessary to obtain a completely sterile system. Experience through the years has shown that short periodic slug treatments at higher concentrations are technically and econom ically more effective in maintaining biological con trol iumde Hie w m than continuous treatment at tower ,, ussmut? A.* u Less hiocisle Is used; hence, less is discharged to the ocean. Slug treatments are optimized for each system but a typical program includes concentrations in the 100-200 ppm range for 2-6 hours on a weekly to biweekly basis. Thus, average usage for a 150 ppm, 4 hour weekly slug w-ould be 4 ppm, compared to 10-20 ppm require ment for continuous treatment. More frequent slug treatments may be required to obtain control initial ly but rarely more than every other day. Hypochlor ite used in seawater systems is added, continuously, with 0.5 ppm residual usually being sufficient to control marine and microbiological growth.
Essentially all of the biocide used in waterflood ing is injected into the formation with the water. Little or none will be discharged to the ocean. Because of reactivity and adsorption on surfaces in the reservoir, none of the biocide is expected to reach, the producing wells.
All of the four operating companies used biocide to some extent, but only in response to problems
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detected by operations personnel and/or monitoring programs (HzS increase, high SRB concentrations, FeS, etc). None o f the operators treated wells downhole, although one indicated that flowlines from remote single well jackets were slug treated weekly (100 ppm for a couple of hours) on an asneeded basis. T reatm ent on the platform s was usually restricted to the water processing equipment, again in response to problems or monitoring. One wet oil pipeline to shore receives a weekly 4 hour slug of glutaraldehyde (50 ppm, active basis) in conjunction with pigging. In another wet oil line, only the water processing equipment on shore is slug treated with 100 ppm acrolein<>. No acrolein was detected in the discharge from the facility due to dilution and reaction. Biocides were not normally required on any platforms in gas fields.
EMULSION BREAKERS
Problem Description. Virtually all of the oil pro duction in offshore operations contains produced water and dissolved or free gas. Major parts of the offshore facilities are involved in separating these three phases. Separation of the gas from the oil and water is relatively straightforward, although foaming can be a problem. As mentioned earlier, most of the gas wells produce very little water, with the liquid hydrocarbon being easily separated from the gas.
Separation o f the oil and water in oil fields is usually a m ore difficult task. While systems vary widely depending on the nature and age of the producing wells, two or more stages of separation are common. Most of the gas is removed in the high pressure separator, with the water and ail both being sent to the intermediate (or low pressure) separator through the same line, usually in an emulsified form. With a low water cut, water droplets are dispersed in the continuous oil phase, called a normal emulsion. At high water cuts the oil droplet is suspended in the continuous water phase, called a reverse emulsion. Oil and w ater are not miscible and normally will rapidly separate if some type of emulsifying agent is not present. Naturally occurring constituents of the produced fluids such as asphaltenes, resins, organic acids, clays, etc. can stabilize emulsions, as can cer tain materials such as corrosion inhibitors, biocides, or corrosion products that are introduced during producing operations. The emulsifying agents concentrate at the o il/water interface, preventing dispersed droplets from coalescing and separating.
The oil entering the low pressure separator usually contains some free water plus dispersed droplets o f water, stabilized to some extent by emulsifying agents. Free water is removed in the low pressure separator (or FWKO) and the oil flows to the bulk oil treater. This oil is treated to pipeline specifications in the treater. Oily water and any wet
oil is sent to other systems for further treatment. Separation of the emulsified water from the oil in
the treater can be improved with longer residence times, warmer fluid tem peratures, electric fields, and/'or chemical additives called emulsion breakers or demulsifiers. Excessive residence time is not economically feasible because of the high cost of space and weight on offshore structures, especially in deeper water. The produced fluids are commonly heated in direct fired h eater-treaters in onshore systems, but the increased risks associated with fire on an offshore structure makes this approach less desirable. Electrostatic fields in the treater are used extensively to improve separation, but it is still often necessary to use an emulsion breaker. Separation of water from very light oils and gas condensate is usually much easier; electrostatic separation is rarely used and emulsion breakers may not be needed.
Emulsion breakers work by attacking the droplet interface. They may cause the dispersed droplets to aggregate intact (flocculation) or to rupture and coalesce into larger droplets. Either way. the density difference between the oil and water then causes the two liquid phases to separate more rapidly. In addi tion. solids present will usually tend to accumulate at the liquid level interface (between the bulk oil and water phases) and form a semi-solid mass. If these solids are not dispersed into the oil phase or waterwetted and removed with the water, the interface detector in the control system will ultimately m al function, causing water to be dumped into the oil pipeline or oil to be carried over to the produced water system. Proper selection and application of emulsion breaker will minimize this accumulation and the resulting problems.
Chemical Description. Several different generic chemical compounds are used in emulsion breakers. Usually there are two or more compounds involved in any formulation.
Qxvalkylated Resins. The resins are usually alkyl phenol formaldehyde types, with R, m. and n being
CH3
I
T / CM rU 'j)
1
GHZ
y j \
Alkyl phenol formaldehyde resin R = C4 - C12 , n - 7-12 , in = 1 to large
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varied. The phenolic hydrogens are essentially all oxyalkylateci, usually with ethylene and/or propylene oxide. Propylene oxide is used in the example. Variation of n and m govern the oil solubility and wetting characteristics of the compound.
Polvglvcoi esters. Glycols such as ethylene gly col, di- or tri-ethylene glycol, glycerine, etc. are reacted with alkyl carboxylic acids to obtain the
desired properties. Using polyethylene glycol as an example:
Q r
G
1
H H
I
G ""O----"C - R 1
L ft h
Dialkyl polyethylene glycol
Variation of R a n d R1 governs the solubilities but the compounds used are all much more soluble in oil than in water. These compounds can also be modi fied by esterifying with dibasic acids (e.g., maleic anhydride) to form even higher molecular weight esters.
Alkyl Aryl Sulfonates. The third major type of com pound used in demulsifiers are the sulfonates, frequently a substituted naphthlalene sulfonate:
S03H
R
Substituted naphthalene sulfonate
Tire R group is usually a straight chain group. The co m p o u n d s are sim ilar to the dodecyl benzene sulfonate used in many household detergents but have different alkyl or aryl substitutions for higher oil and lower water solubilities.
There are a few other different types of com pounds that are occasionally used but the above types probably constitute 95 +% of those used in offshore operations.
Formulations. Probably 90-95% of the product formulations used in the oilfields will consist of mixtures of two or more of the above compounds. There may be two compounds from the same gener ic type or compounds from different generic types. Mixtures are usually required to obtain the best balance of reaction speed, cleanliness of oil, and clarity of water. In addition to these generic types.
many formulations also include a water soluble wetting agent. Probably the most commonly used c o m p o u n d is the sodium or ammonium sail; of dodecyl benzene sulfonic acid, the household deter gent mentioned earlier. Ethoxy late d nonyl phenol, another surfactant, is also used. The base solvent for virtually all of the demulsifiers is a heavy' aromat ic naphtha cut. Methyl alcohol, isopropyl alcohol, or similar solvents are used to obtain stability in the drum and/or freeze protection or viscosity reduction for cold weather applications.
Formulations will usually contain 30-50% total of the various demulsifier compounds. The bulk of the remainder will be the heavy aromatic naphtha. The wetting agent (e.g., dodecylbenzene sulfonate) is a very minor constituent (e.g., <0.01%) used to help the demulsifier migrate through water into the oil phase. This migration is especially important in wells producing a high percentage of water. When alcohols are added for freeze protection, the compound concentrations may drop below the 30% normal lower limit.
Solubility. The three primary dem ulsifier com p o u n d s listed are all highly oil soluble as is the aromatic solvent. Very little of these co m pounds will remain in the water phase except as a contami nant In oil carryover as described for the corrosion inhibitors. The alkyl ay I sulfonates would probably have the highest water solubility. One vendor had data for one crude oil indicating th at 92% of a formulation containing only this generic type of compound went into the oil, with only 8% (including the methyl and isopropyl alcohol cosolvents) of the formulation going into the water.
Application. During normal operations, demulsifi ers are added continuously, either upstream of the low pressure separator (or FWKO) or just before the treater. Concentrations (based on oil production rate) range from 10 to 200 ppm. , with most treat ments requiring less than 30 ppm. The higher concentrations would usually only be required to cope with an abnorm al situation, such as a welt workover, where unusually high solids concentra tions help to stabilize emulsions. High concentra tions of other treating chemicals (e.g., corrosion inhibitors) can increase emulsion stability also, but souse emulsion breaker is often incorporated ioto those formulations to minimize the emulsification tendencies.
Treating concentrations based on total oil and water production will obviously be lower, depending on the water cut. A normal maximum of 50 ppm (oil) would be 25 ppm (total) if an equal volume of water were produced. If 90% goes with the oil, only 5 ppm of total formulation would be present in the
water.
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REVERSE BREAKERS
Problem Description, After the primary oil-water separation occurs, some finely dispersed oil may be carried along w ith the w ater as an oil-in -w ater emulsion, commonly called a reverse emulsion in the oilfield. It is usually necessary- to clean up this water before it is discharged to the ocean or injected into a waterflood or disposal well. The oil itself must be reduced to approximately 48 mg/'l for overboard disposal! . While the oil may directly contribute to injection problems, the solids frequently associated with the oil will cause plugging of formations The injection rate will then decrease, the required pres sure will increase (higher fuel consumption) or the well must be worked over (acidized, backflowed, underreamed, redrilled, etc.) to maintain injectivity.
Probably the most common offshore produced water treating systems include efficient gravity set tlers (e.g., corrugated plate interceptors, CPI) and/ or flotation cells, although many systems may also have a small surge/skim tank as well. The tank (if present) allows Tree* oil and gas to separate from the w ater, easing the load on the downstream equipment. The CPI units provide better separation because the plates drastically reduce turbulence, allowing smaller droplets to separate, coalesce, and m igrate to the surface for skimming. In many svsterns with condensate or light oil, the CPI unit alone will suffice for oil removal for overboard disposal, often without chemical treatment. Howev er, reverse breakers can be added to facilitate gravityseparation in the skim tank and CPI units. For heavier oils, many operators have found that flota tion equipment is the most effective approach. A second chemical or a different formulation may be required to obtain maximum efficiency in the flota tion cell. Granular media filters may also be used for removal of oil and solids, especially if the produced water is to be injected. Different generic types or formulations of treating chemicals may be required for this equipment (See F). Filters have not been used extensively in offshore produced water treat ment because o f the extra space and weight reo quirements for cleanup of the backwash water (as compared to CPI and/or flotation cells).
Chemical Description. Most of the oil droplets in reverse em u lsio n s have a net negative charge. Hence the treating chemicals usually will have posi tive charges to neutralize the droplet charge and cause particles to aggregate. The reverse breaker com pound will have surfactant properties to reduce the interfacial tension, allowing the oil droplets to coalesce into large drops.
Polvamines. Low molecular weight amines or mixtures of amines are moderately polymerized to make these compounds.
M H 2-C8H 1! n -m -llB a Simple polyamine
Mixed polyamine
The R and R1 groups may have 2-8 carbon atoms to vary the charge density, with the molecular weight of the polymer usually in the 2000-5QOO range. In some instances, the R groups are crosslinked to form a more compact com pound structure. The compounds are usually present in the salt form in the drum (halide, acetate).
The reverse breaker com pounds are distin guished from the coagulants in the following section primarily by modification So provide surface tension lowering properties. This property is usually ob tained by reaction with a long chain fatty acid to form either an amide or an ester, but may also be obtained by oxyalkylation. Only a small weight fraction of the c o m p o u n d (e.g., 5-10%) will be modified, as too much reduction in surface tension can either stabilize or form emulsions during usage.
Polyamine Quaternary Compounds. Virtually any of the above polyamines can be quaternarized with methyl chloride or other desired agents to obtain the corresponding quaternary ammonium halide:
+ (n + 2)
IC C I/ I l : i l l (MM) ijftif if11;11 j I ( n + 2 ) C J -
L
(CH 3)2
J
These two generic types comprise most of the reverse breakers used. Many of the coagulants and flocculants discussed in the following section contain similar com pounds and sometimes are also used to aid in oil removal as well as the combined removal of oil and suspended solids.
Form ulations usually consist of20-40% of com pound in water solvent. Metal salts (aluminum,
iron, or zinc chloride) may be included in the formu lation in some instances, as discussed under coagu lants. Methyl or isopropyl alcohol is used for viscos ity reduction or freeze protection when appropriate.
Solubility. The quaternary' ammonium compounds are all highly soluble in water, with very little being carried ioto the oil except through water carryover. The pOlyamines are highly soluble in water at low' pH. but oil solubility will increase at higher pH
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values. The exact distributioo between the phases will depend on the specific compound, but com pounds with smaller R chains and more amino nitrogens per molecule (higher charge density) will be more w ater soluble at any given pH. If the produced water pH is as high as 8, quaternary ammonium compounds will generally provide great er efficiency at lower costs. Some of both types of compounds will accumulate on the surface of oil droplets and be skimmed with the oil.
Application. Reverse breakers are usually added continuously to the water leaving the low pressure separator and/or treater before it enters the water cleanup system. Concentrations will vary with the difficulty7of breaking the reverse emulsion but 5-15 ppm based on the water flow rate is typical. Over treating is both technically and ecooomically unde sirable. Excess breaker often can cause re-emulsifi cation.
COAGULANTS AND FLOCCULANTS
These materials are chemically similar to the reverse breakers but generally do not cause lowering of the surface tension. They are primarily used for removal of solids from injection water but may also be used to improve oil removal for overboard dis charge, Nomenclature varies between the supplier and operating companies interviewed.
Problem Description. Suspended solids in water can cause plugging problems in injection or disposal wells. These solids can also stabilize both normal and reverse emulsions, making it more difficult to obtain saleable oil and/or properly treated water. Reverse breakers are primarily used to clean up oily produced water for discharge, but a coagulant (and/or ftocculant) may be required to get the solids concentration down to very' low levels to prevent injection well plugging.
Chemical Description. The coagulants have the same generic chemical descriptioa as the cationic polymers commonly used for the reverse breakers: low' molecular weight polyamines or quaternarized polyamines. Little or no modification is made to the basic structure. 'lire high charge density provided by amine groups on short chains allows efficient neu tralization of the negatively charged solid particles and some growth into larger particles. Aluminum, iron, and zinc chlorides can also be used as coagu lants. These materials work by precipitation, with the precipitate both centralizing and entrapping suspended solids particles.
Coagulant formulations may be solely polymers (typically 20-30% active in water), inorganic salts (20-50% active), or mixtures (primarily inorganic
salts with 5-10% polymer). Water is the solvent, but methyl or isopropyl alcohol can be added to the polymers for freeze protection.
The flocculants are very high molecular weight polymers. Cationic types are the most common but anionic and non-ionic are available. The molecular weights are in the 0.5 to 20 million range, a hundred to a thousand times higher than She coagulants. The charge density7is much lower than the coagulants as well. These materials help solids removal by bridg ing between particles or aggregates of panicles, with relatively minor neutralization of charges. The drastic difference in molecular weight and charge density is obtained by adding a few active sites to a relatively large inert polymer. For example, a high molecular weight phenol-formaldehyde resin can be formed with sufficient ethoxylation to m aintain water "solubility1. A few7amine groups (salt or quaternary7ammonium form) can be added to form a cationic polymer, or a few carboxylic acid groups added to form an anionic polymer. Formulations are in the 10-30% active range.
Solubility. The coagulants and flocculants are all highly water soluble with very little expected to he carried into the oil except as an impurity in emulsi fied water. In most applications, however, these agents would become rather tightly attached to the particles, becoming essentially insoluble in either the water or oil. They would then follow the solids.
Application. Coagulants can be added to speed up gravity separation in a lank or CPI unit or improve the performance of a granular media tilter. Typical treatment concentrations for settling are in the 5-10 ppm range. Treatm ents below7 1 ppm have been effective in the filtration of relatively clean (1-10 ppm TSS) seaw ater (N orth Sea, A rabian Gulf. California, etc.), but higher concentrations may be required with higher suspended solids concentra tions (e.g., in the Cook Inlet when glacial silt con centrations may reach 1000 ppm TSS during spring runoff).
Flocculants are usually more economically and technically effective when the original suspended solids consists of relatively lew large particles or after a coagulant has been used to aggregate most of the small particles. For example, the original, small, negatively charged particles could be neutralized into a few positively charged aggregates by a moder ate overtreatment with a cationic coagulant. The aggregates could then be further bridged into very large aggregates with an anionic flocculant to cause rapid settling in a tank or CPI unit.. Flocculants can also be used to aid in removal of oil from oil-coated sands.
None o f the operators interviewed were using coagulants or flocculants to treating o f injection
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water. Some of the operating personnel felt that the chemicals added upst ream of the flotation units were best classified as coagulants or flocculants as op posed to reverse breakers.
ANTIFOAM
Problem Description. Foaming can be a significant problem in separation of gas from liquids in both high and low pressure separators. Excessive liquid carryover into the gas can cause problems in down stream compression and/or gas processing equip ment. In let scrubbers installed to protect such equipment are usually sized to catch minor amounts of spray, not large quantities of foam.
Foaming problems can be reduced by decreasing the throughput, increasing the operating pressure, or adding an antifoam chemical. Decreasing the flow through the separators would decrease total produc tion which could have serious economic and techni cal im plications. M aintaining a higher operating pressure on the high pressure separator would reduce the amount of gas released and the volume of gas in the vapor phase, thereby providing more time for the foam to collapse. However, the higher pressure may decrease the production from the lowest pressure wells and will increase the volume of gas to be handled in the low pressure separator. The change will also affect the amount of conden sate in the gas phase.
A ddition of antifoam chemicals (usually up stream of the high pressure separator) can drastical ly reduce both the quantity and stability of the foam. Besides eliminating possible restrictions in produc. lion rates and/or gas processing problems caused by foam, the separator operating pressures can then be adjusted to obtain the most efficient distribution of condensate liquids.
Foaming can be a problem and a benefit in water processing. Foaming can adversely affect vacuum deaerators, significantly reducing oxygen removal efficiency. Some foam is helpful in removal of suspended solids and oil in flotation cells, but exces sive foam is detrimental to both the original separa tion and subsequent handling of the waste stream from the unit.
Chem ical D escription. Two generic types of com pounds are used as antifoams: silicones and polyglycol esters. Variations o f both types can be used in either hydrocarbon or wafer processing. The com pounds wrnrk by accumulating at the gas/ liquid interface and disrupting the foam layer and must have low solubility in the liquid phase to function in this manner.
Silicones. This class o f chemicals is based on silicon, often with substitution of carbon-based organic radicals on the silicon atom.
R
R
I. L
-O -S l-O -S l-
I !
R R
n
The degree of polymerization (n) can be varied as well as the organic group R on the silicon. Larger values of n and larger R groups increase the molecu lar size and the viscosity, which is often used to characterize the basic compound.
Lower molecular weight, silicones with low viscos ities may be sold and applied as pure com pounds without a solvent. Mixtures of com pounds also can be blended for optimum efficiency for specific appli cations. Some form ulations use a hydrocarbon solvent to lower the viscosity of a high m olecular weight silicone for easier handling and pumping. Colloidal silica (e.g., extremely small particles of sand) is included in some formulations to improve the effectiveness of the silicone. Finally, emulsions of silicones in water (with or without colloidal silica) are available for use in water-based systems. A surfactant and sometimes an alcohol are required to maintain emulsion stability in the drum.
Polyglycol esters. These materials are obtained by reacting fatty acids (e.g., stearic acid) with a rela tively high m o lecu lar weight polyglycol. Using polypropylene glycol and stearic acid as the R group:
R group
n Polyglycol
A surfactant is often included in the formulation to improve dispersibility of the com pound in the liquid phase. The surfactant may be different depending on whether the liquid phase is primarily hydrocar bon or water. Methyl or isopropyl alcohol may also be included in the formulation to improve stability in the dram and/or provide freeze protection.
Solubility. The antifoam co m pounds have very' limited solubility in either hydrocarbon or water. The form ulation would usually be diluted with hydrocarbon before injection in production separa tors to improve dispersion into the stream. Since
the water phase is below the oil/ gas interface where foaming occurs, most of the antifoam com pound will go with the oil phase, even though it is not soluble in the oil. Emulsified silicones and/ or polyglycols used
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in deaeration towers obviously carry along with the water and are injected. The compound used in a flotation system mostly goes with the oily froth, ultimately following the oil to sales.
Application. The antifoam compound must be added continuously to control foam. The required concentration for production systems can range from a ferv ppm up to about 25 ppm. Substantially lower concentrations have proven effective in sea water vacuum deaerators, about 0.2 ppm o f both generic types27,28, Thorough dispersion of the formulation into the main process stream is neces sary for optimum effectiveness. Predilution in kero sine, diesel, water, etc. is a commonly used method to aid mixing, but care is required to assure that separation does not occur in the intermediate dilu tion stream.
The operating companies interviewed had encountered very few foaming problems that war ranted treatment with antifoam chemicals. No more than a half dozen production separators (total) required treatment in all of their operations. One operator reported they used antifoam occasionally on flotation cells.
SURFAcrANTS
Problem Description. Surfactants are widely used in offshore operations to remove small amounts of oil or grease from the platform and/or equipment. Accumulations of hydrocarbon would undoubtedly increase the risk of damage due to fires. Oily deck surfaces or equipment can become extremely slip pery and will lead to injury to personnel. The Minerals Management Service (MMS) requires that all offshore facilities be washed down regularly to minimize these potential hazards. Surfactants are also used to remove oil films prior to touehup paint ing, although sandblasting may be required in many instances.
Ill some instances, surfactants arc used to aid in mitigating corrosion and/or bacterial problems in systems. The surfactant supplements the detergent properties of tire inhibitor and/or biocide to allow those compounds to penetrate to the metal surface and may also help dislodge deposits from tubing, pipelines, or vessels.
Surfactants may also he needed to clean up granular media filters that have become contaminat ed with oil, solid hydrocarbon deposits, and occa sionally even non-hydrocarbon materials. Such treatments are usually not required on seawater filters because hydrocarbon contamination is ex tremely rare. In a similar application, surfactants maybe used to water-wet produced sand and/or clays, releasing the oil for recovery and allowing discharge of oil-free solids to the ocean.
Chemical Description. Both of the commonly used types of surfactant compounds are widely used in other industrial and domestic applications.
Alkyl aryl sulfonates. This g e n e ric type o f compound is an anionic surfactant, usually in the neutralized form:
ZH 2~~ 1C H I 2 1~~ 2 ~~S C :
l *
The exam pie shown, dodecyl benzene sulfonate, illustrates the common structure of the alkyl group . a moderately long straight alkane. The chain lengths of m y compound mil vary somewha t, and different average lengths may be used to obtain somewhat different properties. Numerous earlier studies have shown that the straight chain was biologically de graded far more quickly and extensively than branched chains. The higher m olecular weight
sulfonates described under Emulsion Breakers are usually not used as surfactants for system cleanup.
Formulations are usually concentrated solutions o f compounds in water.
Ethoxvlated Alkvl phenols. These materials are formed by ethoxylating phenol or substituted phe nols.
The size of the R group (a straight chain alkane with Oto 18 carbons) and the degree o f ethoxy lation in) controls the solubility of the surfactants. A large R and a moderate n allows the surfactant to be soluble in hydrocarbon for certain applications (e.g.. clean ing storage tanks or vessels) yet be highly water dispersible for washdown purposes, A smaller R group and/or more ethoxylation allows the surfact ant to be highly water soluble and easily diluted and/ or applied with water. onyl phenol is widely used because it is readily available, low in cost, and easily modified to achieve the desired properties.
Formulations can vary substantially, depending on the purpose. One oil-soluble version is available with 2-20% surfactant in hydrocarbon solvent to facilitate tank/ vessel cleanout. Water soluble ver sions are available as more concentrated forms (20 50% compound) in water, with alcohols or ethylene glycol added for solvency and/or pour point depres sion.
Solubility. As discussed earlier, the sulfonates are water soluble while the phenol-based materials can be made oil soluble and water dispersible as well as water soluble. Oil soluble surfactants used to clean
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tanks are drained or pumped directly to the oil stream and would probably continue with the oil to the refinery. Otherwise, the surfactants would be expected to go with w ater into the processing stream. Some of this surfactant would be expected to move with dislodged oil hack to the oil stream from the CPI or flotation ceil, but most of the water soluble surfactant would remain in the water phase and be discharged to the sea.
A pplication. Process applications require lowconcentrations (5-25 ppm) to alter the surface ten sion and water-wet produced sand for example. Treatm etto clean up an "it/ water interface emul sion stabilized by solids is usually a batch operation, with the emulsion breaker treatment preferably being altered to prevent a frequent recu rren ce. Similarly, cleanup of contaminated Biters is usually a batch process not involving continuous addition of surfactant.
Housekeeping cleanup of the external surface of equipment and the platform itself probably involves as many procedures as there are housekeepers. In principle, a 1-10% dilution of surfactant in water is wiped, sprayed, mopped, brushed, etc. onto the surface and allowed to soak. Subsequently, the surface is hosed down with copious amounts of seawater, sometimes followed by a freshwater rinse. The surfactant would be drastically diluted, but it would be difficult to impossible to give probable ranges. After the released oil is separated iu the sump, the water is discharged to the ocean.
None o f the operators continuously added sur factant to any process stream nor did any have media fillers in service which might require cleanup. Surfactants were used on an as-needed basis (not a common occurrence) for cleanup of oil wet solids a n d /o r disposal o f the interface in separators. Various surfactants and cleaners are frequently used for housekeeping and maintenance purposes.
PARAFFIN TREATING CHEMICALS
Problem Description. The liquid hydrocarbon phase produced from many reservoirs becomes unstable after it leaves the form ation. Decreasing pressure and tem peratu re causes a solid hydrocarbon to deposit on the walls of the tubing, flow-' lines and surface equipment. The deposits will progressively block flow' through piping and fill process vessels and tanks. Excessive deposits can interfere with operation o f valves and instrumentation.
The com position of this solid depends on the original oil composition, but it is usually called paraf fin in the oilfield. Straight or branched chain hydro carbons, similar to the paraffin homologous series defined by chemists, are usually deposited from paraffinic crudes. Polynuclear aromatic hydrocar
bons, sometimes referred to as asphaltenes, are usually deposited from asphaltic or aromatic crudes. These various solid deposits have different solubili ties in organic solvents. Unfortunately, paraffin deposits are so complex that no calculation methods exist to predict when they will deposit. Experience in the field with similar crudes is the best method to anticipate problems. Deposition of paraffin from fresh, pressurized holiom hole samples can be a useful indicator also.
Physical methods can be used to control paraffin problems in many instances. Scrapers and 'pigs' can be pumped through flow lines and pipelines, pushing accumulated deposits before them. Pumping hot oil through lines is a common remedial method on shore, but is less common offshore because of safety concerns. Thermal insulation for subsea lines and platform piping will reduce the deposition rate and sometimes prevent any deposition under normal operating conditions.
Chemical methods are used alone or in combina tion with physical methods. Solvents can be used to dissolve the paraffin or keep it in solution. Continu ous addition o f solvent to the total production stream is often prohibitively expensive. However, solvents are frequently used to remove paraffin during workovers involving acidizing, gravel packing, etc. Paraffin inhibitors can be effective in preventing the solid particles from aggregating or depositing on the walls of the piping and equipment.
Chemical Description. Solvents used to control are normally impure refinery' cuts for economic reasons. The paraffinic or aromatic nature of the solvent is selected to obtain maximum solubility of the paraf fin. Cuts approximating xylene mixtures are the closest to a defmabi structure.
Chemical suppliers submitted information on three types o f compounds used as paraffin inhibitors. The available information is not considered suffi ciently defined to show structures. The three types are vinyl polymers, sulfonate salts, and mixtures of alkyl polyethers and aryl polyethers.
Solubility. The solvents and inhibitors are all highly soluble in oil, with very limited solubility in water. Consequently, it is expected that almost ail o f the paraffin chemicals will remain in the oil phase.
Application. Paraffin solvents are used in batch treatments occasionally in offshore systems to aid in cleaning out lines or vessels. Some operators have used a small hatch (50-100 gallons) in front of pigs to aid in paraffin removal or help soften deposits if the pig becomes stuck.
Paraffin inhibitors are used more commonly and are added continuously. Treatment concentrations are usually in the 50-300 ppm range, based on oil
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production. Crades with mild to moderate paraffin deposition tendencies may require treatment only dining the winter months when air and water tem peratures are lower.
SOLVENTS AND ADDITIVES
This section is concerned with components of the formulations Ihal are not related to the functional use or uses o f lhe chemical, primarily solvents and some surfactants.
Solvents. Hydrocarbon solvents are used with those chemicals tha usually end up in the oil phase emulsion breakers, oil-soluble corrosion inhibitors, and anli-foam chemicals. In all instances, Ihis sol vent is a complex refinery cut, not a simple com pound. "Heavy aromatic naphlha" is lire term mosl commonly used by lhe suppliers, emphasizing the key requirements. The aromalicily enhances the solvent properties of the naphlha cut with respect to the various chemical compounds. while lire "heavyrefleets the high molecular weight and low volatility needed to meet flash point restrictions for safe handling.
These solvenls ail have very high solubility in the oil phase and vera low7solubility in the water. Essen tially all of the hydrocarbon solvent is expected to go with the oil.
Olher Solvents. Methyl and isopropyl alcohols are the mosl common other organic solvents. As poinled oui earlier, their primary purposes are to provide lower viscosity or freeze protection in the drum. While both are completely soluble in water in all proportions, they also have substanlial solubility in hydrocarbons. Consequently, they are also incorpo rated into some formulations to obtain a completely miscible stable formulation in the dram. Miscibility can be a particularly important aspecl in multi purpose formulations, such as one containing a corrosion inhibitor, biocide, and scale inhibitor. Glycerine and low molecular weight glycols are also used in some formulations. It is expected that these solvents will primarily end up in the water phase in most applications.
Surfactants. Relatively small amounts of surfact ants are incorporated into some formulations to increase stability and dispersibility in the drum, wiih less than one percent being adequate in most cases. In olher formulations, surfactant may be added in comparable or slightly higher concenlralions to improve the performance of the primary compound. For example, surfactant may be added to help the corrosion inhibitor penetrate to the pipe surface. Chemically, lhe surfactants are similar or identical to those described previously.
GAS P R O C E SSIN G CH EM IC A LS
HYDRATE INHIBITION CHEMICALS
Natural Gas Hydrates. Natural gas hydrates are ice-like solids that can form in natural gas in lhe presence of liquid water under certain conditions. These solid deposils can form at tem peratures well above 32F, even above EOF. Hydrates can block flow of fluids and cause ruplure of pipe, fittings, or valves. Chunks of hvdrales moving through piping can cause catastrophic failures at elbows or tees. Compressors can be destroyed by the impact o f pieces of solids, including hydrates. Clearly, hydrates can be a severe problem in producing or shipping natural gas. How'ever, hydrates frequently are not encountered in shallow w aters in G u lf o f M exico o p e ra tio n s . Deeper waters are expected to be snore severe, as are the colder WeSl Coast and Alaskan walers.
