DISHONORABLE DISCHARGES:

HOW TO SHIFT COOK INLET’S

OFFSHORE OIL & GAS OPERATIONS TO

ZERO DISCHARGE 

Lois N. Epstein, P.E.

Senior Engineer and Oil & Gas Industry Specialist

May 2006

DISHONORABLE DISCHARGES:

HOW TO SHIFT COOK INLET’S

OFFSHORE OIL & GAS OPERATIONS TO

ZERO DISCHARGE

 Lois N. Epstein, P.E.

Senior Engineer and Oil & Gas Industry Specialist

Cook Inletkeeper

May 2006

Printed on 100% post-consumer waste, processed chlorine-free paper
Dishonorable Discharges ii

Acknowledgements

The Dishonorable Discharges report on Cook Inlet offshore oil and gas platform discharges entering Cook Inlet 

was made possible with the generous support of the following: Acorn Foundation, Alaska Conservation 

Foundation, Alaska Oceans Network, Ben and Jerry’s Foundation, Deer Creek Foundation, Oak Foundation, 

and Unitarian Universalist Funding Program. Cook Inletkeeper also thanks the following general support 

funders: Bullitt Foundation, Hugh and Jane Ferguson Foundation, Harder Foundation, George H. and Jane A. 

Mifflin Memorial Fund, Patagonia, Skaggs Foundation, True North Foundation, WestWind Foundation, and 

Wolfensohn Family Foundation.

The author greatly thanks the report’s technical and editorial reviewers who immensely strengthened the 

document: chemical engineer John Louie who made valuable comments at an early stage of writing, two former 

Alaska Department of Environmental Conservation employees with background and experience in oil and gas 

industry operations, Brenda Trefon from the Kenaitze Tribe, Vicki Clark from Trustees for Alaska, and Cook 

Inletkeeper Executive Director Bob Shavelson. Thanks also to Will Schlein of Cook Inletkeeper for his 

invaluable work on Figure 1.

Comments on the study should be directed to:

Lois N. Epstein, P.E.

Cook Inletkeeper

308 G St., Suite 219

Anchorage, Alaska 99501

Phone: (907) 929-9371

Fax: (907) 929-1562

lois@inletkeeper.org

May 2006

© 2006 Cook Inletkeeper

About the author: Lois N. Epstein, P.E. has worked for Cook Inletkeeper as a Senior Engineer and an Oil & Gas 

Industry Specialist since 2001. Previously she worked for Environmental Defense (formerly Environmental 

Defense Fund) in Washington, D.C. Prior to these positions, Ms. Epstein worked for two private consulting firms 

and the U.S. EPA Region 9 Office of Water. She has presented invited testimony before the U.S. Congress on ten 

occasions, including four times representing Cook Inletkeeper. Ms. Epstein currently serves as a part-time 

consultant for the Pipeline Safety Trust, a non-profit organization dedicated to improved fuel transportation safety, 

located in Bellingham, Washington.

Ms. Epstein is a licensed Professional Engineer in the States of Alaska and Maryland and a member of the federal 

Office of Pipeline Safety’s advisory committee on hazardous liquid pipelines. She has a masters degree from 

Stanford University in Civil Engineering with a specialization in environmental engineering and science, and 

undergraduate degrees from both Amherst College (in English) and MIT (in mechanical engineering). President 

Clinton nominated her in October 2000 to the Chemical Safety and Hazard Investigation Board, however the U.S. 

Senate did not vote on her nomination before the end of the 106th Congress.

About Cook Inletkeeper: Cook Inletkeeper is a community-based nonprofit organization dedicated to 

protecting Alaska’s 47,000 square mile Cook Inlet watershed and the life it sustains, and a member of the 

national Waterkeeper Alliance. Cook Inletkeeper has offices in Homer and Anchorage. www.inletkeeper.org
Dishonorable Discharges iii

Dishonorable Discharges: How to Shift Cook Inlet’s

 Offshore Oil and Gas Operations to Zero Discharge

Table of Contents______________________________________________________________________Page

Acknowledgements...................................................................................................... ii

Executive Summary..................................................................................................... v

I. Introduction and Purpose.................................................................................... 1

II. Why Care? ...................................................................................................... 3

Background on the Cook Inlet exemption...................................................... 4

Who and what are affected by the Cook Inlet exemption................................... 5

III. Cook Inlet Offshore Drilling Production and Inje ction Data......................................... 8

IV. Cook Inlet Produced Water Discharge Data............................................................ 11

Produced water discharge locations, volume , and composition........................... 11