Numerous factors affect lhe tem perature at which the solid hydrates will form. Hydrates form at higher temperatures if the pressure is higher and the gas contains more ethane, propane and butane. Figure 4 from an early publication^ shows these trends. These curves indicale lhal hydrates should be expecled above 3000 psia if Hie temperature of most natural gases drops below about 75F. Most gas wellhead pressures in lhe Gulf ol'Mexico are above Ihis value for much of the producing life of lhe well However, the situation is complicated if carbon dioxide or hydrogen sulfide is present in significant
SOGO
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2-000
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Figure 4, Conditions favorable for formation of natural gas/ freshwater hydrates.
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coocentrations. These gases allow hydrates to form at even higher temperatures. On the other hand, high concentrations of salts or other materials dis solved in cha water depress the hydrate temperature considerably.
Tem peratures below-' 75F are not uncommon. Surface water temperatures in the Gulf of Mexico range from about 65F in February to about 85.F in August 30. However, it is the development of deep water prospects that is currently of greatest concern to operators in this arcadi. Average annual tempera ture at 1000 feet is 54F, decreasing to about 4IF at 3000 feet. Seawater temperatures off the West Coast are perhaps 10-15 F cooler than the Gulf of Mexico for comparable depths and seasons. Alaskan waters drop to the 2SF freezing point in many areas during the w inter in w ater, with ice being even eolder. Ambient air tem peratures in all areas can drop below seawater temperatures.
The hydrates can form wherever and whenever the gas is cooled below the solidification tempera ture in the presence of liquid water. The natural gas in the reservoir is hot (15G-350F), far above the hydrate form ation tem peratures. However, the gas cools as it flows up the wellbore, through the equip ment, and to shore. One problem area occurs at the choke valve. Most gases cool as the pressure is reduced from wellhead pressure to pipeline pres sure. Another problem can develop if the gas flows through a subsea flowline from a remote well or platform to a central processing platform. The gas will he cooled by the seawater or mud on the sea bottom. When the gas is flowing, hydrates can form only If the seawater or mud temperature is below the lydrate point and if heat transfer is sufficient to actually cool the gas to the hydrate tem perature. High flow rates and the corrosion and weight coat ings on subsea flowlines sometimes restrict cooling sufficiently in short lines to prevent hydrate forma tion. However, when flow from a well or platform is stopped for a sufficient time for any reason, the gas will cool to the tem perature of the surrounding waiter mud or air. Hydrates can forai, even blocking the flow-line completely. Blockage can cause serious problems when the system is brought back into productio n.
Prevention of Hydrates. The formation of hydrates can be controlled mechanically or chemically. The choice depends on the system and on the tempera ture and pressure conditions. Thermal Insulation can be used to minimize heat loss mechanically and keep the gas warm as long as possible. However, there will he times when How is reduced or stopped for extended periods. If the surrounding tempera ture is below the hydrate point and liquid water is present, hydrates could form and cause problems. The situation is similar to protecting the cooling
w ater In a car. Parking the ear In an unheated garage may provide satisfactory protection if the outside- temperature only drops to 30 F overnight. If it stayed cold for several days, the w ater might freeze and rupture the radiator or engine. More reliable protection can be obtained chemically by adding "antifreeze" to the water.
The "antifreeze- added to the car works exactly tbs same way that hydrate inhibitors work. In fact, the ethylene glycol commonly used in ear radiators is occasionally also used in gas systems. `More anti freeze must be added to the radiator to protect against lower temperatures and more chemical must be added to the gas to get g reater freeze point depressions of the hydrates. Methanol (methyl alcohol) is more commonly used in gas systems because it is normally much less expensive than the glycols.
Methanol. Methanol (CHSOH) is used much more frequently than any other chemical when hydrate inhibition is required offshore. It is much less expensive per pound than the glycols but more pounds are required to obtain the same freeze point depression. A large fraction of the m ethanol will remain in the vapor phase, depending on the tem perature and pressure of the gas in the system. Moreover, substantia! concentrations of methanol are still required in the water to obtain significant depression in the freeze point. Figure 5 illustrates the approximate values of concentration of methanol in the water calculated from the Hammerschmidt equation.32, a common guide. While actual require ments may differ somewhat to practice, it is still quite apparent that substantial concentrations (10 50%) will be present in treated waiter separated from the gas.
S3
j
*3 S iCC
$ 3<? I CM S!
Methanol Fre e ze Point D e p re ssio n
^ mm- & | 3333 + 23 \
W tfwigtfc****5#*# !|
0....
f li
20
*<?
Ffws Point Depression, F
Figured. Approximate methanol concentrations in water required for freeze point depres sions o f natural gas/ freshwater hydrates.
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Treatment is usually only economically feasible when little or no liquid water xs produced from the reservoir. In this situation only the condensed water must be treated to prevent hydrate formation. Even so on the order of 5-15 gallons per MMSCF may be required to inhibit hydrates for moderate Gulf of Mexico condi tions. One o f the operators surveyed used an average of 9,5 gal. per MMSCF to treat the half of the gas requiring hydrate inhibition. Thus a remote 50 MMSCFD platform might require several hundred gallons per day methanol during cold weather conditions, with 50% or more remaining in the gas under many conditions.
Ethylene Glycol. In certain circumstances ethylene glycol (CH20HCH20H) may be the inhibitor of choice. It has a very low vapor pressure, essentially keeping all of the inhibitor in the water phase. If only small depressions are needed, elimination of the vapor losses may offset the higher price per pound,
DEHYDRATION CHEMICALS
Triethylene Glycol (TEG). As discussed earlier triethylene glycol, (CH20CH2CH20Hli, is used almost exclusively for offshore gas dehydration. Since the dehydration system is normally a closed recirculation system, discharges are limited to abnormal occurrences. Typical makeup require ments are only about 0.05-0.3 gal per MMSCF.T3. This loss is almost totally spray or vapor carryover into the gas line to shore. One operator had a total makeup of 0,75 gal/MMSCF. with none of their systems requiring changeout during 1988. The higher than average losses probably reflect higher than average throughput fluxes to minimize space and weight requirements on the platforms.
Disposal of TEG is rare, as it usually does not become seriously contaminated. The greatest risk of contamination is carryover of liquids from the up stream separators. While hydrocarbon liquids are the most likely to be carried over, all but the very heaviest would be vaporized during the regeneration of the TEG. Vexy heavy liquids would collect on the surface of the accumulator, while solids would be removed by S S ra fa . Carryover of corrosion inhibi tors might cause a foaming problem, but antifoam chemicals can be added to minimize that problem. Carryover of salt water is unlikely, but does pose a serious problem if it occurs. The salt can ooly be removed by vaporizing the TEG in reclaimer units, which are normally not installed offshore. The TEG usually must be replaced if salt accum ulation becomes severe. The TEG is normally drained into containers for reclamation or disposal onshore, but is som etim es dumped overboard with the water discharge.
O ther Glycols. Diethylene glycol (DEG). 0(C F12C H z0H h, and tetraethylene glycol, O( H2CH20CH 2CH20H)2, could tie used for dehydration instead of TEG. The DEG would be used for processing cold gas to m aintain a lower viscosity and better efficiency in the contactor. The tetraethylene glycol would normally only be used with unusually hot gases to minimize vaporization losses. One operator noted that some of their glycol systems contained a fraction of tetraethylene glycol in the TEG.
STIM ULATION AND W O RK O VER C H EM IC A L S
ACIDS
H ydrochloric Acid. Hydrochloric acid is the workhorse acid for oilfield stimulations, offshore and onshore. The concentration may vary for different situations, but 15% is the most common form. All types and concentrations will contain an acid corro sion inhibitor to minimize damage to the tubular goods and downhole hardware. The objective of the add is to dissolve calcium and magnesium carbon ates an d /o r iron corrosion products that are block ing flow paths. This acid is somewhat more expen sive than sulfuric acid, but the latter can not be used. Calcium sulfate would precipitate, offsetting the dissolution of calcium carbonate, etc. Post precipitation can be a problem even with hydrochlor ic acid, sometimes requiring special additives.
The acid will normally react rapidly because downhole temperatures are high. The acid will be largely neutralized within an liour or two, provided sufficient carbonate or corrosion product materials are p resen t in the ai'ea contacted by the acid. However, paraffin or asphaltene coatings can pre vent the acid from contacting the surface of these materials. In these instances a detergent or solvent may be required to clean the surface to allow rapid reaction.
Most acid jobs require several solutions being pumped down in series. A pre flush solution, often 3-5% ammonium chloride, is used to push the hydrocarbon and formation water back away from the wellbore, if necessary, a detergent or solvent wash to clean surfaces is the next stage. The acid slug is then pumped in, followed by a post-flush solution. The post-flush solution pushes the acid further into the formation, allowing more efficient use of the acid. After the desired time, the "spent" acid and solutions are produced back to the surface, along 'with the dissolved materials.
The fluids produced from the formation after an acid job will consist of the "spent" acid, flush fluids, formation water, and hydrocarbon. These fluids must be processed before the oil can be shipped and
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the waters discharged, II is not uncommon for these tluids to form a very stable emulsion, making it important to avoid upsetting treatment of the rest of the production. When the appropriate equipment is available, many operators will process tluids from this particular welltlirougb the test separator until production is again normal. In other instances the tluids are produced into a "bad oil" tank first,, and thee slowly blended with incoming production over an extended period. In almost all instances the spent acid and associated aqueous tluids from the job are blended with the produced water stream and discharged overboard. However, these tluids will be pumped into tbe pipeline with other production in those systems where all o il/w ater separation is performed onshore.
Operators normally do not perform detailed analyses or monitor to determine the amount of unreacted acid in the returns. In some instances the returns are checked and excessive acidity is neutral ized. Most of tbe specialists interviewed believed that the acid was probably 95% + reacted downhole, with further neutralization occurring when spent tluids were mixed with produced water. The car bonate/bicarbonate buffering system in seawater will ultimately neutralize tiny unreacted acid. In the absence of analytical data it would not be feasible to estimate the pH in the receiving water vs dilution, volume.
HydroOuoric Acid. Hydrotluoric acid is the second most common acid used in the oilJield. More specif ically this acid is used as a mixture with hydrochloric acid and is commonly referred to as "mud acid". Concentrations may range as high as 12% hydro chloric acid and 3% hydrofluoric acid. Typical concentrations used in the G ulf of Mexico by the participating companies are 7.5% hydrochloric acid and 1,5% hydrofluoric acid. In addition some ammonium bifluoride may be added to increase the effectiveness. Mud acid is used because it can also dissolve sand and clays. The fine clays in drilling mud were added to prevent drilling fluids from flowing into the formation by forming a filter cake. However, some of tbe clay goes into the formation and can cause severe plugging. The mud acid is frequently used in the original well completion to remove these solids. However, it is also used later in the life of the well to remove See sand or clay parti cles in the formation that may have m igrated to wards the wellbore and are blocking flow paths.
Mud acid treatments always involve a series of fluids, similar to that described above. Calcium fluoride is quite insoluble so it is necessary to p re vent the mud acid from contacting a formation or formation water containing calcium, A typical sequence includes a 3-5% ammonium chloride pretlush, followed by 5-15% hydrochloric acid. This
acid dissolves any solid calcium, carbonate, etc. A second ammonium chloride flush pushes this acid and dissolved calcium further into the reservoir, separating it from the mud acid slug which follows. A final postilush solution of ammonium chloride or 3-5% hydrochloric acid pushes mud acid hack for more efficient utilization of the fluoride. The spent acid and associated tluids are produced back in the same manner as described for hydrochloric acid.
Other Acids. Acetic, formic and citric acid are sometimes used in acidizing. The citric acid may actually be added to any of the acid systems to act as a chelating agent to keep dissolved iron in solution. The first two acids are being used in wells completed with duplex alloy tubing for corrosion resistance.
These alloys may be subject to chloride cracking failure at high chloride concentrations, especially under acid conditions at high temperature. Since both of these acids are weaker than hydrochloric acid, they will react slower with carbonates or corro sion products. Slower reaction rates may be an advantage at very high downhole temperatures to allow the acid to penetrate further back into the formation.
Additives. Additives other than corrosion inhibitor are only used when tests or experience indicates that specific problems are likely. Most have the potential of causing problems as well as preventing them. Obviously all will add to the cost of the acidjob.
Corrosion inhibitors for acids will often consist of a mixture of types of com pounds. Acetylenic alcohols, such as propargyl alcohol (CHCCHzOH) or alkyl substituted derivatives, are a common component. Alkyl pyridine quaternary ammonium compounds are also used. The strong acidity may limit solubility of some of these components, requir ing a dispersant. Alkyl phenol ethoxylates or other surfactants may be used for this purpose.
H
BCSC-COH H
^ | | .....
1% "lib-- H f O
, .
H ___
Propargyl Alcohol
Alkyl pyridine be&zyi ammonium chloride
Solvents can be used to dissolve paraffin or asphaltene deposits, allowing faster acid attack. Both aliphatic and aromatic hydrocarbon solvents are used, depending on the nature o f the deposits. These solvents and deposits usually go into the pipe line with the oil, with virtually no carryover into the water discharge. Mutual solvents, such as oxyalkylated alcohols and ethylene glycol ~N-butyl ether, are also used on occasion. Some of these solvents will partition into the water phase.
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Anti-sludging agents are primarily intended to prevent any hydrocarbon solids from being generat ed. Sludging is more likely to be encountered in heavier asphaltic erodes, [f some solids are formed, these agents are intended to keep them highly dis persed. Oil soluble long chain alkyl benzene sulfo nates are one type o f compound used for this pur pose. These formulations can include hydrocarbon solvents, alcohols, and surfactants in proprietary formulations. It is likely that some components could be partitioned into the water. Paramn control is a similar problem, with ethylene vinyl acetate resins being used to prevent deposition.
Surfactants can be used for these same purposes but can lead to severe emulsification o f the oil and treating fluids, potentially throwing both oil and water streams out of specification. Selection o f the specific surfactant can minimize the problem, with fatty acid ethoxyiat.es being one type o f compound. [t is not uncommon to add a second dem ulsifier chemical to offset the emulsification. The demulsifi er may be added with the acidizing fluids or into the returned fluids at the surface, depending on various circumstances. The same types of compounds are used as discussed for production treating chemicals.
Scale control agents are also used to prevent inorganic problems. Citric acid or ethylene diamine tetraacetic acid (EDTA) are used to prevent re precipitation of iron compounds. Scale inhibitors like those used for produced fluids keep the calcium in solution. Clay stabilizers are used to stabilize clays, preventing swelling and permeability reduc tion, Water solutions of potassium, ammonium or aluminum salts are used. Longer term stabilization can be obtained with poly quaternary ammonium compounds. D ispersants are used to keep solids from aggregating and aid in their return. Fatty amido amines and propoxylated amines have been used for this purpose.
Acid diverters are used to improve the efficiency of the acid. Most of these are some form of an oil soluble resin. These finely dispersed solid particles are carried down with the acid, progressively block ing the more permeable streaks. This forces the acid into less permeable layers of the producing formation. Many of these resins are based on te r pene. When the well returns to production, the oil dissolves the resin and restores the permeability.
Recently foamed acid has been used. The foam reduces the hydrostatic head and may prevent frac turing of some reservoirs. The foam is more viscous, which helps di vert some of the acid to less perme able streaks. Alkyl phenol ethoxylates and fatty alkyl quaternary ammonium salts are used as foaming agents.
DENSE BRINES AND ADDITIVES
Chloride Brines. Seawater has adequate density (8.5 pounds per gallon, ppg) to contain formation pressure in many cases and is used wherever possi ble. Seawater is also used extensively to flush resid ual mud or solids from the well. As greater density is required in workovers other brines are used, [n most instances the brines are brought to the plat form as liquids. However solid sodium chloride and calcium chloride are often available for making minor adjustments to the concentration and density. Solid sodium chloride can be used for small density increases for seaw ater but m ixtures with liquid sodium chloride solutions are more common.
Sodium chloride brines are available up to about 10 ppg and are the m ost widely used purchased brine, [n addition to use as completion and packer fluids, they also are used for special purposes. Solid sodium chloride particles can be added to saturated sodium brine to act as fluid loss control agents.34 [n contrast to clay and barites used in drilling muds, the salt crystals will readily dissolve in produced water when the well is returned to production. Thickening agents (viscosifiers) can be added to improve the suspension of sand during gravel pack operations.
Calcium chloride brines provide densities up to about 11.5 ppg. Ideally these brines would only be required when densities between 10 and 115 ppg are required. Practically some operators use calcium chloride more extensively because of the uncertainty during planning as to whether 10 ppg will be ade quate. One operator used calcium chloride as a standard for all wells if densities greater than sea water density' is anticipated.
Potassium or ammonium chloride salts are used to minimize clay damage. Straight potassium chlo ride (to 9.7 ppg) may he required for especially sensitive formations, but is more expens h e than sodium chloride. Often a few percent of either salt is added to other brines to obtain clay stabilization at a more moderate cost
Bromide Brines. Calcium bromide is used for the next increment of density, up to 15.4 ppg. Because of its higher cost, these brines will often contain con siderable calcium chloride. Less chloride salt can be included as the density requirement increases.
Zinc bromide is capable of the highest density , up to 19 ppg. However it is also the most expensive and can be corrosive. 35 Zinc is also classed as a hazardous substance by the EPA, requiring special handling. Fortunately only a very few wells require use of zinc bromide. Even then it is virtually always used in mixtures with calcium bromide, sometimes
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calcium chloride too. The operating companies surveyed normally used brines containing zinc only as completion or workover fluids. This zinc brine is then displaced with a lower density brine to be left as a packer fluid and returned to shore for recondi tioning. One operator indicated that only two wells had required zinc in the last several years, none in 1988. However, other operators do use packer fluids containing zinc.
Sodium bromide (to 12.4 ppg) and potassium
bromide (to 10.8 ppg) are especially useful when the formation contains high concentrations of sulfate or bicarbonate ions. Potassium may be required if sensitive clays are present.
Brine Additives. The variety of additives used with workover fluids can be grouped according to their function.
C orrosion inhibitors are added by most opera tors. For the lighter sodium chloride brines, water soluble compounds similar to the production tre a t ing chemicals can be used. A sulfite oxygen scav enger is also commonly added. Biocides may also be added. The heavier calcium and zinc brines are more difficult because few of the above compounds are soluble in 30-60% calcium brines. Thiocyanate, thioglycolic acid and derivatives have been used. Since calcium sulfite has limited solubility one sup plier has a substituted carbohydrazine for scavenging oxygen.
Fluid loss control with completion and packer fluids is a different problem than with drilling fluids. Any m aterials added to reduce fluid loss to the formation must be easily removed. Otherwise a major advantage of brines will be lost. The use of solid sodium chloride has already been mentioned. A fine dispersion o f calcium carbonate powder is also used, but requires acid stimulation as the final step o f the workover to obtain m aximum well productivity, in both instances the object of the suspended solids is to deposit an impermeable Filter cake on the surface of the formation. The filter cake prevents loss of expensive completion/packer fluid and avoids damage to the formation.
Viscosifiers are used to increase the ability of the brines to suspend solids. These suspended solids may be the fluid loss agents above or debris being circulated from the well. However, a major use is for suspending a graded gravel/sand mixture being pumped down in a gravel packing job. This mixture must be properly placed at the form ation face to prevent fine sand and clay from being produced from the formation. If the gravel and sand become mixed during the pumpdown stage, the job has less chance of success. HEC (hydroxyethyl cellulose), gnar gum, and polysaccharide derivatives are used. Some synthetic polymers are required for higher tern peratures.
ENVIRONMENTAL ASPECTS
GENERAL CON SIDERATION S
Prediction of En vironmental Impact. The predic tion of the impact of discharge of any stream on the receiving environm ent is an extremely complex problem. The environmental sec tion of this report will be directed towards properties of chemicals and aspects of their use in offshore operations which will be pertinent to determining environmental impact. This report will not discuss the im pact itself nor conditions past the end of the discharge pipe, except for the following brief comments.
Any prediction of environm ental impact must characterize the discharge stream and the receiving environment. Both requirements are particularly demanding for discharge of produced water from offshore platforms into the ocean. The produced waters, including the added treating chemicals, are highly variable. Formation water compositions are different and treating chemical requirements are not constant. The nature of the hydrocarbon and the relative water/ hydrocarbon ratio also affect the fraction of the chemicals that will remain in the discharged water. Similarly, the relevant character istics of the ocean are constantly changing. Winds, currents, salinity, dissolved oxygen, etc. are variable. The major study at the Buccaneer Field offshore Texas is an example of the effort required.36
Laboratory Toxicity Testing. Laboratory testing of the effects of constant concentrations of chemicals on sp ecific organism s, either in static o r flow through tests, allows investigators to learn much about the relative effects o f the chemicals and rela tive susceptibility of various species to the chemicals. Conditions must still be closely controlled to im prove the statistical reliability of the results and allow meaningful comparisons between different test results. Direct extrapolation of results of static tests to other organisms, chemicals, and environments is often not feasible and can be misleading. Neverthe less, useful results can be obi.ained.37
Acute aquatic toxicity tests are the most com mon laboratory evaluation. Test organisms of a chosen species are exposed to several differen t concentrations of the chemical. The number of surviving organisms is determined after prescribed intervals, e.g., 3, 12. 24, 48, 96, 168 hours. Results are analyzed statistically to determine the toxicity- of the chemical to the organism. The most common reporting param eter is the LC50 for 96 hours, the maximum concentration at which half of the test organisms will survive for 96 hours. In general, half will survive longer at concentrations lower than the 96 hour LC50. Conversely, at higher concentrations half can only survive for shorler times.
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Round robin testing38 by three governmental., three commercial, and three industrial laboratories has shown that good reproducibility can be obtained for acute aquatic toxicity testing if a clearly defined protocol were strictly adhered to. A ratio o f only 2.6 between maximum and minimum indicated LCSQ values was obtained for the effluent for the species tested. The use of different protocols is probably a major cause of Use variability in the aquatic toxicity data presented later in this report.
It is widely recognized that short term acute toxicity tests and observations can not totally assess the long term effects of particular contaminant s or variations on the environment. Longer term factors include sub-lethal chronic effects on particular specimens or subsequent generations of the species. Longer term chrnnic toxicity testing involves obser vations on species exposed to the altered environ ment to detect changes, sometimes after several generations. Rigorous determination of chronic toxicity of a single pure chemical compound on single species is both time-consuming and expensive. Definition of the combined effects of the range of commercial compounds ansi natural constituents od the wide range of species in a highly complex and variable ecosystem such as the Gulf of Mexico would be a challenging and difficult task. It does not appear that such a massive effort is justified nor would it result in any significant improvement in the environment Kimerle39,40 has studied many acute aquatic toxicity test results for various chemicals, species, and toxicological tests.
Solubility. Solubility of the various chemicals in. water and/ or oil is an important property In use as well as in testing. In fact, definition of solubility and development o f meaningful test procedures were matters of serious concern with the specialists inter viewed in both supplier and operating companies. While test methods are beyond the scope of this paper, some aspects are pertinent to the interpreta tion and applicability of the data. Experienced chemists ears make reasonable ere! ,r: predictions o f the solubility or distribution <f pme compounds between an aqueous and liquid hydro carbon phases. However, behavior of impure mix tures is very complicated. Most commercial formu lations are complex mixtures of solvents and homo logues of one or more compounds. For example, what is the effective solubility (or distribution coeffi cient) of such a formulation if the 15% isopropyl alcohol primarily goes into the water phase and the 35% imidazoline corrosion inhibitor plus 50% naphtha solvent primarily goes into the oil? Distri bution between phases o f the com ponents in a formulation will probably be a function of dosage. It
certainly will be affected by the compositions and ratios of the oil and water phases.
The effeclS of these lands of factors on testing of biodegradability of insoluble chemicals have been called into question by Boething.-n He suggested that variability in procedures for adding and dispers ing insoluble chemicals can significantly affect test results. While Boething was primarily addressing biodegradability, it would appear that his concerns would also be applicable to aq.ua.tic toxicity testing.
Chemical characterization. Characterization of the specific chemical compounds an d /o r functional groups responsible for toxicity is highly desirable. Identification might allow objectionable components to be eliminated from a formulation without sacrific ing the functional objective, in addition, more complete chemical characterization and pertinent analytical methods would he very useful in refining eause/effect observations in site studies.
Biodegradability. The tendency of a chemical to accumulate in. the environment is its persistency. Conversely, destruction of the chemical by biological mechanisms is called biodegradation, which can be roughly measured by biochemical oxygen demand tests (BODs). Data presented by Rohichaux for biocides (see Table 5) indicated that all were de graded to near 100% of theoretical within five days, with the exception of the chlorinated phenols. The latter are no longer used because of this poor biode gradability. BODs data were available for many of the specific formulations in Table 6 for company B. Many of the formulations were nearly 100% degrad ed within five days, with most of the remainder being consumed within 20 days. Three emulsion breakers exhibited the poorest biodegradability, perhaps reflecting Boething's4! concern about testing of insoluble c.hemicals. However, it is important to remember that these oil soluble materials go to the oil pipeline rather than being discharged to the ocean.
AQUATIC TOXICITY DATA
Production Treating Chemicals. An integral part of the discussions with the supply companies was concerned with aquatic toxicity data for the various kinds of chemicals described earlier. In general, only limited amounts of such data were available. The toxicity data summarized in the following tables were obtained on a wide variety of species, account ing for much o f the variability in the data for any particular form ulation. In addition, the testing protocols may not have been identical. Because of these factors, care must be taken in making direct comparisons between specific test results. These data are, however, useful in showing order of magni tude aquatic toxicity of the various treating chemi cals. All concentrations in the data obtained from
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vendors in this report are presented on an "as sold" basis (Tables 3, 6. 7). The concentration basis in Tables 4 and 5 is not known for certain. Because considerable attention has previously been focused on the biocides, they will be discussed separately.
Biocides. Information obtained directly from the suppliers in this survey is shown in Table 3. The widely used aldehyde class of compounds exhibited relatively high I..C50 concentrations compared to the other biocides. Mixtures of other types of biocides with form aldehyde are common and appear to reduce the LC50 values to the same range as the added biocide. It should be noted that many of the
salt water toxicity tests were run on shrimp, crabs, and oysters only. In a few cases where data also included fish species, the fish appeared to be less tolerant of the biocides. The quaternary ammonium
and amine salts are significantly more toxic to fresh
water species than the aldehydes or the other bio cides used in production operations. As a compari son, two materials not used in production operations are also listed. The toxaphene pesticide is included as a reference test material by some laboratories as a control reference pollutant. The tributyltin/qua ternary is sometimes used in closed loop cooling sys tems.
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Table 4 is taken from Zimmerman and deNagy,S summarizing acute toxicity and four chronic toxicity data for several biocides used in oilfield applications (production and/or drilling). Note that their con centrations are in ppb (parts per billion), not ppm (parts per million) or ppb (pounds per barrel, a common drilling fluid unit). O ther data in their paper plus information from companies interviewed in this survey indicate that the various forms o f thiocarbamates and bis (tributyltin) oxide are not widely used in production operations. Glutaraldehyde, formaldehyde (and paraformaldehyde), var ious quaternary ammonium salts, amine salts, and mixtures of these are far more common. Acrolein has been used in some applications but its use is apparently decreasing, it is significant to note that these "production" biocides generally have higher aquatic toxicity LCSO values than the thiocarbamates which apparently are more com m on in drilling operations.
In 1975 Robichaurc42 reported the aquatic toxici ty of some biocides used in drilling and completions (Table 5). Some of these generic chemical types are similar or identical to those used in production operations.
G e n e r i c Chemical Type
LeSO * S a lt W a te r
Aldehydes Chlorinated P h en o ls*
Q uaternaries Mmirms
5 0 -4 0 0 0 .2 -' 0 .2 -5 0 .4 -4
* C o n c e n tratio n (ppm, as s o ld ) f o r S % s e r v iv a l f o r 96 h o u rs. D ata on f i s h , sh rim p .
c r a b an d o y s t e r s p e c ie s .
D ir e c t d a ta com -
p a r i s o n s w y n o t be v a l i d b e c a u s e o f d i f -
ferent sp e c ies and/or t e s t proto co ls.
* * Not u se d in o f f s h o r e p ro d u ct i o n o p e r a t i o n s
i n O . S , sin c e e a rly 1970s. C S S
T a b le 5 .
A quatic T o x i c i t y D a t a f o r S e v e r a l
( la s s e s o f B io c id e s
Direct and detailed comparison of acute toxicity data between various sources and investigators can be virtually meaniogJess unless species, temperature, procedures, etc. are similar and well defined Even with this reservation, the range of acute toxicity for the "production treating chemicals" in Table 4 is about 0.2-2 ppm. This range is about the same as the 0.2-1.6 range for fresh water found in this survey (Table 3) and reported by Robichaux (Table 5). The 2,2-dibromo-3-nitrilopropionamide (4-8 ppm) and formaldehyde (10-50 ppm) LCSO values are significantly higher. Much of the salt water acute toxicities were only determined on shrimp, crab and oysters. The LCSO values in the fish tests obtained
in this survey were neither consistently higher nor lower than those species. The larval brown shrimp were one of the most sensitive of the species tested in the Buccaneer Field study, which also included fish.
Other Production Treating Chemicals, The available data on other types of production treating chemicals from the suppliers interview ed are summarized in Table 6. While essentially all of ibis data was accumulated on specific form ulations, many o f the formulations contained only a single type of compound as an active ingredient. However, solvents and minor additives in the formulations can result in substantially different solubility characteris tics and correspondingly large effects on aquatic toxicity. Hence, this data is insufficient to draw firar conclusions on absolute toxicity of the various types of generic compounds discussed earlier. There are some gross differences and trends, however.
First, LC50 (96 hour) values for m ost o f the production treating chemical formulations in Table 6 are substantially higher than those values for biocides in Tables 3, 4 and 5, While tire same reservations on comparisons of aquatic toxicity data are still applicable, some of She corrosion inhibitors and the water soluble polyamine quaternary ammonium coagulant are clearly in the same fresh or salt water toxicity range as the quaternary ammonium and amine biocides. Second, all o f the other production treatin g chemicals are about one to three orders of magnitude less toxic. Third, available data is insufficient to represent all compounds and combinations of compounds in the multitude of formulations used for various purposes in offshore production operations.
Gas Processing Chemicals. Aquatic toxicity data for the chemical compounds used in hydrate control and dehydration obtained from the literature and from one supplier are given in Table 7. it is readily apparent that these chemicals are relatively non toxic, with LCSO values of 10,000 ppm (1%) or more being common. In tact, these compounds are often used in aquatic toxicity testing to aid in dissolving materials with limited water solubility.43 It is very unlikely that discharge concentrations of this order of magnitude would ever be encountered in offshore operations. Methanol added to any one well during a startup would be diluted by produced water from other wells prior to discharge. However, one area of particular concern to the operating companies is the potential use of methanol for hydrate control in deep or northern waters where the water is always cold. Continuous methanol addition could be neces sary, especially if the subsea flowlines were long.
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Table 4. Aquatic Toxicities and Recommended Application Concentrations for Chemicals in the Host Uidely D istributed Biocides in Calendar Y ear 1981 *
n araldriaa t denyde
C ly c o llc Acid C iutstaidibyd"
l*'ST gPOT 1
5secuE r c M i c i r i F S
'<%r!h3 * *
2.000 tl
SS 1 S3 IT
**> ;ia <3 a v a i l a b i a
5, filo f
0OfST Z i & W t O
CHSdWK: t f o j n c i m s *
i\o vn
Z Ff m d* t a a v a i 1a& 5
ECAT'S OK
3 , 3 t o J O i b . p e r U K t e l tSVO-lXO P*b c o n tin u o u s 0.1 to 0 25 I l l s / b a n e ! H 3 0 -3 0 S
Ini l i a i
10 pia,
Z i U t i & m ireacsen? - u iS coni
S ilio iTestWWst - 500 pp*. covili no ou
~ 50 ppi
d s y d i e t b y i e i s e 31 s
top du t a a v a i l a o i a
*
(aiifeyi d tstechyi 3
4siof3ia cbissf id e )
I <a i k y l a .1n o i - 3 a.ln o o ro o n n e SCSSatC
240 Ff 120 eu
CS UonOi innfoeya*Inntesr-seta**5?*00 -p p *50. pp
2--a i Kcnty-
l-ltyiirdsyprooy i
* r i t ? 3 y :i & m m n i v .
c h lo rid e
35 8 ** F3:
soPUii a i * t f t v t - *
i <t n i n e a r s aw t. 0
1 ( a.Uty.la.lno]
5
3~dtii088fdpan
otassfu ^ j R c t f t y i d i *?3 p carpasele
i 2 7 .} 1 2? Mi
^3 data 5vs iad !
85 fF t S3 f I
31 SOtSIU* cyar>ohit5iiuiPcarbotiste
2-( thl oeyariow etbyi tbJ oi D e n z o t h ' a z o 1e
i- ( a lf e y ta b io ) 3 - a .in o orpoAne dfpate
i d e a s s i ttf* 3 1 th y i d I t h l 0_ pgroviffesre
%SO f f
542 FI
2? Ff
5 DO FF 2 3 0 -* a s *1
J-n ltrilipropidii3*i0
A.eiip s c ld
* ik.y U h a ! -*
so ry jeeh id a ?0
S l s ( t r i b u i v i t l.ni olii i d e '
m da,** ava t u p l e
U3 33*3 v a i id f e i
3 . 3^ ta
43 4)
m mm
i ltbiU
3 1
Mts d a t a a v a l u o t o
n*> m m a v a i m t i a
*a$*ffloctd i sa il w aist disposal sy stem $0~ui9 a m ednuououd as I l r s t . ro n d w -o p tin
0 -1 5 p p * c o n t i n u o u s ? p * t a i t u a * ft c o n t r o l . sway & l e d i m e r i t e n i i y 3 i 3 r a t e o f $ 8 - 2 0 0
p m l o r 4~># M s , a d a y . o n e t o l o u r t l m s 3
1 p i n 1 to i Q u a r t a r 1000 P a c t a i s i 3 ~ 3 PP1 .
i p i n t to i s w a r t p a r 1000 u t r e u <)- 6 p m i ,
$ t p r r e s t e d g ' ? , s t o 3 a . o z . p e r - J . o o o 54*. l i t 5
.') f o n t ) . s u s e s o e f u t r e a t 01 0 . 5 t o 3 . 0 a o x .
p e r 1. POu ga i , ( t , G
p p p p . ) s i to i d p e sw.cie e v r y 1
o 3 day S .
M a g t r e a t n t i $ to 3 II . o z p a r i,3<30 g a l . ( . 1 1 . 1 23 ppaO., s u a s e s u a n ? : t r e . a t m o i 0 5 to 1 .0 J 1 o z c a r 1 .0 0 0 g a t , ( 4 , 8 - 2 3 P m i s faxt* d S e * a d e v e r y i t o s. d a y s
for secondary rcovet y : O.l to !3~>0 p p ! , For g r i l l i n g aud: v o n m 01 iat e s a i ,
oz p e r 1 .0 0 0 -gai.. to 5,2$% 0 1 to r s i
f o r i e e o f t & f y r e c o v e r y : i f i l d a i t r e a t * a' S u 3 l o 25.* n o z per UOPO g e i , CSS-?* eg* , L i subsegM ent
p r e 4 t ? e f l t : u s e 3, a t o ) .2 H . 02. p a r 1 . 0 0 0 $ 4 : . 5~ i 3 p u s
f o r i e c n n d a r y r e c o v e r y ; g , S 3 10 1.66 U . o z p e r 100 p a r r e i * ( 6 - l J p p # * i. F o r a r i i U n o * w i 0 6 t o s . 001.1
p a r 100 P a r r e i i i 4 2 ? u p p * ,
C b n t . i n u o a s f e e d i n i t i a l t t e a n w e m : #j s l c o 2: , 2 n .
o z . 01 a t d * K t p e r 1 . 0 0 0 g , 0J w S S f (2__16 p y a . 1. J
S u s s i s t e r t i Sy, u s e 0 . 1 t o i , s II o z o f g o m i ti c i p a r
1 1 .0 0 0 54i , < 0 . 1 - I p o s . i , } . F o r i n t e r a l t e n s
t r e a t * : 3 * ; & p p d
F or s i p g s r e a E m s t * 8 P d .1 i
n tir ppb is
iai pares
Fs f r o J t e l e r e n o e 5, i i i # e r 5 n . g , a n d d e N a ^ y , I P * i3r3.fi p a p e r, t f i H
p e r P i i K a m p re s w s s g b iy try * s ti g i l t , cevt
S " -S i O c l d e s s>134.
i n MS o n f f s i w
01 1 3 5 CS P l a t t e r 5 a n d
* ;p ir
r o x f c is y 53S3 lo r; fi - ? re s n * 3 t r invar te p ra s e FF > f r e s h w a t e r F i s h
1 .ts a rin e ; v e rt e s r a t e
- sa f i n ? i s h
5>0<.ueTUd p S i d t i Sit a n d d i v e r s i r o * t h e 81 s c f t a r 01 t h i s c M w c p a i d u t i n o t h e 8MCC3d f F t p i d s t u d y .
C?!:! 1C3 i Ju u s e o n o U s h o r e p i a t t o r n s P a s e o n 30 p i a t i d - r w s t u d y t u five C J r l 0 J * * x ic < 3 .
Cftdisidai i p p r o v a i t o r u se on p r o d u c tic n j o i a s t o r * In l a s s a t o c u o s t e d Ivo. ttep . x Py a n u h d C iP tC f
C h e ( t c 3 i i n u s o n d r i H l n g r i ou a n d s i a t i P t i f c S a a s i d d o n ? 4 w e l l s u r v e y i n C u t i 0 1 4 x ; c q ;.
Sierra Club v. EPA 18cv3472 NDCA
38 Tiers 8&9
ED 002061 00130976-00076
Table 6. Acute Aquatic Toxici ty IM a (1CSO) of Other Production Treating Chemicals 'i .2
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CONTINUED
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00077
T a b le 6.
A c u te A q u a t i c T o x i c i t y D a ta (L C S O ) o t O t h e r P r o d u c t i o n T r e a t i n g C h e m i c a l ' (1 . 2 ) CONTINUE D - - -
<2 '2*057 i C&esfieai Type
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treu r
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Table 7. Acute Aquatic Toxicity Data (LeSO) of Treating ChemieaLs *
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sew soe b n d e r J a
Sierra Club v. EPA 18cv3472 NDCA
38 Tiers 8&9
ED 002061 00130976-00078
Stimulation and Workover Fluids. Essentially no data were obtained on the aquatic toxicity of any of the stimulation or workover fluid chemicals. The various companies contacted indicated'that neither they nor their suppliers had run any such tests. No useful data was found during the literature search. A limited amount of pertinent data were included in a recent summary of toxicity of drilling fluid addi tives50- These data were taken using the protocol specifically designed for drilling muds (40 CFR 435, 26 Aug. 1985) and the concentration basis and re sults are not comparable to data presented in this report. Those materials likely to be used in comple tion or packer fluids appeared generally to have LC50 values well above the 30,000 ppm limit ap plicable to drilling muds and that protocol, indicat ing they are environmentally acceptable,
PRACTIC AL ASPECTS
System Effects. The fraction and concentration of various chemicals in the effluent water depend on several factors. For example the point wdiere a production treating chemical is added is important. Corrosion inhibitors added to gas pipelines are carried to shore and removed at the processing plant, usually being sent to disposal wells. Scale inhibitors added to offshore water treating equip ment will primarily be discharged with the water. The solubility characteristics of various formulations (while usually not precisely definable) are generally such that almost all of the formulation is expected to go either to the oil or to the water phase. Notable exceptions are low molecular weight alcohols and glycols added to oil soluble formulations (to provide low tem perature protection and drum stability) which will normally partition into water.
Specifications on the water discharges and on oil sales pipelines affect the overall disposition o f chemicals. Surface discharges of water are restrict ed to a monthly average of 48 m g /1 total 'oil and grease", of which only a liny fraction (e.g., 20-100 ppm in that oil) would be oil soluble treating chemi cals. On the other hand, oil sales specifications usually allow 0.25-1.0% (2,500-10.000 ppm) water in the oil. Thus, more of a water soluble treating chemical can be carried with the oil. Furthermore, a significant (albeit unknown) fraction o f the water soluble chemicals with surfactant properties will tend to collect at the oil/water interface in separa tors and in the shimmings or froth in the water treat ing equipment, usually being carried along as a part of the allowable water in the sales oil. The effective concentration of water soluble treating chemicals in this water is thus likely to be substantially greater than in the bulk w ater phase being d isc h a rg e d , Thus, less water soluble chemicals will be discharged than might otherwise be expected.
Production Treating Chemicals. The environmen tal aspects of the various types of production treat ing chemicals will he briefly summarized in the same order as presented earlier.
The required scale inhibitor concentration of 3 10 ppm is far below the ASO values of 1000 ppm or greater. Although none of the operators contacted used squeeze treatments offshore, such treatments
potentially could lead to initial high discharge concentration immediately after a treatm ent. The peak return concentration from a well conceptually could be the same as the injected concentration (2 10%). More likely it will be diluted by at least five to ten times by the flush water and by produced water from other layers within the same well. Thus, a peak slug concentration from a well would proba bly not exceed 1% (10,000 p p m ) from the well, dropping rapidly to a few hundred ppm within a few days, depending on the producing rate. All of the wells producing into a single production separation system will not be squeeze treated at the same time. Hence, the combined discharge water stream will have a substantially low cr concentration of scale inhibitor than from any individual well. Even a 10:1 dilution by other wells drops the peak concentration to the same level as the LC5Q values. Continuing developments in squeeze technology, e.g., precipita tion squeezes,21 allow longer treatm en t life with better chemical utilization (lower peak slug concen trations). It is apparent that discharge concentra tions of scale inhibitors are below LC50 ranges.
Corrosion inhibitors exhibit a wide range of
aquatic toxicity. The most commonly used inhibitors are predominantly oil soluble, with many having
LC50 values o f 20-500 ppm. This is equal to or greater than the normal continuous dosage of 10-20 ppm. However, others have LC50 values below 10 ppm and have greater potential adverse effect when
discharged. Peak concentrations o f 1000 ppm from batch-type treatments may be seen from individual
wells but would be diluted by other wells. Further more, a large percentage of the inhibitor compound probably goes into the oil phase and is not dis charged with the water. The lower molecular weight formulation in Table 6 is classed as oil soluble, water insoluble, and is primarily recommended for contin uous addition into gas wells. Hence, its treatment
concentration will be relatively low (e.g., 20-50 ppm
maximum) and essentially all would go with the hydrocarbon condensate or produced oil. The phenanthradine formulation contains a surfactant to allow the concentrated inhibitor to be dispersed in water for treatm ent but only be oil soluble after application in the system (continuous injection in gas wells), The water soluble inhibitors are significantly more toxic, probably because they are o f the same
generic type as some o f the biocides. However, these inhibitors are not applied as squeeze or slug
Sierra Club v. EPA 18cv3472 NDCA
.39
Tiers 8&9
ED 002061 00130976-00079
slug treatments. The ammonium bisulfite toxicity is probably totally due to the scavenging of all dis solved oxygen and would.be completely negated by a 1:1 dilution with aerated seawater at discharge. With the exception of the water soluble inhibitors, the combination of high oil solubility and low proba ble concentration indicates that most corrosion inhibitors will be near or below their LCSO values.
The biocides are the most toxic of the various types of production treating chemicals. The applica tion concentrations for the commonly used for maldehyde and glutaraldehyde formulations are generally in the same range as the LCSO values in Tables 3 and 5 (10-400 ppm), although Zimm erm an'sS values (Table 4) are significantly lower (2 ppm). Acrolein is more toxic but is also
more reactive and can be neutralized with bisulfite prior to d is c h a rg e ^ . The chlorinated phenols (Tables 4, 5) are no longer used in U.S. offshore operations. Quaternary ammonium and amine salts have lower LCSO values than the aldehydes but can become deactivated by adsorption onto surfaces of suspended solids particles 6 The remaining biocides (thioc-arbamates, etc.) also had low LCSO values (Table 4) but constituted only about a sixth of the products in use in the Thirty Platform survey.6 Because o f high water solubility, relatively high concentrations daring batch treatments, and proba ble treatment of the Ml. discharge stream, it appears likely that discharge concentrations will equal or exceed typical LCSO values in many instances, al though some o f tlie biocides can be deactivated by solids or specific treatments.
Emulsion breaker toxicity data were provided by Company B for three formulations with a single generic compound. An alkyl aryl sulfonate showed an LCSO 7-10 ppm for the species tested. The oxyalkylated phenol formaldehyde resin formulations showed 4-3-0 ppm, while the oxyalkylated dipropyl ene glycol had a 40 ppm LCSO for a fresh water species. Formulations from the other suppliers were in the same order of magnitude, even when mixtures
of compounds were present. With a normal maxi mum treatment rate of about SO ppm (based on oil) and at least 90% going with the oil, only 5 ppm or less of the total formulation would be carried over into the water. This concentration is at or below the LCSO for most of the available data.
Reverse breakers, coagulants, and Oocculants are similar in chemical composition and application. The limited toxicity data indicates that LCSO values are relatively high in comparison to use concentra tions (1-10 mg/1) except for the polyamine quater nary' ammonium formulation. Ironically, that specif ic formulation is also approved for use in municipal water treating plants' All three types of chemicals are expected to aggregate on the surfaces of oil droplets or solid particles in flotation cells and will
tend to be carried with the oil shimmings or froth and be recycled to the oil streams. The concentra tion of chemical in the effluent water will be sub stantially reduced. In fact, if more oil or solids were red isp ersed in the same water, another dose of chemical would be required to achieve separation again. The concentration of chemical is apparently too low to be effective. Aluminum and iron salts are the more commonly used inorganic agents with LCSO values (for the ions) of 10 and 21 ppm respec tively for crustaceans4(p2Jll. Zinc salts are also used, with LCSO values of 0.1-60 ppm for a number of species4(p234j. Based on the relatively high LCSO
values and the strong adherence to particles and oil droplets, discharge concentrations for most will be near or below their LCSOvalues.
Antifoam aquatic toxicity data were available for two materials. The norm al treating concentrations 0.2-2 ppm in water, 5-20 ppm in oil) are lower than the LCSO concentrations for both of these formula tions. Toxicity' data were not available on the two classes discussed earlier. It was pointed out. howev er, that both the silicone and polyglycol ester generic compounds do have applications in tire food process ing industries.
Surfactants used in offshore cleanup operations are usually very similar chemically to those used in household detergents and other industrial cleaning formulations. The indicated LCSO values are mostly above 50 ppm (Table 6) for the two primary' generic types. Since these materials are primarily used for required housekeeping and maintenance purposes, it is difficult to suggest a discharge concentration. However, such uses are certainly Dot a continuous o r
every day activity. Paramn treating chemicals, both inhibitors and
solvents, would be expected to go with the oil. It is unlikely that significant quantities would be carried with the ernuent water,
TreaJrnent/TVxjcity Sununary. T reatm ent
dosages, system dilution ratios, and LCSO values of the various functional types o f production treating chemicals have been presented. The variation of each of these factors has been discussed. Table 8 has been prepared to tab u late these variables, recognizing fully that it is a simplistic, general summary. The "discharge cone: is an estimated concentration range in the discharge pipe. The top group are all water soluble and expected to be primarily in the water phase. The biocides are the only type where the discharge concentration is likely to be above the LCSO values, and then only for periodic short durations. The corrosion inhibitors are the most complex type, as com pounds and formulations are made to be water soluble, oil solu ble. or mixed solubility / dispersibility. The water soluble compounds are most likely to resemble the biocides chemically. These inhibitors are most likely
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00080
to be added to injection water or gas pipelines and not be discharged to the ocean continuously. The oil soluble corrosion inhibitors will be at or below the LC50 -value, except possibly for short periods after
F u n c t io n Type
Is e C o n e ,
ppm
D is c h i rg e C o n e , p p ra
LC 50 ppn
S c a le In b ib
3 - 10 50 0 0
X o rm a i Squeez e
3 -1 0 5 0 -5 0 0
1 2 0 0 -> 12 00 0 90% > 3000
B io c id e s
1 0 -5 0 F o rm a l 1 0 0 - 2 0 0 S lu g
10 -5 0 10 0 -2 0 0
0 . 2 ->1 0 0 0 90X > 5
R e v e rse B re a k e rs
1-2 5 N o rm al
0 .5 -1 2
0 .2 - 15000 90% > 5
S u rfa c ta n t
??
C le a n e rs
0 ,5 -4 2 9 90S > 5
C a ro is ; on In h ib ( 1)
1 0 -2 0 W a te r
1 0 -2 0
O il
5000 S queeze
5- 15 2 -5 2 5 - 100
0 .2 -5 . 90X 1 2 -10 0 0 .
90% > 5
E m u ls io n B re a k e rs
SO
o il
0 .4 -4
4 -4 0 , 90% >5
P a r a f f in In h ib
5 0 -3 0 0
0 .5 -3
1 .5 -4 4 90% > 3
( I ) " W a t e r 1* i n d i c a t e s a w a t e r s o l u b l e i n h i b i t o r , n o t u s u a l l y s q u e e z e d o r s l u g . " O iL II i s m o s t ly o i l s o l u b l e . " S q u e e z e ^ i s iiia x m m m c o n c e m t r a tio n in r e t u r n s a f t e r s q u e e z e o r b a tc h .
T a b le 8 . R tu g h C o m p a r is o n o f U s a g e , D is c h a r g e ,
a n d 1 eSO (9 6 h o u r ) V a lu e s .
squeeze or batch Treatments. The predominantly on soluble emulsion breakers and paraffin inhibitors will be at or below the LC50 values, except possibly for short periods after squeeze or batch treatments. The predominantly oil soluble emulsion breakers and paraffin inhibitors will be at or below their LC50 values in the discharged water.
Overall Consumption Estimate. Unfortunately, data are not available on the total quantity of these various treating chemicals used in offshore opera tions. Most of the operating companies apparently do not summ arize or report the amount of these chemicals used in their operations. The chemical supply companies are not always sure where their chemicals are actually being used. Hence, only rough estim ates can be made for total chemical usage.
Two of the participating operating companies determined usage of production treating chemicals in their operations during 1988. As pointed out earlier, distribution of the chemicals between oil and water streams is an educated guess by the operating and chemical company specialists and the author. These data are summarized in Table 9.
While the absolute and relative consumption of the various types of treating chemicals will certainly
vary between operating companies, the major uses are probably indicated with reasonable accuracy. Of the total estimated 1988 usage, only about 40% (138,070 gal.) are expected to be water soluble, with perhaps about a third actually going to the water phase. Only about 7,828 gal. of the estimated usage of 3,077,791 gal. are biocides, the chemical with greatest potential risk to the environment.
A substantial fraction of the material going to the water will be consumed in performing the specific function, i.e., corrosion inhibitors adsorbing ooto steel surfaces, scavenger reacting with oxygen, bio cide reacting with bacterial cells, etc. Thus, the overall fraction of treating chemical actually ending
up in the discharged water will be about 2570 or less, although the exact fraction is not known.
A total estimated 1988 chemical usage-for the Gulf of Mexico is also shown in Table 9. The opera tions covered by this specific data produced 8% of the gas, 11% of the oil and 17% o f the water from
7% of the wells in the Gulf of Mexico. Since it is not obvious which percentage would be most appropri ate for estimating the total usage, the average of the four (11%) was used.
The total estimated volume o f 3,077,791 gallons of chem ical p u rch ased per year corresponds to about 8,432 gallons per day (gpd) About 3,439 gpd
Treating P r o d u c t i o n
C h e m ic a l U s a g e
CHCALS LSSii?, CIS CANONS
j-40 0G0a0s
preOpudros.d..
*SSP*
5 ,,$35-755643
2 2J2mU476
SUBiT.O475T42A45L J,91T
2.5,332T3.,O..34&5T26A>M56L4?
sFeUaJI*Cr*mTiObNlfor
SUAiUTY 0 00
{!.4760
a . 9990
22.,4?40 gins2t9a5te.2d1*
Corlorohis&ioinfer
mer
0 00
J8s,.554690 2&9.8I9ZQ& 85*4.9$7504
5.9J50.$JJ68
000
1!0 7.?24157- 7*5224. 2,227
isY#'5
wo*"*? *.7910 $<$,.26960 61S.6B&39 55754.7J255/
Scavenge?s w00a0ter
0
0
0 0
00
Cucrsiaseantaernss . 0
.2900 2.1829 21:452 195.01&
ftsiiiii&n. 83F 5 0 0 0
04,750 26.50629s 4?,256773 552?..3t59S1
parcsoBnBttino[
m tet
000
$4 5430 51130 65.J25
0
Toettatlei<EaI5 wo*s&*%intzr nv?4s'$. ,.271413?7 ?94t..&?4554J5 J21J30&&0...405&754707f >1%J.0&2752725..7,0I90B*19S{
B1B.0Q0u0id00p0rt:o(-jCtlaon15I.nJJO?ti5riPoYn:s`O0l-00g0!K-ypy . 'B52.000 '00 ysss# aS iCi%Kiafritcrt-o.smai*zz 40* 5$5*$6wsteS3xt.comoailfes'
Table 9 .
P r o d u c t io n T re a t in g C h e m ic a ls U s e d
i n the Gulf o f M e x i c o d u r i n g
19 8 8 .
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00081
goes in i:o the water phase, with an even smaller volume (estimated 2,100 gpd) actually being dis charged to the Gulf of Mexico, This volume of chemical is diluted with about 63,000,000 gpd of produced water, for an average discharge concentra tion of about 30 ppm. This total volume is distribut ed through many widely scattered discharge points.
Gas Processing Chemicals. Data on consumption of the gas processing chemicals were obtained from two companies, which had very different processing requirements. Company 1 processed very little gas offshore, perhaps less than 10% o f the 320,000 MMSCF produced in 1988. Their consumption of 6,316 gallons TEG and 17,652 gallons of methanol is relatively low but. meaningless without definition of the quantities of gas actually treated Company 2 consumed 52,833 gallons of TEG in dehydrating 90% o f th e ir 79,500 MMSCF gas, or 0.74 gallons/M M SC F, This averaged about 11 gallons/ day for each dehydration system, essentially all o f which carried over into the gas to shore. None of their systems were changed out in 1988 Hydrate inhibition required 370,049 gallons of methanol to treat about 39,000 MMSCF, mostly during the cooler part of the year. This treatment rate averages just under 10 gaiions/MMSCF,
It is not felt that the available data warrants any estimation o f total consumption of gas treating chemicals. However, some significant observations can be drawn from the Company 2 data. It is appar ent that the TEG losses to the gas pose little envi ronmental risk. Even if all the TEG were carried into a proportionate amount of their produced water, it would only amount to 28 ppm, far below the LC50 of 10,000 ppm or more. Even the larger volume o f methanol amounts to only 357 ppm if all were dissolved in 49% o f the produced water. Again this average concentration is far below the LC50 values of 10,000 ppm or higher. Furtherm ore, a substantial portion of the methanol will end'up in
the gas and oil phases, not in the water. Since the methanol concentration in the water must have been in she percentage ranges so provide effective inhibi tion, a high degree of dilution occurs prior to dis charge. Obviously such generalizations and averages can be misleading, but the gas treating and process ing are rather uniformly scattered throughout the Company 2 operations. It seems very' unlikely that the gas processing chemicals will pose a risk to the environment, but use of methanol will require evalu ation for platforms with little or no produced water iO>dilute the treated condensed water.
Stimulation and Workover Chemicals, Moore9 recently compiled a summary of well service activity for the oil production industry in 1988. The survey provided a breakdown as to types o f activities and
geographical area. While it is difficult to be sure that the various classifications are consistent with those used by the participants in this current survey, Moore's data provides a solid basis for a reasonable estimate of total chemical consumption. Pertinent statistics from his summary are shown in Table 10. As noted, the offshore Alaskan data were not broken out.
It is apparent from Table 10 that over 80% of the offshore wells in the US are in the G ulf o f Mexico, partial justification for the heavy emphasis of the area in this report. About 2% of the wells are being stimulated by acidizing each year, with another 2% being completed or recompleted. Most of the artificiallift repair work will be performed on gas lift wells, which usually does not require pulling the tubing or using brine kill fluids. Repair of tubulars (1-2%) will require pulling the tubing, but m ayor may not require using kill fluids.
Acidizing chemical data were obtained from all four companies covering at least part of their opera tions (Table 11). The data covered operations of 1,666 wells in the Gulf of Mexico, or 16% of the total wells. The 145 acid jobs represents 56% of the total jobs reported by Moore. The 259 total jobs per year corresponds to about five per week in the Gulf of Mexico. The various concentrations and types of acids were converted to the equivalent volume of
W E L L S E R V IC IN G A C T IV IT Y
Gulf o f
M e x ic o
O ffshore
C a l jf.
l T o t a l W e t S
10 6 14
2090
A la s k a s 355
S t im u la t io n
259 ( 2 . 4 )b
28 (1 . 3 )
3 (1 .6 )
C iW ip l o t i o n s
16 2 (1 .5 )
A rtificia l Lift
I n s t a ll, R e p a ir
14 0 1 (1 3 .2 )
36 1.. 7 1
180 (8 .6 )
30 (8 .5 )
53 (1 4 .9 )
T u b u la r R e p a ir
91 (0 .9 )
44 (2 .1 )
5
(1 .4 )
T o ta l Jo b s
% Wet i s
19 17 (1 8 .0 )
288 (1 3 .8 )
86 i 2 4 .0 )
Reeoraplet t o r t s ,
N o t in c lu d e d
320 (3 .0 )
24 (1 . 1)
3 (0 .8 )
a.
E s t im a t e o n ly
b ased on 2 5 S o f w e l l s a n d
s e rv ic e o ffs h o re
Data n o t b r o k e n i n t o
offshore/onshore c a t e g o r i e s ,
b. V alues in p a re n th e sis are percen t o f w d L s
in r e g io n .
T a b l e 10. Summary o f O f f s h o r e S t i m u l a t i o n a n d Wcrkover A c t iv ity in the U .S .
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15% hydrochloric acid, based on available hydrogen ion. The conversion did not take density differences or chemical activity coefficients into consideration.
The total acid used in the G ulf in 1988 is esti mated to range from 541,000 gal. based on number ofjobs to 1,890,000 gal. based on number of wells. The average job was about 2,000 gal. Most of this acid will have been reacted downhole, but some
small, unknown fraction will be discharged. Residu al acidity is apparently not routinely measured by the operators. This spent acid will be commingled with produced water from other layers in that well and further diluted with produced water from other wells before it is discharged. The corrosion inhibitor would be partially adsorbed in the formation as well as being similarly diluted. It seems unlikely that
small amounts of remaining acidity, the corrosion inhibitor, or the calcium and iron reaction products would cause any adverse effect. Larger amounts of
unreacted acid could cause a significant temporary pH shift in the vicinity o f the discharge.
Workover nuid usage was less well defined. The distinction between drilling and workovers as de fined in this report does not necessarily match other
definitions in the industry'. Records for the operat ing companies apparently do not summarize the quantities of brines used for either. In many in stances the brines used are mixtures, so purchases of specific materials may not be directly related to volumes used. Furthermore, dry' salts are often added to purchased brines to make fine adjustments to density' or compensate for dilution by produced
A C ID IZ IN G
IN T H E G O L F O F M E X IC O
C c w p a n y /A re s
i
2
3
4
Total
N u sP e r y e t is
358
Ho. A c i d Jo b s
19
X Acidized
5 .3
386
19
4.9
600 80
1 3 .3
322 27
8 .4
16 6 6 14 5 8 .7
A c i d s U s e d , eq u iv alen t gal 1 5 % H C 1
Hydroch lo r i c H ydrofluoric
A e e t; c
T otal Acid Average J o b
10 74 1
0 0
10 74 1
565
4 6300 8363 366 0
58 32 3 3070
16 8 0 0 0
6 13 2 0
0
229320
2867
4 509
0 0
4 509
167
229550 69683 366 0
30 2 8 9 3 2089
T a b le it .
Summary o f A c i d s U s e d
in S t if m il a t io n
in t h e G u lf o f M e x i c s
water. Many wells only require seawater to contain the pressure.
It is not felt that the data are sufficiently defined to make any estimates of total consumption. Yet some significant conclusions can be drawn from the information submitted by three companies. Compa ny 1 purchased only 44.683 galloos total brines for their 358 wells, but noted that seaw ater was ade quate for most workovers. Company 2 provided
data on amounts o f purchased chemical and number of johs (28 on 386 wells) involving the brines (Table 12). Company 3 provided estimates on the approxi mate num ber and types of chem icals used for an average size job (8400 gaL) in an average year (85 jobs on 600 wells); zinc salts had apparently only been used on one or two wells in their entire operat ing history'.
The combined data for these three companies indicate that more than 95% of the workover fluids will be seawater, sodium chloride, or calcium chloride
Com pany B r in e
2
3
u s GaL.