Toxic chemicals in produced water discharges................................................ 15

V. Cook Inlet Offshore Drilling Waste Discharges......................................................... 15

VI. Current Conditions Warrant a Shift to Zero Discharge................................................ 16

Economic and Technological Changes

Drilling economics: produced water..................................................... 17

Drilling economics: drilling wastes...................................................... 22

Disposal technology: drilling wastes.................................................... 23

New Scientific and Traditional Ecological Knowledge

Oil impacts on salmon..................................................................... 24

Contamination in Cook Inletsubsistence foods..................................... 25

Cook Inlet beluga whales................................................................. 25

VII. Conclusion ...................................................................................................... 27

Appendices

1 EPA’s Regulations for Coastal Oil and Gas Operations............................................... 29

2 Discharge Monitoring Reports for Produced Water from Cook Inlet’s 

Offshore Platforms for 2005................................................................................. 31
Dishonorable Discharges iv

Table of Contents______________________________________________________________________Page

Tables

ES-1 - Cook Inlet Discharge Comparison between 1999 and the Present...................................... vii

1 - Cook Inlet Offshore Platform Information........................................................................ 3

2 - Total Cook Inlet Oil, Natural Gas, and Produced Water Production and Seawater Injection

 from Start-up through 2005......................................................................................... 9

3 - Cook Inlet Platform and Onshore Facility Produced Water Discharge Locations, 

 Currently and in the Draft Permit................................................................................. 13

4 - Produced Water Generation Rate and Annual Average Concentrations of EPA-Permitted

 Pollutants, 2005........................................................................................................ 14

5 - Breakdown of Produced Water and Oil and Grease Generation by Cook Inlet Discharger, 2005.. 14

6 - Weighted Average Concentration of Metals in Offshore Discharges to Cook Inlet, 2005.............. 15

7 - Annual Quantity of Metals in Offshore Drilling Discharges to Cook Inlet, 2005......................... 15

8 - Active Class II Disposal Wells in the Cook Inlet Watershed.................................................. 22

9 - Active Drilling Waste Management Facilities in the Cook Inlet Watershed............................... 23

Figures

1 - Cook Inlet’s Offshore Oil and Gas Platforms and Related Onshore Facilities............................ 2

2 - Production from Offshore Cook Inlet Wells Through 2005................................................... 8

3 - Produced Water vs. Injected Seawater by Platform through 2005.......................................... 10

4 - Annual Production from Offshore Cook Inlet Wells (including Osprey platform)...................... 11

5 - Platform Discharge Locations for Produced Water as of January 2006................................... 12

6 - Two Zero Discharge Scenarios for Produced Water Based on Current

 Cook Inlet Drilling Conditions...................................................................................... 19

7 - Abundance Estimates for Cook Inlet Beluga Whales, 1994-2004............................................ 26
Dishonorable Discharges v

Dishonorable Discharges: How to Shift Cook Inlet’s

 Offshore Oil and Gas Operations to Zero Discharge

Executive Summary

The sixteen offshore oil and gas drilling platforms located in upper Cook Inlet have produced 

over 1 billion barrels (nearly 45 billion gallons) of oil, over 3 trillion cubic feet of natural gas, 

over 1.1 billion barrels (over 48 billion gallons) of contaminated “produced water,” and a

significant quantity of contaminated drilling wastes from the mid-1960s through the end of 2005. 

In contrast to other coastal locations throughout the United States, nearly all the contaminated 

produced water and drilling wastes from these offshore oil and gas operations have been – and 

continue to be – discharged into marine waters despite the 1972 federal Clean Water Act goal of

eliminating the discharge of pollutants into navigable waters. In other coastal locations around 

the country, “zero discharge” is the norm for offshore platforms. Because the U.S. 

Environmental Protection Agency (EPA) allows ongoing discharges into marine waters for the 

fifteen Cook Inlet platforms and their three related onshore facilities covered in the general 

discharge permit and in this report, Cook Inlet’s offshore oil and gas producers receive an 

outdated and unwarranted federal economic subsidy that unnecessarily pollutes the Inlet.

Not all produced water generated by Cook Inlet offshore oil and gas operations is discharged into 

the marine environment directly from the platforms. Over 99.8% of the total produced water 

from Cook Inlet’s offshore drilling operations is sent onshore to three facilities – with 96% going 

to just one facility at Trading Bay – where advanced treatment and/or zero discharge into a Class 

II disposal well would be easier than at the offshore platforms. Once onshore, the crude oil, 

natural gas, and produced water pumped up from underground are separated, and the produced 

water is discharged to Cook Inlet following minimal treatment. Produced water discharged into 

Cook Inlet from the offshore platforms in 2005 contained over 32,000 gallons of oil and grease, 

over 50,000 pounds of zinc and over 440 pounds of arsenic.

Despite that fact that oil and gas production in Cook Inlet is in decline and 1995 was the peak 

year for produced water generation, the draft Clean Water Act permit issued in March 2006 by 

EPA allows a 69% increase in the amount of produced water the offshore platforms can

discharge. The draft permit allows a maximum annual discharge in produced water of over 

100,000 gallons of oil and grease and nearly 887,000 lbs of metals such as mercury, nickel, 

copper, manganese and zinc. 

This report provides a rationale for re-examining EPA’s previous decisions – some based on 

limited information – allowing produced water and drilling wastes to be discharged into Cook 

Inlet’s biologically-productive and economically-important coastal waters. The report 

recommends that EPA use updated economic, technologic, scientific, and Traditional Ecological 

Knowledge information to evaluate if zero discharge is warranted in the renewed Clean Water 

Act permit given known and projected, adverse, economic and environmental impacts on the 

Cook Inlet region should the discharges continue. 

There are new, compelling reasons for EPA to require zero discharge in the finalClean Water 

Act permit, including changed industry economics and new waste management technologies and 
Dishonorable Discharges vi

facilities available within the Cook Inlet region. Additionally, continuing to allowdischarges

can cause cumulative harm from persistent toxic contaminants, can adversely affect the market 

for – and quality of – Cook Inlet commercial fish, and is unnecessary technologically. 

With this report, Cook Inletkeeper hopes to stimulate dialogue among government regulators, 

industry, and the public on the full costs to society of Cook Inlet oil and gas production and how 

the following, significant, recent changes support EPA making a zero discharge decision in the 

final permit for these facilities. The report includes two zero discharge scenarios which are far 

less costly than those analyzed by EPA prior to issuance of the 1999 Clean Water Act permit for 

Cook Inlet’s offshore platforms.

Economic Changes Since Permit Issuance in 1999

• The price of crude oil currently is at record levels and experts expect it to remain high. 

Oil prices in 2006 for Cook Inlet are 448% higher than they were in 1999 in constant 

dollars, and Cook Inlet oil producers covered by the Clean Water Act permit made nearly

$59 million in profits in 2005 (assuming $10 per barrel profit at $50 per barrel oil, low 

compared to 2006 profits);

• When Cook Inlet crude oil was selling for less than $27 per barrel in 2003, the Alaska 

legislature reduced the royalties paid to the state by operators of Cook Inlet platforms 

producing less than 1,200-1,500 barrels of oil per day (four Cook Inlet platforms qualify);

• The state legislature likely soon will enact a tax credit for re-investment in Alaskan 

infrastructure;

• Aging Cook Inlet fields currently produce less oil and gas than in previous years, and 

platforms have been, and likely will continue to be, “shut-in” (i.e., the wells cease 

production) when they no longer produce sufficient oil or gas. This opens up the 

possibility of using the unused pipelines to transport produced water back to the shut-in

platforms for injection; and,

• ConocoPhillips converted the Tyonek platform to zero discharge for its produced water in 

2004 and Chevron/Unocal converted the Anna platform in 2005. Since beginning 

production in Cook Inlet in 2002, Forest Oil injects its platform’s produced water and 

drilling wastes. Thus, for 3 of the 12 operating Cook Inlet platforms, managing produced 

water in this way has been demonstrated to be economically feasible.

 Technology Changes Since Permit Issuance in 1999

• Improvements in “grind and inject” technologies for drilling wastes now can overcome 

the Cook Inlet injection well plugging problems that were a large part of the previous 

rationale for allowing drilling waste disposal directly into Cook Inlet; and,

• Marathon and Chevron/Unocal, both major operators in Cook Inlet, opened new grind 

and inject facilities for drilling wastes in the Cook Inlet region in 1999 and 2002, 

respectively.
Dishonorable Discharges vii

Scientific Changes and Traditional Ecological Knowledge Evidence Since Permit Issuance

in 1999

• New data from Exxon Valdez oil spill research on hydrocarbon effects on salmon show 

that far lower levels of contamination than previously recognized have adverse impacts; 

• New EPA data collected on oil and gas contaminants in food and Traditional Ecological 

Knowledge on the quality/quantity of subsistence foods, respectively, argue against 

allowing additional toxic discharges into Cook Inlet; and

• The National Marine Fisheries Service (NMFS) classified Cook Inlet’s beluga whales as 

a “depleted” stock of marine mammals under the Marine Mammal Protection Act in 

2000. Because the Cook Inlet beluga whale population has not increased in recent years

after sharp restrictions on Alaska Native subsistence hunting, NMFS currently is 

evaluating whether the whale should be classified as “threatened” or “endangered” under 

the Endangered Species Act. 