%
Jo b s
%
Sodium /Potassium C hloride 4 9 8 , 9 6 0 5 7
Calcium C h l o r i d e
1 7 4 ,0 4 8
20
Calcium B rom ide/C hlorid e 1 4 9 . 9 4 0 1 7
Zinc/ Calcium Bromide
5 4 ,0 5 4
6
Total
8n, 002 1 0 0
57
67
19
22
9
11
<1 < 1
85
10 0
T a b le 12 ,
Summary o f D a t a o n D e n s e i n the G ulf o f Mexico
B r in e s
U sed
brines. Some potassium chloride or occasionally some ammonium chloride may be added to mini mize clay swelling. The seawater already contains about 19,000, 10,500, 380, and 65 ppm o f chloride, sodium, potassium and bromide ions respectively. Thus only zinc or very- high concentrations o f bro mide ions are o f major concern. The zinc bromide brines are used in very few wells, probably less than 1% overall, and are normally displaced and returned to shore after completion operations are finished. The brines containing calcium brom ide are used slightly more frequently, perhaps a few percent. Of the additives that might be present in the brine, only biocide seems likely to pose any significant risk. Mixing with produced water from that well or other wells will dilute the brines substantially prior to discharge.
SUMMARY
Treating chemicals can be and are used for a number of different purposes in offshore oil and gas production operations. These chemicals are normal ly only used in response to observed operational problems. Required doses are usually minimized based on results of monitoring programs and opera tional results. Most of these chemicals are proprie tary' mixtures of complex compounds. Alternative technology is being used in many instances when appropriate, but chemical treating is often the only effective approach.
Evaluation of pertinent data and practices indio cate that ooly low concentrations of the productioo treating chemicals in the produced water will nor-
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ED 002061 00130976-00083
mally be discharged. Many of the commonly used chemicals are oil soluble, with perhaps only a fourth of the total production treating chemicals used actually ending up in the effluent water discharge stream. Comparison of available aquatic toxicity data (96 hour LC50) and use concentrations indi cates that most of the chemical concentrations in the effluent stream will be at or below the LC50 values prior to discharge to the ocean.
The gas treating chemicals are used at higher concentrations. The dehydration chemicals are used in closed systems and rarely reach the discharge stream at all. Methanol used as a hydrate inhibitor may be discharged with the produced water at higher concentrations than the production treating chemicals. However, the LC30 value is much higher.
Disposal of stimulation and workover fluids is not a routine occurrence. Only about 9% of the wells were acidized in 1988 in the Gulf of Mexico. The acidizing chemicals conceptually could cause a shortterm lowering of the pH near the discharge
point if substantial volumes o f unspent acid are
discharged without neutralization. The dense sodium and calcium brines used in workovers will not pose a significant risk after even minor dilution. The zinc bromide brines have the greatest potential impact, but are not commonly used and are banned from discharge. When displaced from a well, they are returned to shore for cleanup and reuse. Aquat ic toxicity information on the additives used in stimu lation and workover fluids are veiy limited. Howev er, it appears likely that most will have similar toxici des and use concentrations to the production treat ing chemicals.
REFERENCES
1 Federal Register, "Issuance.of Final General NPDES Permits for Oil and Gas Operations in Portions of the G ulf of Mexico". Vol. 46. No. 64, Friday, April 3, 1981, p.2Q284.
2 Federal Register, "Issuance of Final General NPDES Permits for Oil and Gas Operations in Portions of the Gulf of Mexico", Vol. 50, No. 144, Friday. July 26, 1985, p.30564.
3 Federal Register, "Issuance of Final General NPDES Permits for Oil and Gas Operations in Portions of the Gulf of Mexico", Vol.51, No.131, Friday, July 9, 1986, p.24897,
4 M iddleditch, B.S., "Ecological Effects of Pro
duced Water Effluents from Offshore Oil and
Gas Production Platforms", Ocean Management,
Vol, 9 (1984) p. 191 -316.
"
5 Zimmerman, E. and deNagy. S., "Biocides in Use on Offshore Oil and Gas Platforms and Rigs," EPA Draft Paper, April 11, 1984.
6 API Biocide Task Force, "Use of Biocides in Oil and Gas Production Systems: submitted to EPA, November, 1985.
7 Hudgins, C.M., "Chemical Treatm ent of Pro duced Fluids in Offshore Oil and Gas Production Systems". Offshore Operators Committee, 1985.
8 Watkinson, RJ., and Holt, M.S.. "Biodegradabili ty of Produced Water Effluents", p .165-74. in Microbial Problems in the Offshore Oil industry. Proceedings o f cm International Conference organ ized by The Institute o f Petroleum Microbiology Committee and held in Aberdeen in April 1986. Hill, E.C.. Shennan, J.L., and Watkinson, RJ., Eds. Published on behalf of The Institute of Petroleum, London by John Wiley & Sons, New York. 1987.
9 Moore. S.D., "Well Servicing Industry Finds Slow
Growth", Petroleum Engineer International" (July,
1989) p,16.
'
10 Shirona, G., A m e r i c a n P e t r o l e u m In stitu te, telephone, August 31, 1989.
11 Kasuiis, Po. Energy Information Administration, Dept, of Energy, telephone, September I. 1989.
12 Walk, Haydel, and Associates, Inc., New Orleans, LA."Potential Inpact of Proposed EPA BAT/NSPS Standards for Produced W ater Discharges from Offshore Oil and Gas Extrac tion Industry". Prepared for the Offshore Opera tors Committee (Jan. 1984), Table 2,3, p.2-6.
13 Redweik, R J., Shell Offshore Inc., telephone. Sept. 19, 1985.
14 Wedel, F,, "Workover and Completion Fluids", presented to Region X, Seattle, WA.
15 Stiff, H.A., and Davis, L.E., "A M ethod for
Predicting the Tendency of Oil Field Waters to
Deposit Calcium C arbonate" , Trans. A IM FI,
Vol.195 (1952) p.213.
'
16 Oddo. J.E. and Tomson. M.B., "Simplified Calcu lation of CaC03 Saturation at High Tempera tures and Pressures in Brine Solutions", J. Pet. Tech. (July 1982) p.1583.
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17 Skillman, H.L., McDonald. J.P., and Stiff, HA., 'A Simple Accurate Fast Method for Calculating Calcium Sulfate Solubility in Oil Field Brine', A P I Paper 906-14-1. Presented at the spring m eeting of the Southwestern D istrict, API, Lubbock Texas, March 12-14, 1969.
18 Templeton, C.C., "Solubility of Barium Sulfate in Sodium Chloride Solutions from 25C to 95C*f J.Chem.Eng.Data, Vol.5, (Oct. 1980), p514.
19 Jacques, D.F, and Bourland, B.I., "A Study of Solubility of Strontium Sulfate," J.Pet. Tech, (April, 1983), p.2.92.
20 Vetter, O.J.G. and Phillips, R.e., "Prediction of
D eposition of Calcium Sulfate Scale Under
Down-Hole Conditions", J.PA. Tech. (Oct,1970)
p 1299
'
21 C arlberg, B.L., "Precipitation Squeeze Can Control Scale in High Volume Wells; Oil & Gas Journal (Dec,26. 1983) p.152,
2.2 Nathan, c.e., Ed., Corrosion Inhibitors, National Association of Corrosion Engineers, Houston (1979) p.7.61,76,83.
2.3 Bregman, J.I , Corrosion Inhibitors, MacMillan Company, New York (1963), p.197.
24 Kelley, 1A ,, "The Chemistry of Corrosion Inhibi
tors Used in Oil Production", presented at Royal
Society of Chemistry Symposium, Chemicals in
the Oil Industry, M anchester, England, Jan.
1983.
'
25 Bradborn, J.B. and Todd, R.B., "Continuous
Inj ection M ethod Controls Downhole Corrosion", Petroleum Engineer International (July 1981) p.44; (Aug. 1981) p.54.
2.6 Poetker, R.H., Brock, P.e. and Huckleberry, S.A., ''Does the Inhibitor Squeeze Method Work; Petroleum Engineer (Dec. 1957) p. B102,
27 Hudgins, C.M. and Hanson, R.T., "How Conoco Floods with Seawater", Oil & Gas Journal (Feb. 15, 1971) p.71.
28 Carlberg, B.L., "Vacuum Deaeration - A New Operation for Waterflood Treating Plants'. 51st Annual SPE Meeting (Get.3-6. 1976) No. 6096.
29 Katz, D.L., "Prediction of Conditions for Hydrate Form ation in N atural Gases", Trans. A /M E VQ1.160 (1945) p. 141.
30 H ow lin, W.D., "Water Masses and G eneral Circulation of the Gulf of Mexico', Oceanology Inti. (February. 1971), p,28.
31 Barker, J.W. and Gomez, R.K., "Formation of H ydrates During D eepw ater Drilling Operations', l.PeL Tech. (March, 1989), p.297,
32 Hammerschmidt, E.G., 'Preventing and Remov ing Gas Hydrate Formations in Natural Gas Pipe Lines'. Oil & Gas Journal (May 11, 1939). p.66.
33 Engineering Data Book, Gas Processors Suppli ers Association, Tulsa, OK, 1980. p. 15.13.
34 Mondshine, T., "Completion Fluid Uses Salt for Bridging. Weighting', Oil & Gas Journal, Aug.22. 1977.
35 Ezzat, A.M., Sugsberger, j j . Tillis. WJ ., "SolidsFree, High-Density Brines for Packer-Fluid Applications",/.Pet Tech. (April. 1988) p.491.
36 Environmental Effects o f Offshore Oil Production, The Buccaneer Gas and Oil Field Study, Middleditch, B.S., Ed., Plenum Press, New York, 1981.
37 Rose, C.D., and Ward, T J,, "Acute Toxicity and Aquatic Elazard Associated with Discharged Formation Water', p.301-27 in Ref. 36.
38 Grothe, D.L.R. and Kimerle, R A ,, "Inter- and Intralaboratory Variability in Daphnia magna Effluent Toxicity Test Results", Environmental TcodcoiOfff and Chemistry, VolA (1985) p. 189.
39 Kimerle, RA ,, Werner, A.F., and Adams, WJ,, "Aquatic Hazard Evaluation Principles Applied to the Development of Water Quality Criteria", A quatic Toxicology and Hazard Assessment; Seventh Symposium, A ST M S IP 854, Cardwell, R.D., Purdy, R.A. and B ahner, R.C., Fids., American Society of Testing Materials, Philadel phia (1985) p.538.
40 Kimerle, R.A., Adams, W J.. and Grothe, D.R., "A Tiered Approach to Aquatic Safety Assess ment of Effluents", in Environmental Hazard Assessment o f Effluents, Bergman, H., Kimerle. R. and Maki, A., Eds., Society of Environmental Toxicology and Chemistry, Pergamon Press, New York, (1986) p.247, '
41 Boeihing. R.S., "Biodegradation Testing of Insol uble Materials", Environmental Toxicology and Testing, VoL3 (1984) p,5.
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42 Robichaux, T.I., "Bactericides Used in Drilling and Completion Operations", presented at C onference on Environm ental Aspects of Chemical Use in Well Drilling Operations, May 21-23. 1975, Houston, Texas.
43 Montgomery', R.M., Forester. I., and D'saro, (UN., 'Effects of Triethylene Glycol on Mysidop-
sis bahia (Crustacea: Mysidacea) and Menidia peninsulae (Pisces: A thernieae)', Aquatic Toxi cology and Hazard Assessment: Eighth Symposi um, STM STP 891, Bahner, R.C. and Hanses, DJ,, Eds., American Society for Testing Materi als, Philadelphia, p.27D.
44 Leutennan, A J J .. Jones, F.V., Benge, G.W.. and Stark, c.L., 'New Driffiag Fluid Additive Toxicity Data Developed", Offshore (July, 1989) p.31.
45 Verschueren, K_, Handbook o f Environmental Data on Organic Chemicals, Van N ostrand Reinhold Company, New York, 1977.
46 Bengtsson. B.E., and Tarkpea, M,. "The Acute Aquatic Toxicity of some Substances Carried by Ships', Marine Pollution Bulletin, Voi. 14, N o.6 (1983) p. 213.
47 Power, F.M.; "Toxicological Aspects o f Regula
tion of Liquid Discharges from Alcohol Fuel
Plants", presented at Alcohol Fuel Technology
5t imi. Sym., Auckland, May 13-18, 1982,. voi. 3,
p.3-199 (8).
"
48 Ewell, W.S., Gorsuch, J.W.. Kringle, R.O.. Robillard, K.A., and Spiegel, R.C., `Sim ultaneous Evaluation of the Acute Effects of Chemicals on Seven Aquatic Species', Environmental Ttmeai&~ gy and Chemistry?) Voi 5 (1986) p.831.
49 Cowgill, U.M., Takahashi, LT., and Applegath,
S.L., 'A C om parison o f the Effect o f Four
Benchmark Chemicals on Daphnia magna and
Ceriodapfmia dubia-affinis Tested at Two Differ
ent Temperatures", Environmental Toxicology
and tChoinism/, VoiA ( 1985) P.41S-H.
"
50 Conway, R.A,,, Waggy. G.T.. Spiegel, M.H., and Berglund, R.L., "Environmental Fate and Effects of Ethylene Oxide", Environ. Sci. Technol, voU7,, No.2 i 1983) p.107.
51 Middleditch, B.S., "Biocides", p.55-7 in Ref. 36.
Sierra Club v. EPA 18cv3472 NDCA
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APPENDIX B COMMENT NO. 33
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00087
Copper Ion Systems
For the Prevention of Marine Growth on Submersible Pumps Installation and Maintenance
Sierra Club v. EPA 18cv3472 NDCA
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ED 002061 00130976-00088
How the Copper Ionizer Works
Rectifier DC
Power
+ Positive
Negative
Water Out
Stainless Steel Contact Chamber
Cu Cu
Cu
Cu
Cu
Cu
Cu
Cu
C_ u
Cu
Water In
This is basically an electrolysis process. Electrical Current flows between the Copper Anode and Stainless
Steel Tank we call a Contact Chamber. The Water flowing through the Contact Tank picks up the Copper Ions
which is discharged below the Submersible Pump.
This Copper laden water flowing o ve r the pump prevents marine growth from attaching itself to the pump.
We have found that a .05 - 1PPM level of copper is all that is required to prevent fouling
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ED 002061 00130976-00089
Marine Growth Prevention Copper Ionizer System Installation Guide
1" Gray PVC Pipe
\
PVC Flanges
With m * orifics Piate
instateci between them
A Crouse Hinds GUAL.38 is
serened mtQ tft threaded
to&uiated fitting coming tit o i the fisrsp
Thu Stsmtess stud uomfosi through the m&ytdtor has
Nun bppud fara %2dhuit
Thu wir iug \& attached
t> -100 PSI Gauge { set regulator so pressure is
between IS - 20 P s i)
\
'
I""sister SitVt "" jmust feucm
U-Saiis ta tit S" P'pe I noto Instati Rubber between bottom of p pe and support )
Watts Pressure
Regulator
{N i>i
t h u f iu u y?s $
wa imw imkitw)
Jockey Pump Caisson
V V
1" Flexible PVC Pip Run inside Caisson, strapped to pump discharge piping with
Ty Wraps
tostdll Hard T` PVC piping tong thu pump
A clamp id sucuru Shu PVC pip to thu Pump shuuid hu fshncsted to fit sho pump usud ot that fucstlon.
IhUtSlStheduUhle00's asindicatedmthu
diagram beUctwthu md ofThu pump motor (2' 3" from aodi
Sierra Club v. EPA 18cv3472 NDCA
\
Stainless Steel Bail Valves
Bohs-yppoito&>Grating
Water into NIGP&
(You dan use
Gray PVC pipe)
+ Power to Anode from
Rectifier fuse m Wire)
*Power.to Bolton Flange (Cathode) from Rectifier
(note 'A~20 Tapped hois in terge)
f f \ t o *< ;>'i M ft P v C p i p i n g a s pmfsii& so b o o k t f t e |y s f e n t ? g p
~ t s 6^^ < s p u le s to n u iim i* ( h b " 8 f .'** Kid " u u iftO * t t *< H
meniti be used.
S te s i p p th i Wffl i^ o n tu e iiy stUtp tra m re n i .-irei b a cte ria ; s i t t e r ,
i
Itre ameuef o# arnwrage ppgd io tua raodc wm detorm-oe me corpaf *0 ! s entra wetcr
?s Mtpz >%a m-fmg^m tustn t gc mt frapsrar hruet mtbmvrr* *ute (pgppwlptef slwslrf |g mimm j ~4RPi:l
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ED 002061 00130976-00090
Copper Ion System iainteanee
Orifice Plate
Note: Anytime the system Is being serviced Cut off the Electrical Power arid follow Proper LOTG Procedures, This Is an Electrical Hasard and should be serviced by
Authorised Personnel Only
Vent Valve
Watts Pressure Regulator
Weekly
Check the Water Flow to the Caisson Test Copper Level in water going to Submersible pump Copper Level should be between .5 and 1 PPM Adjust Rectifier Amperage to change Copper PPM Level Check Water Pressure - Adjust Watts Regulator as need Note: The WATTS Regulator is just used to step down the Fire Water System Pressure going into the Contact Chamber The Orifice Plate controls the flow out of the Contact Chamber and pressure on St, Too Large an Orifice and the pressure will be low Too Small or if it is getting plugged the pressure will go up Copper will sometimes build up on the orifice plate plugging it
Sierra Club v. EPA 18cv3472 NDCA
Drain Valves
Monthly System Flush
* Shut Off Power to Ionizer * Shut off the Inlet Water supply and Outlet Lines Open the Top Vent Valve * Open Bottom Drain Valves * Let the water drain out of the Contact Chamber
* Close Vent Valve Off * With both bottom drains open, open the water inlet * Let the water flow out of the Contact Chamber until Clean * Record how much sediment is washed out
Yearly
* Shutdown the System and Flush * Remove the inlet Piping and Flange
Failure to Flush Sediment May Cause it to Short Out internally and Cause a Failure or Sever Electrolysis of the Units Housing and Premature Anode Failure
* inspect the Internal Condition of the Contact Chamber
If significant build up is found on the walls of the Contact Chamber
remove the outlet Piping and Fiange/Anode Assembly
* Examine the condition of the Copper Anode ~ How much is left
* Replace Anode as condition warrants
Note: If you do not want to service the System in the field It can be shipped info EXTERRAN's Shop for Rebuilding
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ED 002061 00130976-00091
Examples of Internal Build Up
Build Up on Wails of Contact Chamber
As Part of the Electrolysis Process Copper will build up on the Inside of the Stainless Steel Contact Chamber Other Sediment and Build up comes from Organics in the Seawater
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ED 002061 00130976-00092
Copper Anode Images
Anode Assembly backed out Notice the sediment
Sierra Club v. EPA 18cv3472 NDCA
Normal Build Up on the Anode
Flange Failure
Failure to Flush Sediments from the Tank will cause severe electrolysis between the Flange and Anode or the Anode and Tank
Below are two examples of Flange Failures
Sierra Club v. EPA 18cv3472 NDCA
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Testing for Copper PPM Level
Copper CHEM ets
0 - 1 & 1 -10 ppm
-n
v
1. Fill the sample cup to the 25 mL mark
" '
with the sample (fig 1).
2. Place the CHEMet ampoule in the sample cup. Snap the tip by pressing the ampoule against the side of the cup. The ampoule will fill leaving a small bubble to facilitate mixing (fig 2).
3. Mix the contents of the ampoule by inverting it several times, allowing the bubble to travel from end to end each time. Wipe all liquid from the exterior of the ampoule. Wait 2 minutes for color development.
4. Use the appropriate comparator to determine the level of copper in the sample. If the color of the CHEMet ampoule is between two color standards, a concentration estimate can be made.
a. Place the CHEMet ampoule, flat end downward into the center tube of the low range comparator. Direct the top of the comparator up toward a source of bright light while viewing from the bottom. Rotate the comparator until the color standard below the CHEMet ampoule shows the closest match
b. Hold the high range comparator in a nearly horizontal position while standing directly beneath a bright source of light. Place the CHEMet ampoule between the color standards moving it from left to right along the comparator until the best color match is found Sierra Club v. EPA 18cv3472 NDCA
__ r-- bfl
Reorder Information Cat. No. Test Kit, complete...................................................K-3510 Refill, 30 CHEMet am poules.................................... R-3510 Sample Cup, 25 mL, package of s ix ..........................A-0013 Comparator, 0-1 p p m ............................................. C-3501 Comparator, 1-10 p p m ........................................... C-3510 CHEMetrics, Inc., 4295 Catlett Road, Calverton, VA 20138-0214 U.S.A. Phone: (800) 356-3072; Fax: (540) 788-4856; E-Mail: orders@chemetrics. com www. chemetrics. com Jan. 07, Rev. 5
Example of Copper Test Reading
Copper PPM Level is Between 2-3 PPM Need to adjust Amperage Setting so that PPM Level is between .5 and 1 PPM
ED 002061 00130976-00095
BASIC OPERATING INSTRUCTIONS FOR RK19 SOLID STATE CONTROL RECTIFIERS CURRENT LIMIT
a a sa s
MANUAL OPERATION
1. Auto - Manual switch must be in manual position. 2. Link bars must be in lowest setting. 3. Turn rectifier on. 4. Observe output. Adjust link bars to desired output.
NOTE: Solid state controls have no effect in manual mode and need not be adjusted. Solid state printed circuit boards may be removed for inspection or repair in manual mode. Unit will remain operational.
CURRENT LIMIT - CONSTANT CURRENT OPERATION
NOTE:
The CURRENT LIMIT is factory set at rated output of rectifier. If different current limit is desired then proceed with the following steps.
1. With the Auto-Manual Control switch in the Manual position, increase link bars to obtain a current output slightly higher than required, but still within the rating of the rectifier. 2. Turn Rectifier OFF and adjust CURRENT LIMT knobs fully clockwise. 3. Place the Auto-Manual switch in the AUTO mode. 4. Turn Rectifier on. Output should return to the output as adjusted in step one above. 5. Adjust CURRENT LIMIT control counter clockwise (decrease) to desired current output. Rectifier will maintain this current setting with nominal circuit resistance changes. If there is an extreme change in external load circuit resistance, link bars may need to be at a higher setting to maintain the preset current. Constance current operation is a function of the current limit feature of this unit
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00096
TROUBLE SHOOTING HINTS
NOTE: A wiring diagram for use by experienced personnel is provided. Only experienced electrical personnel should attempt location and repair of electrical difficulties, should they occur. Some symptoms of elementary trouble and the possible remedy are as follows:
1. NO D.C. CURRENT OR D.C. VOLTAGE OUTPUT. CHECK: A.C. overload protection for blown fuses or tripped breaker. Check A.C. power supply.(ls desired potential maintained?) If desired potential is maintained then unit has automatically cut back output of rectifier to maintain potential.
2. D.C. VOLTAGE BUT NO D.C. CURRENT READING. CHECK: D.C. ammeter. Check D.C. connections and external D.C. circuit for electrical continuity.
3. D.C. CURRENT READING BUT NO D.C. VOLTAGE READINGS. CHECK: Check D.C. voltmeter.
4. MAXIMUM RATED D.C. VOLTAGE CANNOT BE ATTAINED. CHECK: A.C. line voltage. Check link bar adjustments for maximum. Check accuracy of D.C. voltmeter. Check that unit is not operating against a preset voltage and or current limit.
5. MAXIMUM RATED D.C. CURRENT CANNOT BE ATTAINED. CHECK: Load resistance of external D.C. circuit. Check that unit is not operating against a preset voltage and or current limit.
6. REFERENCE METER PEGGED FULL SCALE AND NO D.C. OUTPUT. CHECK: Electrode and Structure connections and external reference circuit for electrical continuity.
NOTE: Give model and serial numbers when writing or calling Universal Rectifiers Inc, in reference to this rectifier.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00097
For Parts and Service
Replacement Anodes and Parts orforShop Repair
Craig Clements Belle Chasse, La Phone: 504-392-2600
Rectifier Parts
Universal Rectifiers, Inc. P.O. Box 1640 1631 Cottonwood School Rd. Rosenberg, Texas 77471 (281) 342-8471 - (281) 342-0292 Fax: www.universalrectifiers.com
For Technical Information Scott Reppel Lead Principal Investigator Chevron USA Eastern Gulf of Mexico Harvey Office Phone: 504-263-6890 Cell: 504-289-1701
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00098
APPENDIX C COMMENT NO. 33
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00099
Area & Block
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 0 4 A Q
M o b ile 9 1 6 A P
M o b ile 9 1 6 A P
M o b ile 9 1 6 A P
M o b ile 9 1 6 A P
M o b ile 9 1 6 A P
M o b ile 9 1 6 A P M o b ile 9 1 6 A P M o b ile 9 1 6 A P M o b ile 9 1 6 A P
M P 142 C M P 142 C M P 144 A M P 144 A M P 300 B M P 300 B M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M M P 42 M SM ! 236 A SM ! 236 A SM ! 236 A SM ! 236 A SM ! 236 A SM ! 236 A SM I 236 A SM I 236 A SM I 236 A SM I 236 A
Sierra Club v. EPA 18cv3472 NDCA
lori Treatm ent
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu
Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu
Pipe Dia
(in ) 6
6
6
6
6
6
6
6
6
2
2
2
2
2
2 2 2 2 3 3 3 3 3 3 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2
Criticai Dilution (%)
1 .4 8
1 .4 8
1 .4 8
1 .4 8
1 .4 8
1 .4 8
1 .4 8
1 .4 8
1 .2 3
0 .2 9
0 .2 9
0 .2 9
0 .2 9
0 .2 9
0 .2 9 0 .2 9 0 .2 9 0 .2 9 1 2 .4 1 2 .4 1 2 .4 1 2 .4 1 2 .4 1 2 .4 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2
C o lle ctio n Date
06/09/14
08/04/14
10/27/14
01/05/15
07/13/15
01/11/16
06/15/16
09/01/16
03/09/17
01/13/14
04/07/14
06/17/14
07/14/14 07/28/14 01/05/15
07/13/15 01/11/16 06/15/16 09/01/16 12/25/13 01/14/14 12/25/13 01/14/14 12/25/13 01/14/14 01/26/14 04/15/14 05/13/14 06/03/14 07/01/14 08/05/14 09/02/14 10/15/14 11/12/14 12/11/14 01/06/15 02/03/15 03/01/16 12/16/13 01/21/14 04/08/14 05/06/14 06/03/14 07/08/14 08/05/14 11/25/14 12/09/14 01/06/15
NOEC
5 .9 2
5 .9 2
5 .9 2
5 .9 2
5 .9 2
5 .9 2
2 .9 6
5 .9 2
4 .9 2
1 .1 6
1 .1 6
1 .1 6
1 .1 6
1 .1 6
1 .1 6 1 .1 6 1 .1 6 1 .1 6 4 9 .6 4 9 .6 2 4 .8 4 9 .6 4 9 .6 4 9 .6 1 1 .2 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 2 2 .4 1 1 .2 4 4 .8 4 4 .8 1 1 .2 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 1 1 .2 4 4 .8 4 4 .8
M, beryllina Survival LOEC
> 5 .9 2
> 5 .9 2
> 5 .9 2
> 5 .9 2
> 5 .9 2
> 5 .9 2
5 .9 2
> 5 .9 2
> 4 .9 2
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6 > 1 .1 6 > 1 .1 6 > 1 .1 6 > 4 9 .6 > 4 9 .6 4 9 .6 > 4 9 .6 > 4 9 .6 > 4 9 .6 2 2 .4 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 4 4 .8 2 2 .4 > 4 4 .8 > 4 4 .8 2 2 .4 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 2 2 .4 > 4 4 .8 > 4 4 .8
P a ss/ F a il
P
P
P
P
P
P
p
p
p
P
P
P
P
P
P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P
Tiers 8&9
NOEC
5 .9 2
5 .9 2
5 .9 2
5 .9 2
2 .9 6
5 .9 2
5 .9 2
5 .9 2
4 .9 2
1 .1 6
1 .1 6
1 .1 6
1 .1 6
1 .1 6
1 .1 6 1 .1 6 1 .1 6 1 .1 6 4 9 .6 4 9 .6 1 2 .4 4 9 .6 4 9 .6 4 9 .6 2 2 .4 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 2 2 .4 1 1 .2 4 4 .8 4 4 .8 1 1 .2 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 2 2 .4 4 4 .8 2 2 .4 4 4 .8 4 4 .8
M. baha Survival LOEC
> 5 .9 2
> 5 .9 2
> 5 .9 2
> 5 .9 2
5 .9 2
> 5 .9 2
> 5 .9 2
> 5 .9 2
> 4 .9 2
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6
> 1 .1 6 > 1 .1 6 > 1 .1 6 > 1 .1 6 > 4 9 .6 > 4 9 .6 2 4 .8 > 4 9 .6 > 4 9 .6 > 4 9 .6 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 4 4 .8 2 2 .4 > 4 4 .8 > 4 4 .8 2 2 .4 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 > 4 4 .8 4 4 .8 > 4 4 .8 4 4 .8 > 4 4 .8 > 4 4 .8
P a ss/ F a il
P
P
P
P
P
P
P
P
p
P
P
P
P
P
P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P P
Copper Ion analysis (m g/L)
0 .5 0 .9 9 N o t m ea su re d N o t m ea su re d
N o t m ea su re d
Comment
C o p p e r Io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r o n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r o n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
N o t m ea su re d
N o t m ea su re d
N o t m ea su re d
BD L
N o t m ea su re d
N o t m ea su re d
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
BD L BD L BD L BD L BD L N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
BD L BD L BD L BD L N o t m ea su re d N o t m ea su re d
C o p p e r Io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r o n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r Io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r Io n t r e a t m e n t o n ly E P A R e g io n 4 / 7 - D a y N O E C te stin g
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly
ED 002061 00130976-00100
SM I 236 A SM I 236 A SM I 236 A SM I 236 A SM I 236 A ST 151 P I
ST 37 J ST 37 J ST 37 J ST 37 J ST 37 J ST 37 J ST 52 A ST 52 A ST 52 A ST 52 A ST 52 A ST 52 A VK 900 A W D 109 A W D 109 A G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) G C 3 3 8 (Fro n t R u n n e r) M C 7 3 6 ( T h u n d e r F la w k ) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 ( T h u n d e r F la w k ) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) M C 7 3 6 (T h u n d er H aw k) A T618 A T618 A T618 A T618 A T618 A T618 G C610 G C610 G C610 G C653 G C653 G C653 G C610 G C610 G G 610 G C653 G C653
Sierra Club v. EPA 18cv3472 NDCA
Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al Cu & Al C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe C u & Fe Cu Cu& AI Cu& AI Cu Cu& AI Cu& AI Cu& AI Cu Cu Cu Cu Cu& AI Cu Cu& AI Cu Cu& AI Cu
2 2 2 1 .5 1 .5 2 >6 >6 >6 >6 >6 >6 2 2 2 2 2 2 3 3 3 16 16 16 16 16 16 16 16 16 16 16 16 16 16 14 14 14 14 14 14 14 14 14 14 14 14 14 8 5 .9 1 1 .8 1 7 .7 5 .9 9 .8 1 7 .7 9 .8 5 .9 9 .8 20 5 .9 9 .8 9 .8 5 .9 5 .9 1 1 1 .8 1 4 .5
1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 2 .4
14 14 14 14 14 14 1 2 .4 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 1 .2 1 2 .4 1 2 .4 1 2 .4 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 20 23 20 14 23 20 14 20 23 20 20 23 20 20 23 23 20 23
02/03/15 03/03/15 01/05/16 01/10/17 03/28/17 01/16/14 09/16/15 10/12/15 11/04/15 12/17/15 03/02/16 05/12/16 01/15/14 04/08/14 07/10/14 10/16/14 02/05/15 02/10/16 01/22/14 12/30/13 01/22/14 01/16/14 02/13/14 03/06/14 04/24/14 05/20/14 06/10/14 07/08/14 08/13/14 09/18/14 10/28/14 11/05/14 12/09/14 11/18/15 11/22/16 01/15/14 02/13/14 03/06/14 04/24/14 05/20/14 06/10/14 07/08/14 08/11/14 09/11/14 10/09/14 11/06/14 12/03/14 11/19/15 08/26/16 10/28/14 10/28/14 10/28/14 11/07/14 11/07/14 11/07/14 11/20/14 11/20/14 11/20/14 12/01/14 12/29/14 12/29/14 01/28/15 01/28/15 02/26/15 02/26/15 03/25/15
4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 9 .6
56 56 56 56 56 56 4 9 .6 2 2 .4 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 9 .6 4 9 .6 4 9 .6 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 40 92 40 56 92 80 64 80 92 80 80 92 80 80 92 92 80 92
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 9 .6
P
>56
P
>56
P
>56
P
>56
P
>56
P
>56
P
> 4 9 .6
P
4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 9 .6
P
> 4 9 .6
P
> 4 9 .6
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
80
P
>92
P
80
P
>56
P
>92
P
>80
P
>64
P
>80
P
>92
P
>80
P
>80
P
>92
P
>80
P
>80
P
>92
P
>92
P
>80
P
>92
P
Tiers 8&9
4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 4 .8 4 9 .6
56 56 56 56 56 56 4 9 .6 1 1 .2 2 2 .4 4 4 .8 4 4 .8 4 4 .8 4 9 .6 4 9 .6 4 9 .6 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 80 20 92 80 56 92 80 64 80 92 80 80 92 80 80 92 92 80 92
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 9 .6
P
>56
P
>56
P
>56
P
>56
P
>56
P
>56
P
> 4 9 .6
P
2 2 .4
P
4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 4 .8
P
> 4 9 .6
P
> 4 9 .6
P
> 4 9 .6
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
>80
P
40
P
>92
P
>80
P
>56
P
>92
P
>80
P
>64
P
>80
P
>92
P
>80
P
>80
P
>92
P
>80
P
>80
P
>92
P
>92
P
>80
P
>92
P
N o t m ea su re d N o t m ea su re d
N o t m ea su re d N o t m ea su re d
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly
C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s
C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s C o p p e r a n d Iro n Io n s
C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly
ED 002061 00130976-00101
G C653 G C653 G C653 G C653 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609 G C609
B D L - B e l o w D e te c t io n lim it ( < 0 .0 1 m g / L )
Cu& AI Cu
Cu& AI Cu
Cu& AI Cu& AI
Cu Cu& AI
Cu Cu& AI Cu& AI Cu& AI
Cu Cu Cu& AI Cu& AI Cu Cu& AI Cu& AI
10 4 .5 1 0 .7 1 1 .8 1 1 .8 1 7 .7 1 1 .8 1 7 .7 5 .9 1 9 .8 4 1 7 .7 2 1 7 .7 5 .9 1
5 12 12 5 .9 1 1 7 .7 2 1 7 .7 2
20 23 20 20 20 2 4 .6 20 2 4 .6 23 20 20 2 4 .6 23 23 20 20 23 20 20
03/25/15 04/01/15 04/01/15 04/01/15 04/28/15 04/28/15 04/28/15 05/31/15 05/31/15 05/31/15 05/01/15 05/01/15 05/01/15 07/01/15 07/01/15 07/01/15 08/05/15 08/05/15 08/05/15
80 90 80 80 80 9 8 .4 80 9 8 .4 92 80 80 9 8 .4 92 92 80 80 92 80 80
>80
P
>92
P
>80
P
>80
P
>80
P
> 9 8 .4
P
>80
P
> 9 8 .4
P
>92
P
>80
P
>80
P
> 9 8 .4
P
>92
P
>92
P
>80
P
>80
P
>92
P
>80
P
>80
P
80 92 80 80 80 9 8 .4 80 9 8 .4 92 80 80 9 8 .4 92 92 80 80 92 80 80
>80
P
>92
P
>80
P
>80
P
>80
P
> 9 8 .4
P
>80
P
> 9 8 .4
P
>92
P
>80
P
>80
P
> 9 8 .4
P
>92
P
>92
P
>80
P
>80
P
>92
P
>80
P
>80
P
N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d N o t m ea su re d
C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s C o p p e r Io n t r e a t m e n t o n ly C o p p e r a n d A lu m in u m Io n s C o p p e r a n d A lu m in u m Io n s
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00102
APPENDIX D COMMENT NO. 36
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00103
Tiered Intake Velocity Monitoring Methodology Justification
The Offshore Operators Committee (OOC) commissioned CK Associates (CK) to evaluate if the velocity monitoring frequency, proscribed for CWIS (intakes) by GMG290000, could be reduced from daily to a lesser frequency while remaining protective of species subject to impingement mortality (IM).
CK evaluated one year of data (2015) from six separate CWIS, located in the GOM, for analysis. The intake velocity data are presented on Figure 1. The data presented in Figure 1 show a range of intake velocities measured throughout the year with a minimum velocity equal to 0.02 ft/s, a maximum intake velocity equal to 0.45 ft/s and a mean intake velocity equal to 0.172 ft/s (excluding days of zero intake flow). Gaps in the plots indicate days for which the intake was not operating. Each of the six CWIS maintained intake velocities below the 0.5 ft/s regulatory threshold (zero exceedances) during the calendar year. There is no general trend of increasing velocity for the intakes as a whole. Intake velocities tend to increase and decrease randomly due to fluctuating cooling water needs rather than an accumulation of biomass blocking the screens.
The daily intake velocities were converted to rates-of-change in intake velocity for this analysis. The results are presented as an individual value plot on Figure 2 and represent 1,290 individual velocity monitoring events. Two criteria were used to create the rate-of-change results. Missing data are omitted for purposes of the analysis (not assumed to be zero); any rate-of-change requires two consecutive non-zero velocity measurements. This analysis resulted in 1,290 data points upon which the remainder of the analysis is based. The data show a minimum rate-of-change in intake velocity equal to -0.14 (ft/s)/day, a mean of 0.00 (ft/s)/day, and a maximum of 0.20 (ft/s)/day.
An ANOVA was used to determine if any individual intake differed statistically from the others based on rates-of-change. Interval plots for each intake can be found on Figure 3. No statistically significant differences in rates-of-change were identified for any intake (P < 0.05). Individual comparison plots using Tukey's Method can be found on Figure 4.
The rate-of-change data were combined for all subsequent analyses because they do not differ statistically. The combined data set is plotted as a histogram with a normal distribution overlain on Figure 5. The data are approximately normal. However, the spread of the data is less than would be expected of a perfectly normal distribution. Therefore, the normal distribution will provide conservative estimates of mean rates-of-change throughout the remainder of the analysis.
As shown on Figure 5, the mean rate-of-change in intake velocity for the combined data set is equal to 0.00004651 (ft/s)/day with a standard deviation equal to 0.01073 (ft/s)/day. These values were used to calculate the upper 95th percentile value for mean velocity increase over 1 day, 30 days, and 90 days. The results can be found in Table 1. Based on this analysis, a given intake will exhibit an increase in velocity equal to 0.115 ft/s or less during any 30-day period at the 95% confidence level. A given intake will exhibit an increase in velocity equal to 0.200 ft/s or less during any 90-day period at the 95% confidence level.
Sierra Club v. EPA 18cv3472 NDCA
1 Tiers 8&9
ED 002061 00130976-00104
JL
0.02 L
0.021
30
0.00384
0.115
90
0.00222
0.200
The information found in Table 1 was used to develop a tiered velocity monitoring frequency that is equally protective of species that are susceptible to IM as the current daily velocity monitoring requirement proscribed in the GMG290000.
Table 2: Tiered retake velocity monitoring frequency bared cm most-recent intake velocity monitoring data.
<0.300 0.300-0.384
>0.384
90
<0.300 + <0.200 = <0.500
Quarterly
30
<0.384+ <0.115 = <0.500
Monthly
1
<0.500
Daily
The following points summarize the arguments in support of the tiered intake velocity monitoring frequency approach:
Of the six intakes included in this evaluation, zero exceeded the 0.5 ft/s intake velocity threshold during 2015 (Figure 1);
Intake velocity does not monotonically increase over time (Figure 1); There is no statistically significant difference in rate-of-change for intake velocity across the six
intakes included in the study (P < 0.05). Therefore a general approach to all intakes, as opposed to a site-specific monitoring methodology, is appropriate (Figures 2 - 5); and The tiered approach presented in Table 2 ensures that intake velocity measurements will be made prior to exceeding the 0.5 ft/s regulatory threshold. Therefore, the tiered velocity monitoring frequency is equally protective of species susceptible to IM as is the current daily intake velocity monitoring requirement proscribed in the GMG290000.
Sierra Club v. EPA 18cv3472 NDCA
2 Tiers 8&9
ED 002061 00130976-00105
Figure 1: Daily Intake Velocity
0,5 -,......................................................................................................................................................................................
0.45
Intake 1 " Intake 2 -- -- Intake 3 "Intake 4 -- -- Intake 5 -- -- Intake 6
Sierra Club v. EPA 18cv3472 NDCA
3
Tiers 8&9
ED 002061 00130976-00106
Figure 2: Individual Value Plot of Daily Changes in Intake Velocity
Change in Intake Velocity [(ft/s)/day
Intake 1
Intake 2
Intake 3
Intake 4
Intake 5
Intake 6
Sierra Club v. EPA 18cv3472 NDCA
4 Tiers 8&9
ED 002061 00130976-00107
Figure 3: Interval Plot of Intake 1, Intake 2, ... 95% Cl for the Mean
0.003
0.002
Mean Intake Velocity (ft/s)
0.001
0.000
- 0.001
- 0.002
-0.003
Intake 1
Intake 2
Intake 3
Intake 4
The pooled standard deviation is used to calculate the intervals.
Intake 5
Intake 6
Sierra Club v. EPA 18cv3472 NDCA
5 Tiers 8&9
ED 002061 00130976-00108
I ntake 2 I ntake 3 I ntake 4 I ntake 5 I ntake 6 Intake 3 Intake 4 Intake 5 Intake6 Intake 4 Intake 5 Intake6 Intake 5 Intake6 Intake6 -
Figure 4: Tukey Simultaneous 95% CIs Difference of Means for Intake 1, Intake 2,.
-0.0050
-0.0025
0.0000
0.0025
If an interval does not contain zero, the corresponding means are significantly different.
Sierra Club v. EPA 18cv3472 NDCA
6 Tiers 8&9
0.0050
ED 002061 00130976-00109
Figure 5: Histogram of Combined Intake Velocity Data Normal
Mean 0.00004651
St Dev 0.01073
N
1290
Frequency
Sierra Club v. EPA 18cv3472 NDCA
7
Tiers 8&9
ED 002061 00130976-00110
APPENDIX E COMMENT NO. 37
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00111
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE 1225) 755-1000 PAX (225) 751-2010
http://www.c-ka.corr:
July 9, 2014
Chevron USA 17000 Katy Freeway Houston, TX 77094 Attn: Ms. Kathy Dahl
Sent Via Email
H O U STO N , TX P H O N E (2 81) 3 9 7 -9 0 1 6
FAX ( 2 8 1 ) 3 9 7 - 6 6 3 7
LA K E C H A R LE S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V E P O R T , LA P H O N E (3 18) 7 9 7 -8 6 3 6
P A X (3 1 8 ) 7 9 8 -0 4 7 8
Re: Second Quarter 2014 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Ms. Dahl:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the second quarter 2014 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit).
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 14:15 on June 27, 2014 and lasted until 14:15 on June 28, 2014. The EMD was operated continuously during the sampling period at a flow rate of 13.2 gallons per minute resulting in an entrainment sample volume of 19,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00112
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate accounts to zero eggs/larvae per cubic meter and approximately zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included copepods, decapods, chaetognatha, and various phytoplankton. These organisms should not be included as part of the discharge monitoring report submittal because they do not represent species of commercial, recreational, or forage concern.
Conclusions
Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at Chad.Cristina@C-KA.com.
Sincerely yours, CK Associates
/ ' <y
...J ^ ..
Chad M. Cristina Ph.D., P.E. Senior Environmental Engineer
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00113
Table 1 Sample Collection Data Summary by Quarter
Quarter Year
Start Date and Time
Stop Date and Flow Rate
Sample
Time
(gal/min) Volume (MG)
6/28/2014
2 2014 6/27/2014 14:15
14:25
13.2
0.019
Collection Method
24-hr Continuous
Quarter Year
2 2014 2 2014 2 2014
Table 2 Entrainment Summary by Quarter
Species/Family
Total Collected
Thunnus albacares{yellowfin tuna)
0
Lutjanus campechanus(red snapper)
0
Total
0
Sample Volume
(MG)
0.019 0.019 0.019
Total # Entrained1
0 0 0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00114
17170 PERKINS ROAD
B A T O N R O U G E , LA 708 10 P H O N E (2 2 5 ) 7 5 5 -1 0 0 0 F A X (2 2 5 ) 7 5 1 -2 0 1 0
http://w w w .c-ka.com
September 18, 2014
Chevron USA 17000 Katy Freeway Houston, TX 77094 Attn: Ms. Kathy Dahl
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 1 8 ) 7 9 8 -0 4 7 8
Re: Third Quarter 2014 Entrainment Monitoring Report for the Chevron Jack and St. Maio Floating Production Unit CK Project No. 10726
Dear Ms. Dahl:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the third quarter 2014 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permitfor New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit).
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 03:00 on August 4, 2014 and lasted until 03:00 on August 5, 2014. The EMD was operated continuously during the sampling period at a flow rate of 13.2 gallons per minute resulting in an entrainment sample volume of 19,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00115
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate accounts to zero eggs/larvae per cubic meter and approximately zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included copepods, decapods, chaetognatha, and various phytoplankton. These organisms should not be included as part of the discharge monitoring report submittal because they do not represent species of commercial, recreational, or forage concern.
Conclusions
Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at Chad.Cristina@C-KA.com.
Sincerely yours, CK Associates
Chad M. Cristina Ph.D., P.E. Senior Environmental Engineer
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00116
Quarter Year
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Flow Rate
Sample
Time
(gal/min) Volume (MG)
3 2014 8/4/2014 03:00 8/5/2014 03:00 13.2
0.019
Collection Method
24-hr Continuous
Table 2 Entrainment Summary by Quarter
Quarter Year
Species/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
3 2014 Thunnus albacares{yellowfln tuna)
0
0.019
0
3 2014 Lutjanus campechanus(red snapper)
0
0.019
0
3 2014
Total
0
0.019
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00117
CK A ssociates
Li':'-
Cwww.w:
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
December 29, 2014
Chevron USA 17000 Katy Freeway Houston, TX 77094 Attn: Ms. Kathy Dahl
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
SH R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 18) 7 9 8 -0 4 7 8
Re: Fourth Quarter 2014 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Ms. Dahl:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the fourth quarter 2014 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permitfor New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit).
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 03:00 on August 4, 2014 and lasted until 03:00 on August 5, 2014. The EMD was operated continuously during the sampling period at a flow rate of 13 gallons per minute resulting in an entrainment sample volume of 19,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00118
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included polychaets, pteropods, copepods, chaetognaths, amphipods, and five fish species. None of these organisms should not be included as part of the discharge monitoring report submittal because they do not represent species of commercial, recreational, or forage concern.
Conclusions
Zero organisms of commercial, recreational, or forage concern were identified in entrainment samples collected from the JSM FPU during its first three calendar quarters of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at Chad.Cristina@C-KA.com.
Sincerely yours, CK Associates
Chad M. Cristina Ph.D., P.E. Senior Environmental Engineer
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00119
Quarter Year
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate (gal/min)
Sample Volume
(MG)
4
2014 11/24/2014 0300 11/25/2014 0300 13.2 (est)
0.019
Collection Method
24-hr Continuous
Table 2 Entrainment Summary by Quarter
Quarter Year
Specles/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
2 2014 Thunnus albacares (yellowfin tuna)
0
0.019
0
2 2014 Lutjanus campechanus(red snapper)
0
0.019
0
3 2014 Thunnus albacares (yellowfin tuna)
0
0.019
0
3 2014 Lutjanus campechanus(red snapper)
0
0.019
0
4 2014 Thunnus albacares (yellowfin tuna)
0
0.019
0
4 2014 Lutjanus campechanus(red snapper)
0
0.019
0
Total 2014 Thunnus albacares (yellowfin tuna)
0
0
Total 2014 Lutjanus campechanus(red snapper)
0
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00120
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE 1225) 755-1000 PAX (225) 751-2010
http://www.c-ka.corr:
July 23, 2015
Chevron USA 17000 Katy Freeway Houston, TX 77094 Attn: Ms. Kathy Dahl
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X 2 8 1 ) 3 9 7 -6 6 3 7
LA K E C H A R LE S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V E P O R T , LA
PHO NE PAX
(3 18) 7 9 7 -8 6 3 6 (3 1 8 ) 7 9 8 -0 4 7 8
Re: Revised First Quarter 2015 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Ms. Dahl:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the first quarter 2015 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit).
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 15:00 on January 18, 2015 and lasted until 11:00 on January 19, 2015. The EMD was operated continuously during the sampling period at a flow rate of 13.2 gallons per minute resulting in an entrainment sample volume of 16,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00121
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included polychaets, pteropods, copepods, chaetognaths, amphipods, ctenophores and two fish species. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent species of commercial, recreational, or forage concern.
Conclusions
Zero organisms of commercial, recreational, or forage concern were identified in entrainment samples collected from the JSM FPU during its first calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at Chad.Cristina@C-KA.com.
Sincerely yours, CK Associates
Chad M. Cristina Ph.D., P.E. Senior Environmental Engineer
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00122
Quarter Year 1 2015
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate (gal/min)
Sample Volume
(MG)
1/18/2015 1500 1/19/2015 1100 13.2 (est) 0.016
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Species/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2015 Thunnus albacares (yellowfln tuna)
0
0.016
0
1 2015 Lutjanus campechanus(red snapper)
0
0.016
0
Total 2014 Thunnus albacares (yellowfin tuna)
0
0
Total 2014 Lutjanus campechanus(red snapper)
0
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8
MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00123
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE 1225) 755-1000 PAX (225) 751-2010
http://www.c-ka.corr:
July 23, 2015
Chevron USA 100 Northpark Blvd. Houston, TX 70433 Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X 2 8 1 ) 3 9 7 -6 6 3 7
LA K E C H A R LE S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V E P O R T , LA
PHO NE PAX
(3 18) 7 9 7 -8 6 3 6 (3 1 8 ) 7 9 8 -0 4 7 8
Re: Revised Second Quarter 2015 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Ms. Dahl:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the second quarter 2015 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit).
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 03:00 on April 6, 2015 and lasted until 21:00 that evening. The EMD was operated continuously during the sampling period at a flow rate of 13.2 gallons per minute resulting in an entrainment sample volume of 16,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00124
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included copepods, pteropods, amphipods, chaetognaths, ctenophores. Additionally, one damaged fish larva was observed, although the species was unable to be identified. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent species of commercial, recreational, or forage concern.
Conclusions
Zero organisms of commercial, recreational, or forage concern were identified in entrainment samples collected from the JSM FPU during its first calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at Chad.Cristina@C-KA.com.
Sincerely yours, CK Associates
Chad M. Cristina Ph.D., P.E. Senior Environmental Engineer
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00125
Quarter Year 2 2015
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate (gal/min)
Sample Volume
(MG)
4/6/15 0300
4/6/15 2100
13.2 (est) 0.016
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Species/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
1 2015 Lutjcmus campechanus{red snapper)
0
0.016
0
2 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
2 2015 Lutjanus campechanus(red snapper)
0
0.016
0
Total 2015 Thunnus albacares (yellowfin tuna)
0
N/A
0
Total 2015 Lutjanus campechanus(red snapper)
0
N/A
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8
MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00126
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE 1225) 755-1000 PAX (225) 751-2010
http://www.c-ka.corr:
July 23, 2015
Chevron USA 100 Northpark Blvd. Houston, TX 70433 Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X 2 8 1 ) 3 9 7 -6 6 3 7
LA K E C H A R LE S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V E P O R T , LA
PHO NE PAX
(3 18) 7 9 7 -8 6 3 6 (3 1 8 ) 7 9 8 -0 4 7 8
Re: Third Quarter 2015 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the third quarter 2015 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 13:00 on July 4, 2015 and lasted until 07:00 July 5, 2015. The EMD was operated continuously during the sampling period at a flow rate of 11.0 gallons per minute resulting in an entrainment sample volume of 12,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00127
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included chaetognatha, copepods, amphipods, Lucifer faxoni. Additionally, three scaridae larvae was observed, although the species was unable to be identified. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent important commercial and recreational species of concern.
Conclusions
Zero organisms of important commercial and recreational species of concern were identified in entrainment samples collected from the JSM FPU during its third calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental, socioeconomic, and ecological damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@c-ka.com .
Sincerely yours, CK Associates
James L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00128
Quarter Year 3 2015
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate
Sample
(gal/min) Volume (MG)
7/4/15 1300
7/5/15 0700
11.0 (est)
0.012
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Species/Famlly
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
1 2015 Lutjanus campechanus{red snapper)
0
0.016
0
2 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
2 2015 Lutjanus campechanus(red snapper)
0
0.016
0
3 2015 Thunnus albacares (yellowfin tuna)
0
0.012
0
3 2015 Lutjanus campechanus(red snapper)
0
0.012
0
Total 2015 Thunnus albacares (yellow fin tuna)
0
N/A
0
Total 2015 Lutjanus campechanus(red snapper)
0
N/A
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00129
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00130
Attachment A ~Example Data Sheet Cooling Water intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St, Malo Platform
Collection Date
Project Number
Names of Personnel Collecting Samples
Sample Collection Flow Rate
//
Sample Event Start Time and Date
Sample Event End Time and Date
Weather Conditions during each cycle
Number of Sample Jars Filled
Sample Collection Method
Other Notes Relevant to Sampling Event
/ n n J,>t
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00131
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00132
ED 002061 00130976-00133
ASSOCIATES
L L C
ENVIRONMENTAL & ENGINEERING CONSULTANTS
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
Page_
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WHITE C O P Y TO A C C O M P A N Y SA M P LE RETA IN Y E L L O W C O P Y FO R FILE S RETA IN P IN K C O P Y FO R FIELD SU P E R V ISO R
CK-100
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ATTACHMENT C FIELD OBSERVATIONS DURING SAMPLING
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00134
Subject:
JSM Entrainment Sample-Attachment A
From: Rodrigue, Clay W. (wrod) [mailto:WROD@chevron.coml Sent: Thursday, July 09, 2015 3:56 PM To: Kunjappy, Raj Subject: RE: JSM Entrainment Sample-Attachment A
Raj, Speaking with John Berry. 1. No obstructions in the meter or the hoses. 2. The assembly has no devices that require calibration, the flow meter is a replaceable type and is functioning now. 3. See above. 4. Both gentlemen report that the screen was intact during the collection procedure. 5. No incident or situation occurred that would that draw any attention to the lowered count. Pumps stayed online with no shut-ins or swaps.
Both indicated a light coating of the material was noted. Let me know if you feel another sample is needed.
From: Kunjappy, Raj Sent: Thursday, July 09, 2015 3:03 PM To: Rodrigue, Clay W. (wrod) Cc: Floyd, Jim Subject: RE: JSM Entrainment Sample-Attachment A
If we can evaluate the sample procedure and ensure none of the following occurred:
(1) possible flow meter obstruction due to aquatic vegetation or other debris on the propeller (2) malfunctioning or damaged flow meters; (3) any equipment used that requires calibration and is not properly calibrated; (4) damaged (torn) screening found after a sample is collected; (5) any incident or situation which may result in the collection of unreliable data;
I am leaning towards having the lab analyze if we can confirm the above.
Thank you, Raj Kunjappy HES Specialist- Water/NPDES
Gulf of Mexico Business Unit
Chevron North America Exploration and Production Company
(a Chevron U.S.A. Inc division)
100 Northpark Boulevard (COV114/122B)
Covington, LA 70433
0: 985-773-7283
C: 985-377-6991
rai.kuniappv(5)chevron.com
.
From: Rodrigue, Clay W. (wrod) Sent: Thursday, July 09, 2015 2:50 PM
Sierra Club v. EPA 18cv3472 NDCA
1
Tiers 8&9
ED 002061 00130976-00135
To: Kunjappy, Raj Subject: RE: JSM Entrainment Sample-Attachment A
Raj, I just spoke with Isaac and he commented that he noticed little was caught in the sample he recovered. Also spoke with John separately and he noted the same. Neither felt the necessity to include it in the note section, though they both said it was just out of the ordinary.
From: Kunjappy, Raj Sent: Thursday, July 09, 2015 2:05 PM To: Rodrigue, Clay W. (wrod) Subject: JSM Entrainment Sample-Attachment A
Clay, Do you have a document referred to as "Attachment A" that was filled out? If you do, could you send it to me? See the second page of the attachment.
Thank you, Raj Kunjappy HES Specialist- Water/NPDES
Gulf of Mexico Business Unit Chevron North America Exploration and Production Company (a Chevron U.S.A. Inc division)
100 Northpark Boulevard (COV114/122B) Covington, LA 70433 O: 985-773-7283 C: 985-377-6991 rai.kuniappyPchevron.com
Sierra Club v. EPA 18cv3472 NDCA
2 Tiers 8&9
ED 002061 00130976-00136
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE 1225) 755-1000 PAX (225) 751-2010
http://www.c-ka.corr:
July 23, 2015
Chevron USA 100 Northpark Blvd. Houston, TX 70433 Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X 2 8 1 ) 3 9 7 -6 6 3 7
LA K E C H A R LE S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V E P O R T , LA
PHO NE PAX
(3 18) 7 9 7 -8 6 3 6 (3 1 8 ) 7 9 8 -0 4 7 8
Re: Third Quarter 2015 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the third quarter 2015 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainment monitoring is required for the JSM FPU CWIS in accordance with section 12.C.2.M of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 13:00 on July 4, 2015 and lasted until 07:00 July 5, 2015. The EMD was operated continuously during the sampling period at a flow rate of 11.0 gallons per minute resulting in an entrainment sample volume of 12,000 gallons. Sample collection data are summarized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00137
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organisms that were not listed as species of concern, but that were found in the entrainment samples included chaetognatha, copepods, amphipods, Lucifer faxoni. Additionally, three scaridae larvae was observed, although the species was unable to be identified. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent important commercial and recreational species of concern.
Conclusions
Zero organisms of important commercial and recreational species of concern were identified in entrainment samples collected from the JSM FPU during its third calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environmental, socioeconomic, and ecological damage due to entrainment in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@c-ka.com .
Sincerely yours, CK Associates
James L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00138
Quarter Year 3 2015
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate
Sample
(gal/min) Volume (MG)
7/4/15 1300
7/5/15 0700
11.0 (est)
0.012
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Species/Famlly
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
1 2015 Lutjanus campechanus{red snapper)
0
0.016
0
2 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
2 2015 Lutjanus campechanus(red snapper)
0
0.016
0
3 2015 Thunnus albacares (yellowfin tuna)
0
0.012
0
3 2015 Lutjanus campechanus(red snapper)
0
0.012
0
Total 2015 Thunnus albacares (yellowfin tuna)
0
N/A
0
Total 2015 Lutjanus campechanus(red snapper)
0
N/A
0
1Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00139
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00140
Attachment A ~Example Data Sheet Cooling Water intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St, Malo Platform
Collection Date
Project Number
Names of Personnel Collecting Samples
Sample Collection Flow Rate
//
Sample Event Start Time and Date
Sample Event End Time and Date
Weather Conditions during each cycle
Number of Sample Jars Filled
Sample Collection Method
Other Notes Relevant to Sampling Event
/ n n J,>t
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00141
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00142
ED 002061 00130976-00143
ASSOCIATES
L L C
ENVIRONMENTAL & ENGINEERING CONSULTANTS
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
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CK-100
W
ATTACHMENT C FIELD OBSERVATIONS DURING SAMPLING
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00144
Subject:
JSM Entrainment Sample-Attachment A
From: Rodrigue, Clay W. (wrod) [mailto:WROD@chevron.coml Sent: Thursday, July 09, 2015 3:56 PM To: Kunjappy, Raj Subject: RE: JSM Entrainment Sample-Attachment A
Raj, Speaking with John Berry. 1. No obstructions in the meter or the hoses. 2. The assembly has no devices that require calibration, the flow meter is a replaceable type and is functioning now. 3. See above. 4. Both gentlemen report that the screen was intact during the collection procedure. 5. No incident or situation occurred that would that draw any attention to the lowered count. Pumps stayed online with no shut-ins or swaps.
Both indicated a light coating of the material was noted. Let me know if you feel another sample is needed.
From: Kunjappy, Raj Sent: Thursday, July 09, 2015 3:03 PM To: Rodrigue, Clay W. (wrod) Cc: Floyd, Jim Subject: RE: JSM Entrainment Sample-Attachment A
If we can evaluate the sample procedure and ensure none of the following occurred:
(1) possible flow meter obstruction due to aquatic vegetation or other debris on the propeller (2) malfunctioning or damaged flow meters; (3) any equipment used that requires calibration and is not properly calibrated; (4) damaged (torn) screening found after a sample is collected; (5) any incident or situation which may result in the collection of unreliable data;
I am leaning towards having the lab analyze if we can confirm the above.