These recent developments, taken together, make a compelling case for EPA to require zero 

discharge for Cook Inlet offshore oil and gas operations during Clean Water Act permit renewal. 

Table ES-1 compares the reasons EPA used in its 1999 permit decision to allow discharges with 

current conditions in Cook Inlet. The current rationale for zero discharge is discussed in detail in 

Section VI of this report.

Table ES-1

Cook Inlet Discharge Comparison Between 1999 and the Present

Type of Discharge Primary 1999 Rationale Allowing 

Discharges

Current Rationale for

Zero Discharge

Produced water Cost High price of crude oil resulting in 

higher industry profits; royalty 

reductions; shut-in platforms and 

pipelines can be used for produced 

water injection instead of new 

pipeline construction; an injection 

well near Trading Bay Production 

Facility now may be feasible 

Drilling waste Lack of nearby facilities for disposal Technological improvements have

overcome injection problems; 

operators opened new disposal 

facilities
Dishonorable Discharges 1

I. Introduction and Purpose

Offshore Southcentral Alaska – within view of homes on the hillsides above Anchorage – stand 

sixteen drilling platforms with over 580 oil and natural gas wells protruding from their 

foundations (see Figure 1). These wells are approximately 11,000 feet deep, and the oldest 

platforms and wells date from the mid-1960s. Through the end of 2005, the wells produced over 

1 billion barrels of oil (nearly 45 billion gallons), over 3 trillion cubic feet of natural gas, over 

1.1 billion barrels of contaminated “produced water” (over 48 billion gallons) and a significant

quantity of contaminated drilling wastes.1 Additionally, Cook Inlet offshore operators injected

over 2.3 billion barrels of treated seawater (97 billion gallons) to maintain and enhance oil

production in the underlying formations. 

Cook Inlet operators (with the exception of Forest Oil and its Osprey platform2 which is not 

included in this report unless otherwise noted) discharge nearly all of the contaminated produced 

water and drilling wastes generated from the 

offshore oil and gas platforms into Cook Inlet. 

The discharges occur following only minimal 

treatment (gas flotation) of the produced water 

and no treatment of the drilling wastes. In 

2005, operators sent over 99.8% of the total 

produced water from Cook Inlet’s offshore 

operations by pipeline to three onshore facilities 

– Trading Bay Production Facility, Granite 

Point Production Facility, and the East Foreland 

Treatment Facility – where they separated the 

crude oil, natural gas, and produced water and 

piped the still-contaminated produced water 

offshore for discharge. 

Table 1 shows oil and gas field locations, 

ownership, ages, and status of existing Cook 

Inlet offshore platforms. The platforms are 

located in what the federal and state 

governments consider a “coastal” area 

(generally less than three nautical miles, almost 

3.5 miles, offshore) in state waters, and thus 

under state jurisdiction. 

 

1

 Each Cook Inlet well generates approximately 30,000 barrels (1.26 mill. gallons) of drilling wastes (Drilling Waste 

Disposal Alternatives: A Cook Inlet Perspective, Marathon Oil Company and Unocal Corporation, March 1994, p. 

6.)

2

 Forest Oil’s Osprey platform, which is permitted individually under the Clean Water Act, began operations in 

Cook Inlet in 2002 after issuance of the 1999 Clean Water Act general discharge permit for all other Cook Inlet oil 

and gas platforms. Forest Oil’s Osprey platform permit (U.S. EPA Permit Number AK-005330-9) requires zero 

discharge. 

Produced water: “Produced water” is any water 

brought to the surface during oil and gas

production including water containing oil from 

the geologic formation, injection water, and

drilling additives. Generally briny, produced

water typically contains pollutants such as oil and 

grease, acids, ammonia, benzene, naphthalene,

metals (e.g., chromium, copper, lead, zinc), and 

sometimes radionuclides, following separation

from crude oil and natural gas.

Drilling wastes - fluids, muds, and cuttings: 

“Drilling wastes” covers all these byproducts. 