Thank you, Raj Kunjappy HES Specialist- Water/NPDES
Gulf of Mexico Business Unit
Chevron North America Exploration and Production Company
(a Chevron U.S.A. Inc division)
100 Northpark Boulevard (COV114/122B)
Covington, LA 70433
0: 985-773-7283
C: 985-377-6991
rai.kuniappv(5)chevron.com
.
From: Rodrigue, Clay W. (wrod) Sent: Thursday, July 09, 2015 2:50 PM
Sierra Club v. EPA 18cv3472 NDCA
1
Tiers 8&9
ED 002061 00130976-00145
To: Kunjappy, Raj Subject: RE: JSM Entrainment Sample-Attachment A
Raj, I just spoke with Isaac and he commented that he noticed little was caught in the sample he recovered. Also spoke with John separately and he noted the same. Neither felt the necessity to include it in the note section, though they both said it was just out of the ordinary.
From: Kunjappy, Raj Sent: Thursday, July 09, 2015 2:05 PM To: Rodrigue, Clay W. (wrod) Subject: JSM Entrainment Sample-Attachment A
Clay, Do you have a document referred to as "Attachment A" that was filled out? If you do, could you send it to me? See the second page of the attachment.
Thank you, Raj Kunjappy HES Specialist- Water/NPDES
Gulf of Mexico Business Unit Chevron North America Exploration and Production Company (a Chevron U.S.A. Inc division) 100 Northpark Boulevard (COV114/122B) Covington, LA 70433 O: 985-773-7283 C: 985-377-6991 rai.kuniappyPchevron.com
Sierra Club v. EPA 18cv3472 NDCA
2 Tiers 8&9
ED 002061 00130976-00146
CK A ssociates
Li':'-
Cwww.w:
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
October 30, 2015
Chevron USA 100 Northpark Blvd. Houston, TX 70433
Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
SH R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 18) 7 9 8 -0 4 7 8
Re: Fourth Quarter 2015 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the fourth quarter 2015 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a new fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CW IS in accordance with section 12.C.2.M of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf of the Gulf of M exico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 m icrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 19:00 on October 5, 2015 and lasted until 19:00 on October 6, 2015. The EMD was operated continuously during the sampling period at a flow rate of 19.0 gallons per minute resulting in an entrainm ent sample volum e of 27,360 gallons. Sample collection data are summarized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00147
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organism s that were not listed as species of concern, but that were found in the entrainm ent samples included ctenophores, copepods, pteropods amphipods, Lucifer faxoni._ Additionally, one Stomatopod (mantis shrimp) probably Squilla empusa stage II larvae, one Xanthidae crab probably Hexapanopeus angustifrons Megalop stage, two Brevooitio spp. larvae, and two Haemulidae larvae too damaged to identify. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent important commercial and recreational species of concern.
Conclusions
Zero organisms of important commercial and recreational species of concern were identified in entrainm ent samples collected from the JSM FPU during its fourth calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or com m ents regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00148
Quarter Year
4
2015
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate
Sample
(gal/min) Volume (MG)
10/5/15 1900
10/6/15 1900
19.0 (est)
0.027
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Specles/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2015 Thunnus albacares (yellowfln tuna)
0
0.016
0
1 2015 Lutjanus campechanus(red snapper)
0
0.016
0
2 2015 Thunnus albacares (yellowfin tuna)
0
0.016
0
2 2015 Lutjanus campechanus(red snapper)
0
0.016
0
3 2015 Thunnus albacares (yellowfin tuna)
0
0.012
0
3 2015 Lutjanus campechanus(red snapper)
0
0.012
0
4 2015 Thunnus albacares (yellowfin tuna)
0
0.027
0
4 2015 Lutjanus campechanus(red snapper)
0
0.027
0
Total 2015 Thunnus albacares (yellowfin tuna)
0
N/A
0
Total 2015 Lutjanus campechanus{red snapper)
0
N/A
0
Projected number j - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ^ of organ^isms entrained pe^ r quarter based o^ n an average coo^ ling water flow equal to 26.8 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00149
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00150
Attachment A Data Sheet Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St. Malo Platform
Collection Date Project Number
' 70/.yc- s --
- / - /
^ i..y*--V--
Names of Personnel Collecting Samples
" ' A,' * / i--"-
Sample Collection Flow Rate
~ (G
Sample Event Start Time and Date / / - j
:
i
Sample Event End Time and Date , / j n r .
Weather Conditions during each cycle
Number of Sample Jars Filled
, J
Sample Collection Method
,, J , * , h ,
Other Notes Relevant to Sampling Event
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00151
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00152
CHAIN OF CUSTODY
ASSOCIATES
L L C
ENVIRONMENTAL & ENGINEERING
<
CONSULTANTS
mTl
> CLIENT:..f1,i dj e vrais-..rN~ira~chIe,
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N O . OF CONTAINERS
PRESERVATIVE
Page,, 7 of J
SAMPLED BY
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DATE: / 0 - 4 - IS
ANALYSES AN D INSTRUCTIONS
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ED 002061 00130976-00153
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------------------- ----- ------------------------------ ----------------------in o u r B a to n R ouge, D La ke C h a rle s , D S h re v e p o rt, H o u sto n O ffic e
W HITE C O P Y TO A CCO M PA N Y SAM PLE RETAIN YELLO W C O P Y FO R FILES RETAIN P IN K C O P Y FO R FIELD SU PERV ISO R
C K -1 0 0
CK A ssociates
Li':'-
Cwww.w:
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
February 2, 2016
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
SH R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 18) 7 9 8 -0 4 7 8
Re: First Quarter 2016 Entrainment Monitoring Report for the Chevron Jack and St. Maio Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the first quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CWIS in accordance with section 12.c.2.ii of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf o f the Gulf o f Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 0600 hours on January 6, 2016 and lasted until 0000 hours on January 7, 2016. The EMD was operated continuously during the sampling period at a flow rate of 19.0 gallons per minute resulting in an entrainm ent sample volume of 20,520 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00154
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero species of concern entrained per day. A summary of the entrained species of concern is included in Table 2. Entrained organism s that were not listed as species of concern, but that were found in the entrainm ent samples included ctenophores, copepods, pteropods chaetognaths. Additionally, one Scaridae larva and three M ugilidae larvae. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent important commercial and recreational species of concern.
Conclusions
Zero organism s of important commercial and recreational species of concern were identified in entrainm ent samples collected from the JSM FPU during its first calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or com m ents regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00155
Quarter Year 1 2016
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Flow Rate
Sample
(gal/min) Volume (MG)
01/6/16 0600
01/7/16 0000
19.0 (est)
0.020
Collection Method
Composite
Table 2 Entrainment Summary by Quarter
Quarter Year
Specles/Family
Total Collected
Sample Volume
(MG)
Total # Entrained1
1 2016 Thunnus albacares (yellowfin tuna)
0
0.020
0
1 2016 Lutjanus campechanus(red snapper)
0
0.020
0
Total 2016 Thunnus albacares (yellowfin tuna)
0
N/A
0
Total 2016 Lutjanus campechanus{red snapper)
0
N/A
0
1 Projected number of organisms entrained per quarter based on an average cooling water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00156
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00157
Attachment A Data Sheet Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St. Malo Platform
Collection Date
Project Number
Names of Personnel Collecting Samples
1/6/2016 \ o n o n ,? Kent Ertan, Clark Bergeron, Clint Ward
Sample Collection Flow Rate Sample Event Start Time and Date Sample Event End Time and Date Weather Conditions during each cycle Number of Sample Jars Filled
Sample Collection Method
Other Notes Relevant to Sampling Event
~ \\ G P M
i -6-2 16
n io O O
1-7-2016 [ a O O A m
5'--7' seas Clear sky 75 degrees
4
,
Side Stream
Normal operations. No facility upset Sea water Lift Pump on line entire time.
Flow Rate unknown. Operators commented valves were open as on the last sample
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00158
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00159
cr A S S O C I A T E S - L L C
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WHITE COPY TO ACCOMPANY SAMPLE RETAIN YELLOW COPY FOR FILES RETAIN PINK COPY FOR FIELD SUPERVISOR
CK-100
1 7 1 7 0 P E R K IN S R O A D B A T O N R O U G E , LA 70810
P H O N E (2 2 5 ) 7 5 5 -1 0 0 0 F A X (2 25) 7 5 1 -2 0 1 0
http ://w w w .c-ka.com
May 10, 2016
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2811 3 9 7 -9 0 1 6
F A X (2811 3 9 7 -6 6 3 7
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F A X (31 8 ) 7 9 8 - 0 4 7 8
Re: Second Quarter 2016 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the second quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CWIS in accordance with section 12.c.2.ii of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf of the Gulf o f Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 m icrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 2000 hours on April 5, 2016 and lasted until 2000 hours on April 6, 2016. The EMD was operated continuously during the sampling period at a flow rate of 7.0 gallons per minute resulting in an entrainm ent sample volum e of 10,080 gallons. Sample collection data are summarized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00161
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. In addition to any key species of concern identified, there were other ichthyoplankton observed in the sample. Two additional fish eggs were found; however, they could not be identified because of the lack of developm ent structures. There were no additional fish larvae observed in the sample, see Table 3. Other entrained organism s that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included Am phipods, Mysid shrimp, polychaetes, ctenophores, copepods, pteropods, chaetognaths, see Table 4. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent sam ples collected from the JSM FPU during its second calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or com m ents regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00162
Quarter Year 2 2016
Table 1 Sample Collection Data Summary by Quarter
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
04/5/16 2000
04/6/16 2000
7.0 (est)
0.010
Collection Method
Composite
Table 2 Entrainment Summary by Quarter (Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total Collected
Eggs
Total Collected
Larvae
Sample Volume
(MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
Thunnus albacares (yellowfin tuna)
0
0
0
0
1
Z U 1 Lutjanus campechanus{red snapper)
0
0
u.uzu
0
0
Thunnus albacares (yellowfin tuna)
0
0
0
0
Z
Z U u Lutjanus campechanus(red snapper)
0
0
U .U 1U
0
0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus(red snapper)
0
0
N/A
0
0
1 Projected num 3er of organisms entrained per quarter based on an average coo Ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton (Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total Collected
Eggs
Total Collected
Larvae
Sample Volume
(MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
Scaridae Mugilidae
0
1
0
121,940
0
3
0.020
0
365,820
2
2016
N/A
2
0
487,760
0
0
0
0.010
0
0
Total 2016
Eggs
2
0
N/A
487,760
0
Total 2016
Larvae
0
4
N/A
0
487,760
1 Projected num 3er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
A m p h ip o d s
Table 4 Other Non-lchthyoplankton Entrained Organisms
Chaetognaths
Copepods
Ctenophores
Polychaetes
Mysid shrimp
Pteropods
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00163
ATTACH MENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00164
Attachment A Data Sheet
Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater
Jack St. Malo Platform
Collection Date
Project Number
Names of Personnel Collecting Samples
\ D Q - QlL ,
Sample Collection Flow Rate
~7 --
Sample Event Start Time and Date
Sample Event End Time and Date
b> - /
Weather Conditions during each cycle
Number of Sample Jars Filled
d 4 l'v v 2 &A-S C l
Sample Collection Method
t\ h
,,S c/c
Other Notes Relevant to Sampling Event
l '. o o
-S T
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00165
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00166
A S S OC I A T E S LLC
ENVIRONMENTAL & ENGINEERING CONSULTANTS
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
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Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
W HITE CO PY TO A CCO M PA N Y SAMPLE RETAIN YELLOW C O P Y FOR FILES RETAIN P IN K C O P Y FO R FIELD SU PERVISO R
CK-100
ED 002061 00130976-00167
CK A ssociates
Li':'-
Cwww.w:
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
August 8, 2016
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
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SH R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 18) 7 9 8 -0 4 7 8
Re: Third Quarter 2016 Entrainment Monitoring Report for the Chevron Jack and St. Maio Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the third quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU
CWIS in accordance with section 12.c.2.ii of the NPDES General Permit for New and Existing Sources and New Dischargers in the Offshore Subcategory of the Oil and Gas Extraction Point Source Category for the Western Portion of the Outer Continental Shelf of the Gulf of Mexico (GMG290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 0900 hours on July 4, 2016 and lasted until 0900 hours on July 5, 2016. The EMD was operated continuously during the sampling period at a flow rate of 34.4 gallons per minute resulting in an entrainm ent sample volume of 49,536 gallons. Sample collection data are summarized in Table 1. Upon sam pling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00168
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. In addition to any key species of concern identified, there were other ichthyoplankton observed in the sample. One additional fish egg was found. There were no additional fish larvae observed in the sample, see Table 3. Other entrained organism s that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included Amphipoda, Acetes americanus caroiinae, Ctenophores, copepods, pteropoda, Chaetognatha, see Table 4. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent samples collected from the JSM FPU during its third calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00169
Quarter 3
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
Collection Method
2016
07/4/16 0900
07/5/16 0900 34.4 (est)
0.049
Composite
Table 2 Entrainment Summary by Quarter
(Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
Thunnus albacares (yellowfin tuna) Lutjanus campechanus{red snapper)
0 0
0
0
0
0.020
0
0 0
9
2016
Thunnus albacares (yellowfin tuna) Lutjanus campechanus(red snapper)
0 0
0
0
0
0.010
0
0 0
Thunnus albacares (yellowfin tuna)
0
0
0
0
j
2016 Lutjanus campechanus(red snapper)
0
0
0.049
0
0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus(red snapper)
0
0
N/A
0
0
1Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton (Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
Scaridae Mugilidae
0
1
0.020
0
121,940
0
3
0
365,820
2
2016
N/A
2
0
0.010 487,760
0
3
2016
Clupeidae
1
0
0.049
49,771
0
Total 2016
Eggs
3
0
N/A
537,531
0
Total 2016
Larvae
0
4
N/A
0
487,760
1Projected num >er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00170
Table 4 Other Non-lchthyoplankton Entrained Organisms
Acetes americanus carolinae copepods
Amphipoda Ctenophores
Chaetognatha pteropods
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00171
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00172
Attachment A Data Sheet
Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater
.
Jack St. Malo Platform
Collection Date
7 /4 h i
Project Number
/0 7 2 &
Names of Personnel Collecting Samples
/F th n / J o e / l//'< /rn t
Sample Collection Flow Rate Sample Event Start Time and Date
34M or- i in lz tiL
Sample Event End Time and Date
o rto / ilffc v L
Weathr Conditions during each cycle
Number of Sample Jars Filled
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Sample Collection Method
f i F 'e r t J F c /tm 1 ^ 6 F F
Other Notes Relevant to Sampling Event
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00173
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00174
ASSOCIATES
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CO
ED 002061 00130976-00175
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W HITE C O P Y TO ACCO M PAN Y SAM PLE RETAIN Y ELLO W C O P Y FO R FILES RETAIN P IN K C O P Y FO R FIELD SU P ER V ISO R
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CK A ssociates
Li':'-
Cwww.w:
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
November 4, 2016
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Sent Via Email
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 1 8 ) 7 9 8 -0 4 7 8
Re: Fourth Quarter 2016 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the fourth quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CWIS in accordance with section 12.c.2.ii of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf o f the Gulf o f Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 1815 hours on October 21, 2016 and lasted until 1215 hours on October 22, 2016. The EMD was operated continuously during the sampling period at a flow rate of 13.4 gallons per minute resulting in an entrainm ent sample volume of 14,472 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00176
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. There were no additional ichthyoplankton (eggs/larvae) observed in the sample see Table 3. Other entrained organisms that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included copepods, Chaetognatha, Callinectes sapidus (two - megalopa) see Table 4. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent sam ples collected from the JSM FPU during its fourth calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00177
Quarter 4
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
Collection Method
2016
10/21/16 1815
10/22/16 1215 13.4 (est)
0.014
Composite
Table 2 Entrainment Summary by Quarter (Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
Thunnus albacares (yellowfin tuna)
0
0
0
0
1
2016
0.020
Lutjanus campechanus(red snapper)
0
0
0
0
Thunnus albacares (yellowfin tuna)
0
0
0
0
2
2016
0.010
Lutjanus campechanus(red snapper)
0
0
0
0
Thunnus albacares (yellowfin tuna)
0
0
0
0
3
2016
0.049
Lutjanus campechanus(red snapper)
0
0
0
0
4
2016
Thunnus albacares (yellowfin tuna)
0
0
0.014
0
0
Lutjanus campechanus(red snapper)
0
0
0
0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus(red snapper)
0
0
N/A
0
0
1Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton (Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
Scarldae Mugllidae
0
1
0.020
0
121,940
0
3
0
365,820
2
2016
N/A
2
0
0.010 487,760
0
3
2016
Clupeldae
1
0
0.049
49,771
0
4
2016
N/A
0
0
0.014
0
0
Total 2016
Eggs
3
0
N/A
537,531
0
Total 2016
Larvae
0
4
N/A
0
487,760
1Projected num 3er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00178
Table 4 Other Non-lchthyoplankton Entrained Organisms
copepods
Chaetognatha
Callinectes sapidus (2 - megalopa)
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00179
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00180
Attachment A - Example Data Sheet Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St. Malo Platform
Collection Date
Project Number
Names of Personnel Collecting Samples
/ h i k o
10726
Sample Collection Flow Rate
Sample Event Start Time and Date
Sample Event End Time and Date
Weather Conditions during each
cyde
Number of Sampie Jars Filled
Sample Method
Other Notes Relevant to Sampling Event
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Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00181
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00182
CHAIN OF CUSTODY
A S S O C I A T E S LLC
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ENVIRONMENTAL & ENGINEERING C O NS U LIANTS
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CK-100
17170 PERKINS ROAD
B A T O N R O U G E , LA 70810 P H O N E (2 2 5 ) 7 5 5 -1 0 0 0 F A X (2 25) 7 5 1 -2 0 1 0
http ://w w w .c-ka.com
April 12, 2017
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Jim .flo yd@ chevron .com
H O U ST O N , TX P H O N E (2811 3 9 7 -9 0 1 6
F A X (2811 3 9 7 -6 6 3 7
LA K E C H A R L E S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
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S H R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (31 8 ) 7 9 8 - 0 4 7 8
Re: First Quarter 2017 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the first quarter 2017 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CWIS in accordance with section 12.c.2.ii of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf of the Gulf o f Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 m icrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 2100 hours on January 5, 2017 and lasted until 2100 hours on January 6, 2017. The EMD was operated continuously during the sampling period at a flow rate of 20.0 gallons per minute resulting in an entrainm ent sample volume of 28,800 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00184
Sample Results
Samples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. T h e se species were identified in the FPU's general permit application as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CW IS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. There were additional ichthyoplankton larvae observed in the sample, see Table 3. One possible Gempylidae, however only the head was present and it was difficult to identify any further. Additionally, there were three Haemulidae and two Sparidae, but again both were too damaged to be identify further. There were no ichthyoplankton eggs observed in the sample see Table 3. Other entrained organisms that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included copepoda, ctenophora, Chaetognatha, Amphipoda, Lucifer faxoni, Bronchiostoma floridae, Cladoceran, Polychaete, bivalve and pteropoda see Table 4. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent samples collected from the JSM FPU during its first calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comm ents regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@c-ka.com .
Sincerely yours, CK Associates
James L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00185
Quarter 1
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
Collection Method
2017
01/5/17 2100
01/6/17 2100 20.0 (est)
0.029
Composite
Table 2 Entrainment Summary by Quarter (Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total Collected
Eggs
Total Collected
Larvae
Sample Volume
(MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2017
Thunnus albacares (yellowfin tuna)
0
0
0.029
0
0
Lutjanus compechanus (red snapper)
0
0
0
0
Total 2017 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2017 Lutjanus campechanus (red snapper)
0
0
N/A
0
0
1 Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton
(Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total Collected
Eggs
Total Collected
Larvae
Sample Volume
(MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
Gempylidae
0
1
0
84,097
1
2017
Haemulidae Sparidae
0
3
0.029
0
252,290
0
2
0
168,193
Total 2017
Larvae
0
6
N/A
0
504,580
1 Projected num jer of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 4 Other Non-lchthyoplankton Entrained Organisms
copepoda Amphipoda Cladoceran
Ctenophora Lucifer faxoni
Polychaete pteropoda
Chaetognatha Bronchiostoma floridae
Bivalve
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00186
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00187
Attachment A - Data Sheet Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St. Malo Platform
Collection Date
. 6
\/jb /n
kin
Project Number
10726
Names of Personnel Collecting Samples
Sample Collection Flow Rate
Sample Event Start Time and Date
Sample Event End Time and Date
Weather Conditions during each cycle
Numberof Sample Jars Filled
4
Sample Method
Other Notes Relevant to Sampling Event
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Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00188
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00189
ASSOCIATES ILC
ENVJJONM ENTAl L ENGINEERING CONSULTANTS
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
C L IE N T !
P . O . H U M B E R : " & 0 E ........
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1 7 1 7 0 P E R K IN S R O A D B A T O N R O U G E , LA 708 10
P H O N E (2 2 5 ) 7 5 5 -1 0 0 0 F A X (2 2 5 ) 7 5 1 -2 0 1 0
http://www.c-ka.com
July 1, 2016
Ms. Ellen Thomson Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, TX 77380
Ellen.Thomson@anadarko.com
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
SH R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 18) 7 9 8 -0 4 7 8
Re: Second Quarter 2016 Entrainment Monitoring Report for the Heidelberg Spar Production Facility CK Project No. 13096
Dear Ms. Thomson:
CK Associates (CK) is providing this letter report to Anadarko Petroleum Corporation (Anadarko) to summarize the findings of the second quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Heidelberg Spar production facility (HSPF). The HSPF is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the HSPF CWIS in accordance with section 12.C.2. of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion of the Outer Continental Shelf o f the Gulf of Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Anadarko personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s) and seawater basket strainers. The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the HSPF cooling water system downstream of the initial slip stream collection location.
The sampling process began at 0815 hours on June 9, 2016 and lasted until 0815 hours on June 10, 2016. The EMD was operated continuously during the sampling period (24 hours) at a flow rate of 14.0 gallons per minute resulting in an entrainm ent sample volum e of 20,160 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00191
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the HSPF CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. In addition to any key species of concern identified, there were no ichthyoplankton observed in the sample, see Table 3. Other entrained organism s that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included chaetognaths, copepods and polychaetes, see Table 4. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent sam ples collected from the HSPF during its second calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the HSPF CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00192
Quarter 2
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
2016 06/9/16 0815
06/10/16 0815 14.0 (est)
0.020
Collection Method Composite
Table 2 Entrainment Summary by Quarter
(Key Important Commercial and Recreational Species of Concern)
Quarter Year
Specles/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
Thunnus albacares (yellowfin tuna)
0
0
0
0
1
zu io Lutjanus campechanus(red snapper)
0
0
u.zu
0
0
z
ZUlu
Thunnus albacares (yellowfin tuna) Lutjanus campechanus(red snapper)
0 0
0 0
u.uzu
0 0
0 0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus(red snapper)
0
0
N/A
0
0
1Projected num ber of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton
(Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
N/A
0
0
0
0
0
0
0.20
0
0
2
2016
N/A
0 0
0 0
0.020
0 0
0 0
Total 2016
Eggs
0
0
N/A
0
0
Total 2016
Larvae
0
0
N/A
0
0
1Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Chaetognaths
Table 4 Other Non-lchthyoplankton Entrained Organisms
Copepods
Polychaetes
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00193
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00194
A TTA CH M EN T A
Attachment C - Sampling Data Sheet Cooling Water Intake Structure Entrainment Sampling Procedures
Anadarko Petroleum Corporation Heidelberg Spar Production Facility
Collection Dates
Name(s) of Personnel Collecting Samples
Sample Event Start Time Flow reading after 1 min Sample Event End Time Total Time Sampled
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Other Notes Relevant to Sampling Event
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00195
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00196
ED 002061 00130976-00197
A S S O C I A T E S * LLC
ENVIRONMENTAL & ENGINEERING CONSULTANTS
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
Page.
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(0
CKAssociates
17170 PERKINS ROAD BATON ROUGE, LA 70810
PHONE (225) 755-1000 FAX (225) 751-2010
http://www.c-ka.com
October 24, 2016
Ms. Ellen Thomson Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, TX 77380
Ellen.Thomson@anadarko.com
H O U ST O N , TX P H O N E (2 8 !) 3 9 7 -9 0 1 6
F A X (2 8 !) 3 9 7 -6 6 3 7
LA K E C H A R LE S, LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (3 1 8 ) 7 9 8 -0 4 7 8
Re: Third Quarter 2016 Entrainment Monitoring Report for the Heidelberg Spar Production Facility CK Project No. 13096
Dear Ms. Thomson:
CK Associates (CK) is providing this letter report to Anadarko Petroleum Corporation (Anadarko) to summarize the findings of the third quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Heidelberg Spar production facility (HSPF). The HSPF is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the HSPF CWIS in accordance with section 12.C.2. of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf o f the Gulf of Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Anadarko personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s) and seawater basket strainers. The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the HSPF cooling water system downstream of the initial slip stream collection location.
The sampling process began at 1030 hours on September 23, 2016 and lasted until 1030 hours on September 24, 2016. The EMD was operated continuously during the sampling period (24 hours) at a flow rate of 4.0 gallons per minute resulting in an entrainm ent sample volum e of 5,760 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00198
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the HSPF CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. In addition to any key species of concern identified, there were no ichthyoplankton observed in the sample, see Table 3. Other entrained organism s that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included chaetognaths, copepods, polychaetes and ctenophores, see Table 4. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent sam ples collected from the HSPF during its third calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the HSPF CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00199
Quarter 3
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
2016 09/23/16 1030 09/24/16 1030 4.0 (est)
0.006
Collection Method Composite
Table 2 Entrainment Summary by Quarter (Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
Thunnus albacares (yellowfin tuna)
0
0
0
0
1
Z U lO
Lutjanus campechanus{red snapper)
0
0
u.zu
0
0
Thunnus albacares (yellowfin tuna)
0
0
0
0
Z
zuo Lutjanus campechanus(red snapper)
0
0
u.uzu
0
0
jo
im a
Thunnus albacares (yellowfin tuna)
Lutjanus campechanus (red snapper)
0 0
0
n nnc
0
0
0
0 0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus(red snapper)
0
0
N/A
0
0
1Projected num jer of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 3 Other Ichthyoplankton (Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
N/A
0
0
0.20
0
0
0
0
0
0
2
2016
N/A
0
0
0
0
0
0
0.020
0
0
3
2016
N/A
0
0
0
0
0
0
0.006
0
0
Total 2016
Eggs
0
0
N/A
0
0
Total 2016
Larvae
0
0
N/A
0
0
1Projected num >er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Chaetognaths
Table 4 Other Non-lchthyoplankton Entrained Organisms
Copepods
Ctenophores
Polychaetes
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00200
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00201
Attachment C - Sampling Data Sheet Cooling Water Intake Structure Entrainment Sampling Procedures
Anadarko Petroleum Corporation Heidelberg Spar Production Facility
Collection Dates
Name(s) of Personnel Collecting Samples Sample Event Start Time Flow reading after 1 min Sample Event End Time Total Time Sampled
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Other Notes Relevant to Sampling Event
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00202
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00203
ED 002061 00130976-00204
CO
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CHAIN OF CUSTODY AND
Page_
of
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B A T O N R O U G E , LA 70810 P H O N E (2 2 5 ) 7 5 5 -1 0 0 0 F A X (2 25) 7 5 1 -2 0 1 0
http ://w w w .c-ka.com
January 16, 2017
Ms. Ellen Thomson Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, TX 77380
Ellen.Thomson@anadarko.com
H O U ST O N , TX P H O N E (2811 3 9 7 -9 0 1 6
F A X (2811 3 9 7 -6 6 3 7
LA K E C H A R L E S , LA P H O N E (3 3 7 )6 2 5 -6 5 7 7
F A X (3 3 7 )6 2 5 -6 5 8 0
S H R E V EP O R T, LA P H O N E (3 1 8 ) 7 9 7 -8 6 3 6
F A X (31 8 ) 7 9 8 - 0 4 7 8
Re: Fourth Quarter 2016 Entrainment Monitoring Report for the Heidelberg Spar Production Facility CK Project No. 13096
Dear Ms. Thomson:
CK Associates (CK) is providing this letter report to Anadarko Petroleum Corporation (Anadarko) to summarize the findings of the fourth quarter 2016 entrainment monitoring event for intake water collected from the cooling water intake structure (CW IS) aboard the Heidelberg Spar production facility (HSPF). The HSPF is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the HSPF CWIS in accordance with section 12.C.2. of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf of the Gulf of Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Anadarko personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s) and seawater basket strainers. The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the HSPF cooling water system downstream of the initial slip stream collection location.
The sampling process began at 0925 hours on Decem ber 17, 2016 and lasted until 0925 hours on December 18, 2016. The EMD was operated continuously during the sampling period (24 hours) at a flow rate of 8.0 gallons per minute resulting in an entrainm ent sample volum e of 11,520 gallons. Sample collection data are sum m arized in Table 1. Upon sampling termination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00205
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the HSPF CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. There were no additional ichthyoplankton (eggs/larvae) observed in the sample see Table 3. Other entrained organisms that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples included Chaetognaths, copepods and pteropods, see Table 4. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent samples collected from the HSPF during its fourth calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the HSPF CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comm ents regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@c-ka.com .
Sincerely yours, CK Associates
James L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00206
Quarter 4
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
2016 12/17/16 0925
12/18/16 0925
8.0 (est)
0.012
Collection Method Composite
Quarter Year
1
2016
Table 2
Entrainment Summary by Quarter
(Key Important Commercial and Recreational Species of Concern)
Total
Total Sample Total #
Species/Family
Collected Collected Volume
Eggs
Eggs
Larvae (MG) Entrained1
Thunnus albacares (yellowfin tuna)
0
Lutjanus campechanus{red snapper)
0
0 0
0.20
0 0
Total # Larvae Entrained1
0 0
z
2016
Thunnus albacares (yellowfin tuna) Lutjanus campechanus{red snapper)
0 0
0 0
0.020
0 0
0 0
JQ
2016
Thunnus albacares (yellowfin tuna) Lutjanus campechanus (red snapper)
0 0
0 0
0.006
0 0
0 0
Thunnus albacares (yellowfin tuna)
0
0
0
0
A
2016
0.012
Lutjanus campechanus (red snapper)
0
0
0
0
Total 2016 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2016 Lutjanus campechanus{red snapper)
0
0
N/A
0
0
1 Projected number of organisms entrained per quarter based on an average coo ing water flow equal to 26.8
MGD for a 91-day quarter
Table 3
Other Ichthyoplankton
(Non Key Commercial and Recreational Species of Concern)
Quarter Year
Species/Family
Total Collected
Eggs
Total Collected
Larvae
Sample Volume
(MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2016
N/A
0
0
0.20
0
0
0
0
0
0
2
2016
N/A
0
0
0
0
0
0
0.020
0
0
3
2016
N/A
0 0
0 0
0.006
0 0
0 0
4
2016
N/A
0 0
0 0
0.012
0 0
0 0
Total 2016
Eggs
0
0
N/A
0
0
Total 2016
Larvae
0
0
N/A
0
0
1 Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00207
Chaetognaths
Table 4 Other Non-lchthyoplankton Entrained Organisms
copepods
pteropods
Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00208
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00209
Attachment C - Sampling Data Sheet Cooling Water Intake Structure Entrainment Sampling Procedures
Anadarko Petroleum Corporation Heidelberg Spar Production Facility
Collection Dates
/ L -/1 -
Name(s) of Personnel Collecting Samples
(Z o / 'T I (3 < ? u X
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Other Notes Relevant to Sampling Event
H&
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00210
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00211
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:71 7 0 P E R K IN S R O A D B A T O N R O U G E , LA 708 10
P H O N E (2251 7 5 5 -1 0 0 0 F A X (2 2 5 ) 7 5 1 -2 0 :0
http://www.c-ka.com
April 21, 2017
Ms. Sofia Lamon Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, TX 77380 so fia.lam on@ anadarko.com
HOUSTON, rx PHONE (2811 397-9016
FAX (28!) 397-6637
LAKE CHARLES, LA PHONE (337)625-6577
FAX (337)625-6580
SHREVEPORT, LA PHONE (318) 797-8636
FAX (31 8) 798-0478
Re: First Quarter 2017 Entrainment Monitoring Report for the Heidelberg Spar Production Facility CK Project No. 13096
Dear Ms. Lamon:
CK Associates (CK) is providing this letter report to Anadarko Petroleum Corporation (Anadarko) to summarize the findings of the first quarter 2017 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Heidelberg Spar production facility (HSPF). The HSPF is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the HSPF CWIS in accordance with section 12.C.2. of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf o f the Gulf of Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Anadarko personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s) and seawater basket strainers. The slip stream is passed through an entrainment monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the HSPF cooling water system downstream of the initial slip stream collection location.
The sampling process began at 1316 hours on March 15, 2017 and lasted until 1317 hours on March 16, 2017. The EMD was operated continuously during the sampling period (24 hours) at a flow rate of 11.0 gallons per minute resulting in an entrainm ent sample volume of 15,840 gallons. Sample collection data are sum m arized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00213
Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the HSPF CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae per cubic meter and zero key species of concern entrained per day. A sum m ary of the entrained key species of concern is included in Table 2. There were no additional ichthyoplankton (eggs/larvae) observed in the sample see Table 3. Other entrained organisms that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainm ent samples were Copepods, see Table 4. None of these organism s should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent samples collected from the HSPF during its first calendar quarter of entrainment monitoring for 2017. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the HSPF CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin@ c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00214
Quarter 1
Year 2017
Table 1
Sample C o lle ctio n D ata Sum m ary by Q u a rte r
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
03/15/2017 1316 03/16/2017 1317 11.0 (est)
0.016
Collection Method Composite
Table 2
Entrainm ent Sum m ary by Q uarter
Quarter Year
1
2017
(Key Im portant Com m ercial and R ecreational Species of Concern)
Total
Total Sample Total #
Species/Family
Collected Collected Volume
Eggs
Eggs
Larvae (MG) Entrained1
Thunnus albacares (yellowfin tuna)
0
Lutjanus campechanus(red snapper)
0
0
0
0
0.016
0
Total # Larvae Entrained1
0
0
Total 2017 Thunnus albacares (yellowfin tuna)
0
0
N/A
0
0
Total 2017 Lutjanus cam pechanus (red snapper)
0
0
N/A
0
0
1Projected num jer of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter.
Table 3
O ther Ichthyoplankton
(N on Key Com m ercial and R ecreational Species of Concern)
Quarter Year
Species/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2017
N/A
0
0
0.016
0
0
0
0
0
0
Total 2017
Eggs
0
0
N/A
0
0
Total 2017
Larvae
0
0
N/A
0
0
1Projected num )er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter.
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00215
Table 4
Other Non-lchthyoplankton Entrained Organisms
Organism
Total Number Collected
Copepods
6
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00216
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00217
Attachment C - Sampling Data Sheet Cooling Water Intake Structure Entrainment Sampling Procedures
Anadarko Petroleum Corporation Heidelberg Spar Production Facility
Collection Dates
3 /l5l
Name(s) of Personnel Collecting Samples
Sample Event Start Time Flow reading after 1 min Sample Event End Time
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Other Notes Relevant to
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M /ft________________
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00218
ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00219
O ASSOCIATES
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------------------ ---------------------------------------------------------in o u r B a to n R o u g e , L a ke C h a rle s , S h re v e p o rt, H o u s to n O ffic e
WHITE COPY TO A C C O M P A N Y SA M P LE RETA IN Y E L L O W C O P Y F O R FILES R ETA IN P IN K C O P Y F O R FIELD S U P E R V IS O R
CK-1 00
A ssociates
:71 7 0 P E R K IN S R O A D B A T O N R O U G E , LA 708 10
P H O N E (2251 7 5 5 -1 0 0 0 F A X (2 2 5 ) 7 5 1 -2 0 :0
http://www.c-ka.com
May 5, 2017
Chevron USA 100 Northpark Blvd. Covington, LA 70433
Attn: Jim Floyd
Jim .floyd@ chevron .com
HOUSTON, rx PHONE (2811 397-9016
FAX (28!) 397-6637
LAKE CHARLES, LA PHONE (337)625-6577
FAX (337)625-6580
SHREVEPORT, LA PHONE (318) 797-8636
FAX (31 8) 798-0478
Re: Second Quarter 2017 Entrainment Monitoring Report for the Chevron Jack and St. Malo Floating Production Unit CK Project No. 10726
Dear Mr. Floyd:
CK Associates (CK) is providing this letter report to Chevron USA (Chevron) to summarize the findings of the second quarter 2017 entrainment monitoring event for intake water collected from the cooling water intake structure (CWIS) aboard the Jack and St. Malo (JSM) floating production unit (FPU). The JSM FPU is a fixed facility, for which construction was commenced after July 17, 2006. Therefore, quarterly entrainm ent monitoring is required for the JSM FPU CWIS in accordance with section 12.c.2.ii of the NPDES General Perm it fo r New and Existing Sources and New Dischargers in the Offshore Subcategory o f the Oil and Gas Extraction Point Source Category fo r the Western Portion o f the Outer Continental Shelf o f the Gulf o f Mexico (GM G290000) (general permit), effective October 1, 2012.
Sample Collection
Entrainment samples were collected by Chevron personnel from a slip stream of the cooling water system. The slip stream begins downstream of the CWIS intake screens and upstream of the facility heat exchanger(s). The slip stream is passed through an entrainm ent monitoring device (EMD) consisting of a closed conduit with a 330 micrometer screen in line with the flow after which the stream is returned to the JSM cooling water system downstream of the facility heat exchanger(s).
The sampling process began at 0700 hours on April 4, 2017 and lasted until 0700 hours on April 5, 2017. The EMD was operated continuously during the sampling period at a flow rate of 10.0 gallons per minute resulting in an entrainm ent sample volume of 14,400 gallons. Sample collection data are summarized in Table 1. Upon sampling term ination, the screen was removed from the EMD and washed of entrained particles into sample jars containing 10% buffered formalin. The sample jars were packed in an ice chest and shipped to CK for processing and species identification by a fisheries biologist. See attachments A and B for a copy of the field data sheet and chain of custody documentation respectively.
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Sample Results
Sam ples were analyzed for the presence of eggs and larvae from yellowfin tuna, and red snapper. These species were identified in the FPU's general permit application as key representative commercial and recreational species of concern because eggs and larvae of these species are considered to be most likely to be entrained in the JSM CWIS.
Zero yellowfin tuna eggs/larvae and zero red snapper eggs/larvae were identified during sample analysis. When normalized to the total facility flow, this entrainment rate amounts to zero eggs/larvae of key species of concern per cubic meter entrained per day. A summary of the entrained key species of concern is included in Table 2. There was an additional non-target ichthyoplankton larvae observed in the sample, see Table 3. One M icrodesmidae, however the larvae was too damaged to identify further. There were no additional non-target ichthyoplankton eggs observed in the sample see Table 3. Other entrained organism s that were not listed as key species of concern and are not ichthyoplankton, but that were found in the entrainment samples included several Copepoda, see Table 4. None of these organisms should be included as part of the discharge monitoring report submittal because they do not represent key important commercial and recreational species of concern.
Conclusions
Zero organisms of key important commercial and recreational species of concern were identified in entrainm ent sam ples collected from the JSM FPU during its first calendar quarter of entrainment monitoring. Based on the analysis of the entrainment monitoring samples, engineering controls installed at the JSM FPU CWIS have successfully minimized the potential for environm ental, socioeconomic, and ecological damage due to entrainm ent in the facility CWIS.
If you have any questions or comments regarding this report, please do not hesitate to contact me at (255) 755-1000 or via email at James.Durbin(5)c-ka.com .
Sincerely yours, CK Associates
Jam es L. Durbin Senior Environmental Scientist
Attachments: As referenced
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ED 002061 00130976-00222
Quarter
1 2
Table 1 Sample Collection Data Summary by Quarter
Year
Start Date and Time
Stop Date and Time
Sample Flow Rate (gal/min)
Sample Volume (MG)
Collection Method
2017 2017
01/5/17-2100 04/04/17-0700
01/6/17-2100 04/05/17-0700
20.0 (est) 10.0 (est)
0.029 0.014
Composite Composite
Table 2 Entrainment Summary by Quarter (Key Important Commercial and Recreational Species of Concern)
Quarter Year
Species/Famlly
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2017
Thunnus aibacares (yellowfin tuna)
0
0
0.029
0
0
Lutjanus campechanus (red snapper)
0
0
0
0
Thunnus aibacares (yellowfin tuna)
0
0
0
0
2
2017 Lutjanus campechanus (red snapper)
0
0
0.014
0
0
Total 2017 Thunnus aibacares (yellowfin tuna)
0
0
N/A
0
0
Total 2017 Lutjanus campechanus (red snapper)
0
0
N/A
0
0
1Projected num >er of organisms entrained per quarter based on an average coo ing water flow equal to 26.8
MGD for a 91-day quarter
Table 3
Other Ichthyoplankton
(Non Key Commercial and Recreational Species of Concern)
Quarter Year
Specles/Family
Total
Total Sample
Collected Collected Volume
Eggs
Larvae (MG)
Total #
Total #
Eggs
Larvae
Entrained1 Entrained1
1
2017
2
2017
Gempylidae Haemulidae
Sparidae Microdesmidae
0
1
0
84,097
0
3
0.029
0
252,290
0
2
0
168,193
0
1
0.014
0
174,200
Total 2017
0
7
N/A
0
678,780
1Projected num jer of organisms entrained per quarter based on an average coo ing water flow equal to 26.8 MGD for a 91-day quarter
Table 4 Other Non-lchthyoplankton Entrained Organisms
Copepoda
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ED 002061 00130976-00223
ATTACHMENT A DATA SHEET FOR SAMPLE EVENT
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ED 002061 00130976-00224
Attachment A - Example Data Sheet Cooling Water Intake Structure Entrainment Sampling and Monitoring Procedures
Chevron North America Exploration and Production Company Deepwater Jack St. Male Platform
Collection Date Project Number
4/5/2017 10726
Names of Personnel Collecting Samples
Sample Collection Flow Rate Sample Event Start Time and'Date Sample Event End Time and Date
Weather Conditions during each cycle
Number of Sample Jars Filled
Sample Method
Other Notes Relevant to Sampling Event
C e d ric Milton
1GPM 0700 yf /T?//7
0700 9/4/7____________
S e a s 4 to 6 W inds 10 to 12 Knots
ntrainment
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ATTACHMENT B CHAIN-OF-CUSTODY FOR SAMPLE EVENT
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A S S O C I A T E S LLC
ENVIRONMENTAL & ENGINEERING CONSULTANTS
cu m i* . 4 e p w ^ M
CHAIN OF CUSTODY AND
ANALYTICAL REQUEST RECORD
j , /& p.o, n u m ber?
Page.
of
SAMPLED BY; .^J ^ J
PROJECT NO.: .J . *?&.Cp___________ -- LA BO RATO RY*; C f c
SAMPLE IDENTIFICATION
DATE
TIME
MATRIX
NO. OF CONTAINERS
PRESERVATIVE
f1 (
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ANALYSES AND INSTRUCTIONS
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in our D Baton Rouge, D Lake Charles, Q Shreveport, Q Houston Office a;
W HITE CO PY TO ACCOM PANY SAM PLE RETAIN YELLO W C O P Y FO R FILES RETAIN P IN K C O P Y FO R FIELD SU PERVISO R
C K -1 0 0
W
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Kurtis Schlicht, Bill Stephens, Emily Lantz
Date: Subject:
10 April 2015
Quarter 1 (January-March) 2015 Entrainment Sampling Results
Environmental Resources Management
CityCentre Four 840 West Sam Houston Parkway North, Suite 600 Houston, Texas 77024-3920 T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, development, and production facilities located in and discharging to federal waters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastewater and storm water in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith conditions that the permittee agrees to a variety of effluent limitations, monitoring, reporting, and cooling water intake structure (CWIS) requirements.
Samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t sampling requirements for Quarter 1 2015 (Q1 2015). A description of the sampling procedures and analytical results of the Q1 2015 event are presented in the following paragraphs
Procedure
ERM staff travelled to Lucius under Anadarko supervision on March 9, 2015. Sampling began at 00:00 on the m orning of March 10, 2015. Samples were collected every six hours (06:00,12:00, 18:00) until four 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. Samples remained in the possession of the sample team during the transport to shore.
Once onshore, entrainm ent samples were shipped within 24 hours to Ecological Associates, Inc. (EAI), with chain-of-custody documentation included in the shipment. Samples w ere processed by EAI during a 45-60 day period.
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level.
Texas Registered Engineering Firm F-2393 Texas Board of Professional Geoscientists Firm 50036
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ED 002061 00130976-00228
Memorandum
Page 2
Sampling Results
A total of 2,597 organisms were present in the 100m3 of water sampled. Of these organisms, 21 were fish and shellfish (also know n as "Target" organisms, per EAI nomenclature): 2 fish larvae and 19 fish eggs. Table 1 below indicates the types, numbers, and lifestages of the fish w ithin the March 10, 2015 sample. Table 2 below indicates the types, numbers, and lifestages of the non-fish species w ithin the March 10, 2015 sample.
Table 1. Laboratory Analysis of Ichthyoplankton Samples Collected During Event 1 on March 10, 2015 at the Anadarko Lucius Truss Spar Platform: Target Organisms.
i a\a
C lil/\o li i ifesiage Sample* I Sample 2 Sample 3 Sample 4
citi
Invertebrates
Collection linn* 00:00
Oh:00
12:00
18:00
Fish
A ulostom us
Post Yolk-
1
m aculatus
Sac Larvae
Unidentified fish -
Post Yolk-
1
damaged
Sac Larvae
Fish total
1
1
Fish Eggs
Unidentified eggs - No embryos
Egg
3
3
1
12
Fish Eggs Total
3
3
1
12
Tol.il Combined
3
4
1
13
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans. None present in
samples.
Total
1 1 2 19 19 21
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Memorandum
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Table 2. Laboratory Analysis of Ichthyoplankton Samples Collected During Event 1 on March 10, 2015 at the Anadarko Lucius Truss Spar Platform: Non-target Organisms.
Taxa
( R I/\on -( RI l.ifesUige
Invertebrates
Collection lime
Crustaceans
Amphipoda
Non-CRI
Other
Portunus sp.
Non-CRI
Megalops
Decapod shrimp Non-CRI
Other
Crustacean Total
Decapods
Pleocyemata
Non-CRI
Megalops
Pleocyemata
Non-CRI
Zoea
Decapods Total
Ostracods
Ostracoda Non-CRI
Other
Ostracods Total
Polychaetes
Polyehaeta Non-CRI
Other
Polychaete Total
Arthropods
Copepoda Non-CRI
Other
Arthropod Total
Chaetognatha
Chaetognatha Non-CRI
Other
Chaetognatha Total
Total Combined
Sample I 00:00
6 6
87 87
244
244
342
Sample 2 06:00
10 10
149 149
380 380
11
Sample 3 12:00 1 18 19 1 7 8 182 182
533 533
753
Sample 4 18:00 1 1 35 37 2 2 187 187
705 705
936
loia!
2 1 69 72
3 7 10
605 605
1,862 1,862
19 19 2576
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ED 002061 00130976-00230
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Kurtis Schlicht, Bill Stephens, Emily Lantz
Date:
17 August 2015
Subject:
Quarter 2 (April-june) 2015 Entrainment Sampling Resu lts
Environmental Resources Management
CityCentre Four 840 West Sam Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, development, and production facilities located in and discharging to federal waters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastewater and storm water in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith conditions that the permittee agrees to a variety of effluent limitations, monitoring, reporting, and cooling water intake structure (CWIS) requirements.
Samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t sampling requirements for Quarter 2 2015 (Q2 2015). A description of the sampling procedures and analytical results of the Q2 2015 event are presented in the following paragraphs
Procedure
ERM staff travelled to Lucius under Anadarko supervision on June 01, 2015. Sampling began at 00:00 on the m orning of June 02, 2015. Samples were collected every six hours (06:00,12:00, 18:00) until four 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. Samples remained in the possession of the sample team during the transport to shore.
Once onshore, entrainm ent samples were shipped within 24 hours to Ecological Associates, Inc. (EAI), with chain-of-custody documentation included in the shipment. Samples w ere processed by EAI during a 45-60 day period.
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level.
Texas Registered Engineering Firm F-2393 Texas Board of Professional Geoscientists Firm 50036
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00231
Memorandum
Page 2
Sampling Results
A total of 120 "Target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 2 fish larvae and 118 fish eggs. Table 1 below indicates the types, numbers, and lifestages of the fish w ithin the June 02, 2015 sample.
Table 1. Laboratory Analysis of Ichthyoplankton Samples Collected During Event 1 on June 02, 2015 at the Anadarko Lucius Truss Spar Platform: Target Organisms.
i axa
CRi/Xon-
i ifeslage Sample 1 Sample 2 Sample .1 Sample 4
( R1
Invertebrates
i.'oNet lion lime 00:00
06:00
12:00
18:00
Fish
Carangidae
Post Yolk- 1
0
0
0
Sac Larvae
Unidentified fish -
Post Yolk- 1
0
0
0
damaged
Sac Larvae
Fish total
2
0
0
0
Fish Eggs
Unidentified eggs - No embryos
Egg
0
115
3
0
Fish Eggs Total
0
115
3
0
Total Combined
2
115
3
0
*CR1 = Commercially or Recreationally Im portant Decapod Crustaceans. None present in
samples.
total
1 1 2 118 118 120
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G :\2015\0243120\22707H(memo).docx
ED 002061 00130976-00232
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Kurtis Schlicht, Emily Lantz
Date: Subject:
15 December 2015
Lucius Truss Spar - Quarter 3 (July-September) 2015 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, developm ent, and produc tion facilities located in and discharging to federal wa ters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastew ater and storm w ater in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith condi tions that the permittee agrees to a variety of effluen t limitations, monitoring, reporting, and cooling w ater intake structure (CWIS) requirements.
Entrainmen t samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t monitoring requirements for Q uarter 3 2015 (Q3 2015). A description of the sampling procedures and analytical results of the Q3 2015 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM staff travelled to Lucius under Anadarko supervision on September 21, 2015. Sampling began at 18:00 on the evening of September 21, 2015. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. Sampling began at 18:00 in order to accommodate Lucius personnel request to have the entrainm ent sampling system (ESS) disassembled the day prior to crew change. Samples rem ained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped w ithin 24 hours to Ecological Associates, Inc. (EAI), w ith chain-of-custody documentation included in the shipment. Samples were processed by EAI during a 45-60 day period. The final results, dated December 11, 2015, were received via email on December 11, 2015.
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ED 002061 00130976-00233
Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. During this quarter, EAI composited the four samples into two samples: one composite to represent the samples taken during the daytime (12:00 and 18:00, sunset occurred around 19:30); and one composite to represent the samples taken during the nighttim e (00:00 and 06:00, sunrise occurred around 07:15). In Q1 and Q2 the four samples collected each quarter were individually processed in order to verify the amount of ma terial (number of organisms) present in the samples. After these two quarters were utilized as a baseline, we have assumed that the samples will contain relatively low numbers and organism density. In Q3 and future quarterly sampling events, the samples will be composited into two samples (as described above), which is sufficient to show diel migration of organisms for analysis.
Sampling Results
A total of 28 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 7 crustaceans; 3 fish larvae; and 18 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 28 organisms present in the September 21, 2015 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
Table 1. Laboratory Analysis of Ichthyoplankton Samples Collected During Event 3 on September 21, 2015 at the Anadarko Lucius Truss Spar Platform.
Taxa
( RF/Non-
I.lestage
Nighttime Sample Daytime Sample
(R i
(00:00 and 00:00) (12:00 and 18:00}
Invertebrates
Crustaceans
Penaeidae
CRI
Post Larvae 0
6
Sicyonia sp.
CRI
Mysis
0
1
Crustacean Total
0
7
Fish
Diplogrammus pauciradiatus
Post Yolk- 0
1
Sac Larvae
Unidentified fish -
Post Yolk- 2
0
damaged
Sac Larvae
Fish Total
2
1
Fish Eggs
Unidentified eggs - No embryos
Egg
17
1
Fish!3ggs Total
17
1
!OI \\
19
9
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
total
6 1 7 1 2 3 18 18 28
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Memorandum
Page 3
Table 2. Total Length (mm) of Ichthyoplankton Specimens Collected during Event 3 on September 21, 2015 at the Anadarko Lucius Truss Spar Platform.
Sample
Taxa
Life Stage
Nighttime Sample (00:00 and 06:00)
Daytime Sample (12:00 and 18:00)
Unidentified fishdamaged Unidentified fishdamaged Diplogrammus pauciradiatus
* Specimen damaged, not measured.
Post Yolk-Sac Larvae Post Yolk-Sac Larvae Post Yolk-Sac Larvae
Specimen Number 1
1
1
Total Length (mm) N /A *
N /A *
N /A *
Table 3. Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 3 on September 21, 2015 at the Anadarko Lucius Truss Spar Platform.
Taxa
( RL/Nnn( Ri
I.ifesLige
Nighttime Sample Daytime Sample (00:00 and 06:00) (12:00 and 18:00}
invertebrates
Noin me of filtered w.iler (m :)
50.0
50.0
Crustaceans
Penaeidae
CRI
Post Larvae 0
0.120
Sicyonia sp.
CRT
Mysis
0
0.020
Crustacean Total
0
0.140
Fish
Diplogrammus pauciradiatus
Post Yolk- 0 Sac Larvae
0.020
Unidentified fish -
Post Yolk- 0.040
0
damaged
Sac Larvae
Fish Total
0.040
0.020
Fish Eggs
Unidentified eggs - No embryos
Egg
0.340
0.020
Fish Eggs Total
0.340
0.020
T O ! Al.
0.380
0.180
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
1 criai
i 00.0 0.060 0.010 0.070 0.010 0.020 0.030 0.180 0.180 0.28t}
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v. EPA 18cv3472 NDCA
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G :\2015\0243120\23269FE(memo).docx
ED 002061 00130976-00235
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Rurtis Schlicht, Emily Lantz
Date: Subject:
19 January 2016
Lucius Truss Spar - Quarter 4 (October-December) 2015 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, developm ent, and produc tion facilities located in and discharging to federal wa ters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastew ater and storm w ater in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith condi tions that the permittee agrees to a variety of effluen t limitations, monitoring, reporting, and cooling w ater intake structure (CWIS) requirements.
Entrainmen t samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t monitoring requirements for Q uarter 4 2015 (Q4 2015). A description of the sampling procedures and analytical results of the Q4 2015 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM staff travelled to Lucius under Anadarko supervision on November 30, 2015. Sampling began at 18:00 on the evening of November 30, 2015, and ended at 12:00 on December 01, 2015. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3 entrainment sample volumes were collected representing a 24-hour sample period. Sampling began at 18:00 in order to accommodate Lucius personnel request to have the entrainm ent sampling system (ESS) disassembled the day prior to crew change. Samples remained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped w ithin 24 hours to Ecological Associates, Inc. (EAI), with chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated December 17, 2015, were received via email on December 17, 2015.
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Sierra Club v. EPA 18cv3472 NDCA
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ED 002061 00130976-00236
Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. Based on client feedback received from the third quarter 2015 monitoring results, EAI processed the four samples individually (similar to Q1 and Q2 samples), versus the Q3 2015 methodology that composited the four samples to results in two diel (daytime versus nighttime) samples. In Q4 and future quarterly sampling events, the samples will be processed individually rather than composited.
Sampling Results
A total of 27 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 16 crustaceans; 1 fish larvae; and 10 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 27 organisms present in the November 30- December 01, 2015 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 - Laboratory Analysis of Ichthyoplankton Samples Collected During Event 4 on November 30- December 01, 2015 at the Anadarko Lucius Truss Spar Platform.
taxa
CRiyXon-
I l lestage
Sampie t Sample 2 Sample 3
C RI
Invertebrates
Crustaceans
( oiicciiou Time 18:00
00:00
06:00
Euphausiacea
Non-CRI
Adult
Lophogastrida
Non-CRI
Adult
Pinnotheres spp. Non-CRI
Megalops
Rimapenaeus spp. CRI
Post Larvae
Sergestidae
Non-CRI
Adult
Xiphopenaeus
CRI
kroyeri
Crustacean Total
Fish
Post Larvae
Exocoetidae Fish Total Fish Eggs
Juvenile
Unidentified eggs
Egg
- No embryos
Fish Eggs Total
m i Ai.
io
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
Sample 4 12:00
lutai
16 10 10 27
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G :\2016 \ 0243120\ 23417H(Q4memo).docx
ED 002061 00130976-00237
Memorandum
Page 3
TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 4 on November 30- December 01, 2015 at the Anadarko Lucius Truss Spar Platform.
Sample
Taxa
Sample 1- 18:00 Sample 2- 00:00
Sample 3- 06:00
Exocoetidae
Sample 4-12:00
* Specimen damaged, not measured.
Life Stage
Specimen
Number
No Ichthyoplankton Present
No Ichthy oplankton Present
Juvenile
1
No Ichthyoplankton Present
Total Length (mm)
N/A*
TABLE 3 - Densities (Number per m3 of Water Filtered) of Organisms Collected during Event 4 on November 30- December 01, 2015 at the Anadarko Lucius Truss Spar Platform.
taxa
t Kr/Non-
I.ifestage
Sample 1 Sample 2 Sample 3
( Ki
Invertebrates
Collection Time 18:00
00:00
06:00
Volume of water fillom i (m :)
25
25
25
Crustaceans
Euphausiacea
Non-CRI
Adult
0
0.08
0
Lophogastrida
Non-CRI
Adult
0
0.04
0
Pinnotheres spp. Non-CRI
Megalops 0.12
0
0
Rimapenaeus spp. CRI
Post Larvae 0
0
0.12
Sergestidae
Non-CRI
Adult
0
0.16
0.04
Xiphopenaeus
CRI
Post Larvae 0
0
0.08
kroyeri
Crustacean Total
0.12
0.28
0.24
Fish
Exocoetidae
Juvenile
0
0
0.04
Fish Total
0
0
0.04
Fish Eggs
Unidentified eggs - No embryos
Egg
0.04
0.12
0
Fish Eggs Total
0.04
0.12
0
TOI'AI.
0.16
0.40
0.28
*CR1 = Commercially or Recreationally Im portant Decapod Crustaceans.
Sample 4
i 2:00 25
0 0 0 0 0 0
0
0 0
0.24
0.24 0.24
1ota!
100
0.02 0.01 0.03 0.03 0.05 0.02
0.16
0.01 0.01
0.10
0.10 0.27
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G :\2016 \ 0243120\ 23417H(Q4memo).docx
ED 002061 00130976-00238
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Bill Stephens
Date: Subject:
16 May 2016
Lucius Tr uss Spar - Quarter 1 (January-March) 2016 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, developm ent, and produc tion facilities located in and discharging to federal wa ters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastew ater and storm w ater in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith condi tions that the permittee agrees to a variety of effluen t limitations, monitoring, reporting, and cooling w ater intake structure (CWIS) requirements.
Entrainmen t samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t monitoring requirements for Q uarter 1 2016 (Q1 2016). A description of the sampling procedures and analytical results of the Q1 2016 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM staff travelled to Lucius under Anadarko supervision on February 15, 2016. Sampling began at 18:00 on the evening of February 15, 2016, and ended at 12:00 on February 16, 2016. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3 entrainment sample volumes were collected representing a 24-hour sample period. Sampling began at 18:00 in order to accommodate Lucius personnel request to have the entrainm ent sampling system (ESS) disassembled the day prior to crew change. Samples remained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped w ithin 24 hours to Ecological Associates, Inc. (EAI), with chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated March 7, 2016, were received via email on March 7, 2016.
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ED 002061 00130976-00239
Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. The four samples were processed individually (not composited).
Sampling Results
A total of 73 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 67 crustaceans; 4 fish larvae; and 2 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 73 organisms present in the Febr uary 15February 16, 2016 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 -
Laboratory Analysis of Ichthyoplankton Samples Collected During Event 5 on February 15-February 16, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
LifeStage
Lucius-021516- Lucius-021616- Lucius-021616- Lucius021616-
Sample 1
Sample 2
Sample 3
Samplel Total
Collection Time
18:00
0:00
6:00
12:00
CrusUHiMiis
Decapoda
Non-CKI Post Larvae
7
2
2
11
Euphausiacea
Non-CRI Post Larvae
13
8
19
9
49
H epatus epheliticus
Non-CRI Megalops
1
1
Hexapanope us
Non-CRI Megalops
1
1
2
L itopenaeus sp.
CRI
Post Larvae
1
1
P o rtu n u s sp.
Non-CRI
Megalops
1
1
Solenocera sp.
Non-CRI
Mysis
1
1
Solenocera sp.
Non-CRI Post Larvae
1
1
Crustacean Total fish
Unidentified fish
23
10
23
11
67
PosL Yolk-Sac
1
1
Larvae
2
4
Fish Total
1
1
2
4
_____ FishEggs______________________________________________________________________________________________________
Unidentified eggs -
No embryos
Egg
1
1
2
Fish Eggs Total Total
1
1
2
24
12
23
14
73
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
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G :\ 2016 \ 0243120\ 23918Fi(Ql-2016).docx
ED 002061 00130976-00240
Memorandum
Page 3
TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 5 on February 15-16, 2016 at the Anadarko Lucius Truss Spar Platform
Sample Number Lucius-021516-Sample 1 Lucius-021616-Sample 2 Lucius-021616-Sample 3
Lucius-021616-Sample 4
Taxa Unidentified Fish Unidentified Fish
Unidentified Fish Unidentified Fish
Life Stage Post Yolk-Sac Larvae
Specimen Number
1
Post Yolk-Sac Larvae
1
No Ichthyoplankton Present
Post Yolk-Sac Larvae
1
Post Yolk-Sac Larvae
2
Total Length (mm) N /A 1 N /A 1
N /A 1 N /A 1
1Specimen damaged, not measured.
TABLE 3 -
Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 5 on February 15-16, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Life Stage
Invertebrates*
Lucius-021516- Lucius-021616- Lucius-021616- Lucius-021616-
Sample 1
Sample 2
Sample 3
Sample 4
Collection Time
18:00
0:00
6:00
12:00
Volume of W ater Filtered (m )
25.0
25.0
25.0
25.0
Crustaceans
Decapoda
Non-CRI
Post Larvae
0.28
0.08
0.08
Euphausiacea
Non-CRI
Post Larvae
0.52
0.32
0.76
0.36
Hepatus epheliticus Non-CRI
Megalops
0.04
Hexapanopeus angustifrons
Non-CRI
Megalops
0.04
0.04
Litopenaeus sp.
CRI
Post Larvae
0.04
Portunus sp.
Non-CRI
Megalops
0.04
Solenocera sp.
Non-CRI
Mysis
0.04
Solenocera sp.
Non-CRI
Post Larvae
0.04
Crustacean Total
0.92
0.4
0.92
0.44
Hsh
Unidentified fish
Post Yolk-Sat'
0.04
0.04
0.08
Fish Total
0.04
0.04
0.08
Fish Eggs
Unidentified eggs - No
Egg
0.04
0.04
Fish Eggs Total
0.04
0.04
Total
0.96
0.48
0.92
0.56
Total
100.0
0.11 0.49 0.01 0.02 0.01 0.01 0.01 0.01 0.67
0.04 0.04
0.02 0.02 0.73
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
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G :\ 2016 \ 0243120\ 23918Fi(Ql-2016).docx
ED 002061 00130976-00241
Memorandum
To:
Ms. Sofia Lamon, Ms. Ellen Thomson
Company:
Anadarko
From:
Bill Stephens
Date:
22 August 2016
Subject:
Lucius Truss Spar - Quarter 2 (April-June) 2016 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, developm ent, and produc tion facilities located in and discharging to federal wa ters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastew ater and storm w ater in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith condi tions that the permittee agrees to a variety of effluen t limitations, monitoring, reporting, and cooling w ater intake structure (CWIS) requirements.
Entrainmen t samples were collected from the Lucius Truss Spar (Lucius) in accordance w ith the General Permit quarterly entrainmen t monitoring requirements for Q uarter 2 2016 (Q2 2016). A description of the sampling procedures and analytical results of the Q2 2016 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM staff travelled to Lucius under Anadarko supervision on June 13-14, 2016. Sampling began at 18:00 on the evening of June 13, 2016, and ended at 12:00 on June 14, 2016. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. Sampling began at 18:00 to accommodate a Lucius personnel request to have the entrainm ent sampling system (ESS) disassembled the day prior to crew change. Samples remained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped w ithin 24 hours to Ecological Associates, Inc. (EAI), w ith chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated July 15, 2016, were received via email on July 15, 2016.
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Tiers 8&9
ED 002061 00130976-00242
Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. The four samples were processed individually (not composited).
Sampling Results
A total of 11 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 6 crustaceans; 0 fish larvae; and 5 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 11 organisms present in June 13- June 14, 2016 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 - Laboratory Analysis of Ichthyoplankton Samples Collected During Event 6 on June 13 - June 14, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
LifeStage
Lucius-061316Sample 1
Collection Time
18:00
Crustaceans
Decapoda
Non-CRI
Juvenile
Euphausiacea
Non-CRI
Juvenile
Euphausiacea
Non-CRI
Other
1
Crustacean Total
1
Fish
Fish Total
\o FhihuipLmkloi!
I l-h i
Unidentified eggs No embryos
Egg
1
Fish Eggs Total
1
Total
2
Lucius-061416Sample 2 0:00 1 1 2
2 2 4
Lucius-061416- Lucius061416-
Sample 3
Sample4
6:00
12:00
1
1
1
2
1
1
1
1
1
2
2
Total
2 2 2 6
5 5 11
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
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G :\ 2016 \ 0243120\ 246CtoFi(Q2-2016).docx
ED 002061 00130976-00243
Memorandum
Page 3
TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 6 on June 13-14, 2016 at the Anadarko Lucius Truss Spar Platform
Sample Number
Lucius-061316-Sample 1 Lucius-061416-Sample 2 Lucius-061416-Sample 3 Lucius-061416-Sample 4
Taxa
Life Stage
Specimen Number
No Ichthyoplankton Present
No Ichthyoplankton Present
No Ichthyoplankton Present
No Ichthyoplankton Present
Total Length (mm)
1Specimen damaged, not measured.
TABLE 3 -
Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 6 on June 13-14, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
Life Stage
Lucius-061316- Lucius-061416- Lucius-061416- Lucius-061416-
Sample 1
Sample 2
Sample 3
Sample 4
Collection Time
18:00
0:00
6:00
12:00
Volume of Water Filtered (nP)
25.0
25.0
25.0
25.0
Cmslaceans Decapoda
Non-CRI
Juvenile
0.04
0.04
Euphausiacea
Non-CRI
Juvenile
0.04
0.04
Euphausiacea
Non-CRI
Other
0.04
0.04
Crustacean Total
0.04
0.08
0.08
0.04
Fish
Fish Total
No Ichihvopiankton Presen!
Fish Lags Unidentified eggs
Egg
0.04
0.08
0.04
0.04
Fish Eggs Total
0.04
0.08
0.04
0.04
Total
0.08
0.16
0.12
0.08
Total
100.0
0.02 0.02 0.02 0.06
0.05 0.05 0.11
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
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G :\ 2016 \ 0243120\ 246CtoFi(Q2-2016).docx
ED 002061 00130976-00244
Memorandum
To:
Mr. John Geng and Mr. Steven McElhany
Company:
Anadarko
From:
Bill Stephens
Date: Subject:
24 February 2017
Lucius Tr uss Spar - Quarter 3 (July-September) 2016 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, development, and production facilities located in and discharging to federal waters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastewater and storm water in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith conditions that the permittee agrees to a variety of effluent limitations, monitoring, reporting, and cooling water intake structure (CWIS) requirements.
Entrainment samples were collected from the Lucius Truss Spar (Lucius) in accordance with the General Permit quarterly entrainm ent monitoring requirements for Q uarter 3 2016 (Q3 2016). A description of the sampling procedures and analytical results of the Q3 2016 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM traveled to Lucius on September 19, 2016 to conduct a sample event. Sampling began at 18:00 hours on September 19, 2016 and after 15 minutes of sample run time, the sampling equipment exhibited a system failure and the sampling event was unable to be completed at that time. The sampling system was subsequently repaired and ERM staff travelled to Lucius on December 28, 2016 to conduct a make-up sample event for the previously uncompleted event. Sampling began at 18:00 hours on the evening of December 28, 2016, and ended at 12:00 hours on December 29, 2016. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. Sampling began at 18:00 to accommodate a Lucius personnel request to have the entrainm ent sampling system (ESS) disassembled the day prior to crew change. Samples rem ained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped within 24 hours to Ecological Associates, Inc. (EAI), w ith chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated February 2, 2017, were received via email on February 2, 2017.
Texas Registered Engineering Firm F-2393 Texas Board of Professional Geoscientists Firm 50036
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
ED 002061 00130976-00245
Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. The four samples were processed individually (not composited).
Sampling Results
A total of 6 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 5 crustaceans; 1 fish larvae; and 0 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 6 organisms present in December 28- December 29, 2016 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 -
Laboratory Analysis of Ichthyoplankton Samples Collected During Event 7 on December 28 - December 29, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
Life Stage
Lucius-Q3 122816 Sample 1
Lucius-Q3
Lucius-Q3
122916 Sample 2 122916 Sample 3
Lucius-Q3 122916 Sample 4
Total
Collection Time
18:00
0:00
6:00
12:00
Crii stai eans
Caridea
Non-CRI
Other
2
2
Decapoda
Non-CRI
Other
2
1
3
Crustacean Total Hsh
2
2
1
5
Unidentified fish-
Post Yolk-
1
1
damaged
Sac Larvat'
Fish Total
1
1
Fish Eggs
Fish Eggs Total
No eggs present
Total
3
2
1
6
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
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T :\D M \T EM P\PN 0243120\25277H(Q3-2016).docx
ED 002061 00130976-00246
Memorandum
Page 3
TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 7 on December 28-29, 2016 at the Anadarko Lucius Truss Spar Platform
Sample Number
Taxa
Life Stage
L ucius-Q 3122816-Sample 1 Unidentified fish-damaged Post Yolk-Sac Larvae
Specimen Number
1
L ucius-Q 3122916-Sample 2
No Ichthyoplankton Present
L ucius-Q 3122916-Sample 3
No Ichthyoplankton Present
Lucius-Q3122916-Sample 4
No Ichthyoplankton Present
1Specimen damaged, not measured.
Total Length (mm)
NA
TABLE 3 -
Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 7 on December 28-29, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRl/NonCRI
Life Stage
Invertebrates
Collection Time
Lucius-Q3 122816-Sample 1
18:00
Lucius-Q3 122916-Sample 2
0:00
Lucius-Q3 122916-Simple 3
6:00
Lucius-Q3 122916-Sample 4
12:00
Total
Volume of Water Filtered (m^)
25.0
25.0
25.0
25.0
100.0
( Yustacca ns
Caridea
Non-CRI
Other
0.08
0.02
Decapoda
Non-CRI
Other
0.08
0.04
0.03
Crustacean Total
0.08
0.08
0.04
0.05
Fish
Unidentified fish-
Post Yolk -
0.04
0.01
damaged
))))))))))))))))))))))))))))))))))))))))))))) Sac Larvae
Fish Total
0.04
Fish Eggs
Fish Eggs Total
No eggs present
Total
0.12
0.08
0.04
o.oi" 0.06
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
Texas Registered Engineering Firm F-2393 Texas Board of Professional Geoscientists Firm 50036
Sierra Club v. EPA 18cv3472 NDCA
Tiers 8&9
T :\D M \T EM P\PN 0243120\25277H(Q3-2016).docx
ED 002061 00130976-00247
Memorandum
To:
Mr. John Geng and Mr. Steven McElhany
Company:
Anadarko
From:
Bill Stephens
Date: Subject:
24 February 2017
Lucius Truss Spar - Quarter 4 (October-December) 2016 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, development, and production facilities located in and discharging to federal waters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastewater and storm water in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith conditions that the permittee agrees to a variety of effluent limitations, monitoring, reporting, and cooling water intake structure (CWIS) requirements.
Entrainment samples were collected from the Lucius Truss Spar (Lucius) in accordance with the General Permit quarterly entrainm ent monitoring requirements for Q uarter 4 2016 (Q4 2016). A description of the sampling procedures and analytical results of the Q4 2016 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM traveled to Lucius on December 28, 2016 to conduct a sample event. Sampling began at 12:00 hours on the evening of December 30, 2016, and ended at 06:00 hours on December 31, 2016. Samples were collected every following six hours (18:00, 00:00, 06:00) until four, 25 m3 entrainment sample volumes were collected representing a 24-hour sample period. Sampling began at 12:00 to allow a 24-hour period between the 3rd quarter make-up sample event and the regularly-scheduled 4th quarter sample event. The entrainm ent sampling system (ESS) was disassembled prior to crew change. Samples rem ained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped within 24 hours to Ecological Associates, Inc. (EAI), w ith chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated February 2, 2017, were received via email on February 2, 2017.
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Memorandum
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In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. The four samples were processed individually (not composited).
Sampling Results
A total of 5 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 2 crustaceans; 2 fish larvae; and 1 fish egg. Table 1 describes the types, numbers, and lifestages of the organisms of the 5 organisms present in December 30- December, 31, 2016 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 -
Laboratory Analysis of Ichthyoplankton Samples Collected During Event 8 on December 30 - December 31, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRl/Non-CRI Invertebrates*
Life Stage
Lucius-Q4 123016 Sample 1
Lucius-Q4 123016 Sample 2
Lucius-Q4 123116 Sample 3
Lucius-Q4
123116 Sample 4 Total
( ruslat cans Euphausiacea Crustac ean Total
fish Clupidae
Syngnathidae Fish Total
Fish Eggs Unidentified eggs Fish Eggs Total
Collection Time Non-CRI Post Larvae'
Posi YolkSac Larvae Post YolkSac La vat'
Egg
12:00
18:00
1 1 1
00:00
06:00
2
2
2
2
1
1
1
1
2
1
Total
2 *CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
3
5
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TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 8 on December 30-31, 2016 at the Anadarko Lucius Truss Spar Platform
Sample Num ber L ucius-Q 4123016-Sample 1 L ucius-Q 4123016-Sample 2 L ucius-Q 4123116-Sample 3 L ucius-Q 4123116- Sample 4
Taxa Clupidae Syngnatliidae
Life Stage
Specimen Number
No Ichthyoplankton Present
Total Length (mm)
Post Yolk-Sac Larvae
1
3.0
No Ichthyoplankton Present
Post Yolk-Sac Larvae
1
3.0
TABLE 3 -
Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 8 on December 30-31, 2016 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
Life Stage
Lucius-Q4 123016 Sample 1
Lucius-Q4
Lucius-Q4
123016 Sample 2 123116 Sample 3
Collection Time Volume of Water Filtered (m3)
12:00 25.0
18:00 25.0
00:00 25.0
Lucius-Q4 123116 Sample 4
Total
06:00 25.0
100.0
Crustaceans
Euphausiacea
Non-CRl Post Larvae
Crustacean Total
E:ish
Clupidae
Post Yolk-
0.04
Sac Larvae
Post Yolk-
Syngnathidae
Sac Lavae
Fish Total
0.04
f ish iggs
Unidentified
eggs
Egg
0.04
Fish Eggs Total
0.04
Total
0.08 *CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
0.08
0.02
0.08
0.02
0.01
0.04
0.01
0.04
0.02
0.01
0.01
0.12
0.05
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Memorandum
To:
Mr. John Geng and Mr. Steven McElhany
Company:
Anadarko
From:
Bill Stephens
Date: Subject:
5 May 2017
Lucius Tr uss Spar - Quarter 1 (January-March) 2017 Entrainment Monitoring Results
Environmental Resources Management
CityCentre Four 840 West Sam. Houston Parkway North, Suite 600 Houston, Texas 77024-3920
T: 281-600-1000 F: 281-520-4625
The Environmental Protection Agency (EPA) regulates discharges from exploration, development, and production facilities located in and discharging to federal waters of the Gulf of Mexico offshore of Louisiana and Texas under National Pollutant Discharge Elimination System (NPDES) General Permit num ber GMG 290000 (General Permit). The General Permit provides authorization to discharge wastewater and storm water in the western outer continental shelf (OCS) regions of the Gulf of Mexico w ith conditions that the permittee agrees to a variety of effluent limitations, monitoring, reporting, and cooling water intake structure (CWIS) requirements.
Entrainment samples were collected from the Lucius Truss Spar (Lucius) in accordance with the General Permit quarterly entrainm ent monitoring requirements for Q uarter 1 2017 (Q1 2017). A description of the sampling procedures and analytical results of the Q1 2017 monitoring event are presented in the following paragraphs.
Sampling Procedures
ERM traveled to Lucius on M arch 27, 2017 to conduct the 1st Q uarter sample event. The contractor Dolphin supported the assembly of the entrainm ent sampling system (ESS). Sampling began at 18:00 hours on the evening of March 27, 2017, and was completed following the end of the 12:00 hour event on March 28, 2017. Samples were collected every following six hours (00:00, 06:00,12:00) until four, 25 m3entrainm ent sample volumes were collected representing a 24-hour sample period. The entrainm ent sampling system (ESS) was disassembled prior to crew change after the last event. Samples rem ained in the possession of the ERM sample team during the transport to shore, under the chain of custody protocol.
Once onshore, the entrainm ent samples were shipped within 24 hours to Ecological Associates, Inc. (EAI), w ith chain-of-custody documentation included in the shipment. Samples were processed by EAI during a less than 30 day period. The final results, dated April 10, 2017, were received via email on April 10, 2017.
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Memorandum
Page 2
In the laboratory, EAI technicians separated debris or material from aquatic organisms and sorted the organisms by life-stage to the lowest possible taxonomic level. The four samples were processed individually (not composited).
Sampling Results
A total of 5 "target" (per EAI nomenclature) fish or shellfish organisms were present in the 100m3 of water sampled: 3 crustaceans; 2 fish larvae; and 0 fish eggs. Table 1 describes the types, numbers, and lifestages of the organisms of the 5 organisms present in March 27- March, 28, 2017 sample. Table 2 describes the lengths of captured fish organisms. Table 3 describes the density of organisms within the samples.
TABLE 1 -
Laboratory Analysis of Ichthyoplankton Samples Collected During Event 9 on March 27 - March 28, 2017 at the Anadarko Lucius Truss Spar Platform
Taxa
('ni stai eans Euphausiacea Euphausiacea Crustacean Total
i ish Myctophidae
Blermiidae Fish Total
Fish Eggs No fish eggs collected Fish Eggs Total
CRl/Non-CRI Invertebrates*
Life Stage
Lucius-Ql 032717 Sample
1
Collection Time
18:00
Non-CRI Metanauplius
2
Non-CRI
Adult
2
Post Yolk-Sac Larvae Yolk-Sac Larvae
Lucius-Ql 032817 Sample 2
00:00
1 1
Lucius-Ql 032817 Sample 3
06:00
1 1
Lucius-Ql 032817 Sample 4
Total
12:00
2 1 3
1
1
1
1
2
Total
2
1
1
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
1
5
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Memorandum
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TABLE 2 - Total Length (mm) of Ichthyoplankton Specimens Collected during Event 9 on March 27-28, 2017 at the Anadarko Lucius Truss Spar Platform
Sample Number Lucius-Q l 032717-Sample 1
Taxa
Life Stage
Specimen Number
No Ichthyoplankton Present
Total Length (mm)
Lucius-Q l 032817-Sample 2 Lucius-Ql 032817-Sample 3
Mycotophidae
Post Yolk-Sac Larvae
1
No Ichthyoplankton Present
N /A 1
Lucius-Ql 032817- Sample 4
Blenniidae
Yolk-Sac Larvae
1
2.5
^Specimen damaged, not measured
TABLE 3 -
Densities (Number per m3 of Water Filtered) of Organisms Collected During Event 9 on March 27-28, 2017 at the Anadarko Lucius Truss Spar Platform
Taxa
CRI/Non-CRI Invertebrates*
Life Stage
Lucius-Ql 032717 Sample
1
Collection Time Volume of Water Filtered (m3)
18:00 25.0
Lucius-Ql
Lucius-Ql
032817 Sample 2 032817 Sample 3
00:00 25.0
06:00 25.0
Lucius-Ql 032817 Sample 4
Total
12:00 25.0
100.0
Crustaceans
Euphausiacea
Non-CRI Metanauplius
0.08
Euphausiacea
Non-CRI
Adult
0.04
Crustacean Total
0.08
0.04
Hsh
Myctophidae
Post Yolk-Sac
0.04
Larvae
Blemiidae
Yolk-Sac La vat'
Fish Total
0.04
0.02 0.01 0.03
0.01
0.04
0.01
0.04
0.02
No Fish Eggs Identified Fish Eggs Total
Total
0.08
0.04
0.04
*CRI = Commercially or Recreationally Im portant Decapod Crustaceans.
0.04
0.05
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APPENDIX F COMMENT NO. 37
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Meeting the Requirements of 40 CFR.125.137 For Information on Seasonal Variation of Entrainment
Relevant Text from 40CFR.125.137
"After that time[24 months of bimonthly monitoring], the Director may approve a request for less frequent sampling in the remaining years of the permit term and when the permit is reissued, if supporting data show that less frequent monitoring would still allow for the detection of any seasonal variations in the species and numbers of individuals that are impinged or entrained."
Proposed alternative to quarterly monitoring of a small number of regulated intakes
Approach
Allow operators of regulated intakes to submit an initial report on seasonal densities of eggs and larvae from SEAMAP data base and follow up with updated reports periodically as data are added
Advantages
Proposed approach is more effective at addressing regulatory requirement than existing method Data are collected and maintained over the long term Long term consistency of collection methods ensures comparability over time Data are suitable for detecting evolution of entrainment risk over time SEAMAP larval data could be selected for most common species in each region Approach is cost effective and appropriate to the low level of risk demonstrated in the 24-month
Entrainment Monitoring Study and in a peer-reviewed study of entrainment risk from much larger water volumes in depths of 20-60 m where egg and larval densities are much higher.*
` G a ll a w a y , B .J., W . J . G a z e y , J .G . C o le , a n d R .G . F e c h h e l m ( 2 0 0 7 ) ; " E s t im a t io n o f P o t e n t ia l I m p a c t s f r o m O f f s h o r e L i q u e f ie d N a t u r a l G a s T e r m i n a l s O n R e d S n a p p e r a n d R e d D r u m F is h e rie s o f t h e G u lf o f M e x ic o : A n A lt e r n a t iv e A p p r o a c h " T r a n s a c t io n s o f t h e A m e r ic a n F is h e rie s S o c ie t y (2 0 0 7 ) 1 3 6 :6 5 5 - 6 7 7
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Gulf of Mexico Fishery Zones
Figure E l. Zones for fishery dat raid water-use assessment.
The Source Water Biological Baseline Characterization Study divided the GOM into 15 fishery zones organized by depth and longitude
Each zone can be considered a homogenous unit for fishery analysis
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L i r a i Density (#An3)
Comparison of SEAMAP, EMS, and On-Platform Densities
Western Region
Central Region
O - 20 m 20 - 60 m 60 - 200 m 200 -1000 m := 1000 m EMS 200-1000 m EMS> 1000 m
On-platform
On-platform (LT)
E gg D@ nty (#An3)
*On-Platform (LT) means the values are "less than" the y-axis value. As an example, a 100 cubic meter sample in which there were no eggs found was plotted as having an egg density of less than 0.01 eggs/cubic meter.
E g g _ a n d _ la rv a e _ m u litp lo ts .jn b
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APPENDIX G COMMENT NO. 39
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Issue
It is acknowledged that surfactants should not be used for purposes which "could circumvent the intent of the permit's produced water sheen monitoring requirem ents'll).
Detergent vs Surfactant
It is important to differentiate between surfactants (detergents, dispersants) in the context of reducing oil content in a discharge stream vs the use of surface active substances in the formulation of chemicals to impart specific properties to the formulation. Detergents, dispersants, and soaps are surfactants or surfactant mixtures, whose solutions have cleaning properties (2). For example detergents alter interfacial properties so as to promote removal of a phase from solid surfaces (2). However, not all surfactants are detergents although their names are often used interchangeably. On the other hand, the cleaning ability of some surfactants is also required at some stages of the Petroleum Industry.
Use of Surfactants in the Oil Industry
Surfactants are used at all stages in the petroleum industry; from oil-well drilling and production, reservoir injection to surface plant processing, to pipeline and marine transportation of petroleum emulsions (2).
Surfactants are required in chemical formulations due to their unique property to break down the interface between water and oil and their ability to influence the properties of surfaces and interfaces (2). They are also defined as compounds that contain one part that has an affinity for polar media and the other has affinity for nonpolar media (3). They behave in this manner because they contain both a hydrophilic group, such as an acid anion (-C02- or S03-), and a hydrophobic group such as an alkyl chain.
These qualities make surfactants invaluable to the petroleum industry. Their relevance in various interfacial phenomena, such as adsorbed surfactant films, self-assembly, contact angle, wetting, foams and emulsions with regard to drilling, enhanced oil recovery, antifoaming, corrosion inhibition, oil spill clean-up, oil/water separation, and fluidization of highly viscous materials has been well documented has been well documented (3).
Use of Surfactants in Drilling Processes
The main applications of surfactants in oil based drilling fluids are emulsification and oil wetting of cuttings to ensure good suspension and transports. Emulsifiers have by definition surface active (surfactant) properties and they are an essential part of oil and synthetic based drilling fluids. The use of surfactants is at the core of invert emulsion technology from conventional mineral oil invert emulsion fluid system to high-performance organophilic clay-free synthetic based invert emulsion fluid system.
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The function of the emulsifier is to lower the interfacial tension between oil and water resulting in the formation of a stable emulsion. This is achieved by having a mixture of oil and water in which one of the phases, the dispersed phase, occurs as droplets dispersed within the other (3). The emulsifier surrounds droplets of water as if encapsulating the water molecules, with the fatty acid component of the chemical dissolving in the oil phase of the mud. Emulsifiers used in drilling muds have been classified as primary and secondary; common primary emulsifiers include fatty acids, rosin acids and their derivatives, with secondary emulsifiers including amines, amides, sulphonic acids alcohols and related copolymers. The secondary emulsifiers improve the stability of the emulsion further from the primary or main emulsifier and aids.
Water based drilling fluids use a variety of surfactants (4) for specific applications such as lubrication and corrosion inhibition. Drilling lubricants often contain surfactants which are used to reduce friction during the drilling process and increase rate of penetration which is imperative for drilling long horizontal well depths. Without lubricants, some reservoir targets may not be reachable due to torque and drag limitations which lead to stuck pipe and possible well abandonment. These are especially important in applications using water or brine base fluids where there is minimal lubricity in comparison to oil based muds.
One common issue with water based drilling fluids when adding viscosifiers is the production of foam. The surfactants in defoamers (also known as anti-foamers) help reduce the interfacial tensions between fluid and air allowing the reduction in formed bubbles.
Other uses in water based drilling fluids include, inhibition of shale-swelling to prevent wellbore instabilities, prevention of cuttings sticking to the drill bit, prevention of differential sticking, inhibition of flocculation of clay particles and surfactant-polymer complexes for enhanced properties in fluids for low-pressure reservoirs.
Completion fluids are fluids used after the drilling process to complete the well before production begins. These fluids commonly consist of brine as the base fluid which is naturally corrosive. Therefore, it is common to use a corrosion inhibitor. Surfactants are now widely used in corrosion inhibitors by interacting with the metal surface. This is done by forming a film on the metal surface which in turn protects the metal through an absorption mechanism. Since completion brines are commonly used in the reservoir section, there is a need to ensure the brine/crude oil don't mix. Therefore, surfactants are commonly used to prevent emulsions from lowering the surface tension of the brine and interfacial tensions as previously explained.
Other surfactants are components in wellbore clean-up / cleaner chemicals for cleaning metal and/or formation surfaces both on surface and down hole.
Reservoir permeability (productivity or injectivity) can be severely adversely affected by drilling fluid and other residues coating metal surfaces. Surfactants are utilized to efficiently clean these metal surfaces of this debris and residue and therefore help protect the reservoir from damage.
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A common down-hole usage is when displacing drilling fluids and other fluids from the well bore to clean metal surfaces downhole (e.g. production casing and tubing) and also for cleaning the marine riser at the end of the well, when the drilling and completion phase is finished. Occasionally, surfactants can be used to remove the drilling fluid filter cake from the face of the reservoir rock in order to re-establish optimal permeability pathways between the hydrocarbon reserves and the production tubing to surface.
At the surface, surfactants are used for cleaning of surface pits (tanks containing specialized fluids).
Summary
Surfactants are part of the composition of many chemicals and fluid systems used in the Gulf of Mexico. Toxicity tests in cuttings wastes containing both oil based muds and water based muds consistently meet the required limits, indicating that the presence of small concentration of these chemicals does not affect the toxicity of the discharge stream containing drilling fluids adhered to cuttings, as well as other fluids systems which may contain chemicals with surfactants in their make- up.
In summary chemicals with surfactant properties are currently used in the Gulf of Mexico and throughout the world in fluids systems which are discharged and meet regulatory requirements.
A complete ban in the discharge of surfactants would preclude the current discharge regime in the Gulf of Mexico.
References
( 1) Fact sheet and supplemental information for the proposed reissuance of the NPDES general permit or new and existing sources in the offshore subcategory of the oil and gas extraction point source category for the western portion of the outer continental shelf of the gulf of mexico (GMG290000); April 7,2017
(2) Surfactants. Fundamentals and Applications in the Petroleum Industry. L. Schramm edition 2000.
(3) Surface Chemistry in the Petroleum Industry; James R. Kanicky, Juan-Carlos Lopez-Montilla, Samir Pandey and Dinesh O. Shah Chapter 11,
(4) Optimization of Water-based Drilling Fluid Using Non-ionic and Anionic Surfactant Additives. Procedia Engineering Volume 148, 2016, Pages 1184-1190Putri Yunitaa,*, Sonny Irawana, Dina Kaniab. Procedia Engineering 148 ( 2016 ) 1 1 8 4 - 1190
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APPENDIX H COMMENT NO. 41
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Stret Code 85871 85868R 85868 S 85868T
TQM3E
TQM6B
04239T 22414 51726 TOP3E TOP6B TPP3E TPP6B TXP3E TXP6B TYP3E TYP6B TLP3E TGP3E TOP3E TPP3E TYP3E TXP3E TOP6B TPP6B TXP6B TLP3E TGP3E TOP3E TPP3E TYP3E TXP3E TOP6B TPP6B TXP6B 22414 51726 TLP3E TGP3E TOP3E TPP3E TYP3E TXP3E TOP6B TPP6B TXP6B
NeTDMR Inconsistences
Limit Set
Parameter Visual Frequency
DMR Weekly
CW
Velocity Frequency
Instantaneous
48 HR MN
CT
Coeffecient of Variation
MO AV MN 48 HR MN
MO AV MN
Visuals - Untreated
See MD DMR
Permit Monthly
Daily
DA MAX Not in permit
DA MAX Not in permit
SS
Toxicity Reporting Units
Percentage
mg/L
None Shown
(see TQP3E - mysid. Mysid species name Americamysis bahia Mysidopsis bahia Bahia) for consistency HF
Menidia species name
Menidia menidia None Shown
Menidia berryllina
(see TLP6B - Menidia for consistency
PR
Mysid species name
Americamy sis bahia
Mysidopsis bahia
(see TQP3E - mysid. Bahia) for consistency
Menidia species name Menidia menidia Menidia berryllina
Whole effluent toxicity Critical Dilution
percentage percentage None Shown
mg/L mg/L
(see TGP6B Menidia for consistency
MD
Mysid species name
Americamysis bahia
Mysidopsis bahia
(see TQP3E - mysid. Bahia) for consistency
Menidia species name Menidia menidia Menidia berryllina
(see TGP6B Menidia for consistency
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