“Drilling fluids” or “drilling muds” are the

lubricating materials used in the rotary drilling of 

wells during well exploration and development 

(i.e., prior to production), which clean and

condition well holes, lubricate the drill bit,

transport drill cuttings to the surface, and

maintain down-hole pressure to prevent well

blowouts. Drilling fluids and muds are mixtures 

of water or oil with clay, metals (e.g., cadmium, 

mercury, and lead), and organics (e.g., alkylated 

benzenes, naphthalenes, phenanthrenes). “Drill

cuttings” are small pieces of formation rock

brought to the surface during drilling.
Dishonorable Discharges 2
Dishonorable Discharges 3

Table 1

Cook Inlet Offshore Platform Information

Platform Name Oil/Gas Field Current 

Owner/Operator

Installation 

Date

Status

“A” Middle Ground Shoal XTO Energy 1964 Active

Anna Granite Point Chevron/Unocal 1966 Active

Baker Middle Ground Shoal Chevron/Unocal 1965 Shut-in* (2003)

Bruce Granite Point Chevron/Unocal 1966 Active

“C” Middle Ground Shoal XTO Energy 1967 Active

Dillon Middle Ground Shoal Chevron/Unocal 1966 Shut-in* (2003)

Dolly Varden McArthur River Chevron/Unocal 1967 Active

Granite Point Granite Point Chevron/Unocal 1966 Active

Grayling McArthur River Chevron/Unocal 1967 Active

King Salmon McArthur River Chevron/Unocal 1967 Active

Monopod Trading Bay Chevron/Unocal 1966 Active

Spark Trading Bay Marathon 1968 Injection only

Spurr Trading Bay Marathon 1968 Shut-in* (1993)

Steelhead McArthur River Chevron/Unocal 1986 Active

Tyonek North Cook Inlet Phillips 1968 Active (gas only)

* “Shut-in” means the platform’s wells no longer produce oil or gas, nor are they used to inject wastes.

Alaska’s Cook Inlet is the only coastal area in the nation where produced water and drilling 

wastes can be released into marine waters. The 1999 Clean Water Act general3 discharge permit 

for Cook Inlet’s offshore oil and gas operations contains this U.S. Environmental Protection 

Agency (EPA) exemption (see Appendix 1 for the applicable regulation). In contrast, EPA does 

not allow discharge of produced water and drilling wastes in coastal areas in the Gulf of Mexico,

off the coast of California, and elsewhere.

This report provides a rationale for re-examining EPA’s earlier permit decision allowing

produced water and drilling wastes to be discharged into Cook Inlet’s biologically-productive 

and economically-important coastal waters. It now is appropriate for EPA to mandate 

requirements more protective of Cook Inlet’s valuable marine environment because 

circumstances have changed significantly. Moreover, ongoing discharges pose the increased risk 

of cumulative harm to Cook Inlet’s marine organisms.

II. Why Care?

Long after Cook Inlet’s oil and gas resources are extracted, fishing, tourism and recreation, and 

subsistence will continue if the ecosystem remains healthy. A healthy Cook Inlet ecosystem also

provides substantial jobs and revenue to Southcentral Alaska residents, approximately half the 

state’s population.

 

3

 The permit is considered a “general” permit because it covers multiple facilities.
Dishonorable Discharges 4

It is reasonable to ask why EPA created a coastal-area exemption for Cook Inlet’s offshore 

drilling operations in the first place and why the exemption is a concern.

Background on the Cook Inlet exemption. As shown in Table 1, operators installed nearly all of 

Cook Inlet’s offshore platforms in the late 1960s, prior to passage of the Clean Water Act in 

1972. Cook Inlet’s relatively old platforms were designed in an era before extensive discharge 

regulation, making it potentially more difficult and costly for the platforms to achieve the zero 

discharge norm. Congress recognized the importance of allowing for an orderly upgrading of 

facility infrastructure to meet the Clean Water Act discharge elimination goal4and designed the 

statute to encourage strengthening of discharge permits during the five-year permit renewals.

In 1999, EPA issued the Clean Water Act general discharge permit for Cook Inlet’s fifteen 

offshore platforms (i.e., not including Osprey platform) and their three related onshore facilities5

based on a previously-issued EPA technical and economic document known as the Effluent 

Limitations Guideline (ELG) for coastal oil and gas extraction operations.6 ELGs contain 

technology-based discharge limits for all facilities in a particular industrial category, which then 

are incorporated into discharge permits nationwide. EPA issued the final ELG for coastal oil and 

gas extraction operations in 1996 and has not updated it since. In response to requests from 

several stakeholders to update the ELG in 2004, EPA stated it would not do so in part because 

the EPA permit writer could “require an operator to demonstrate that zero discharge is not 

technically feasible for a specific project.”

7

 EPA did not, however, require a demonstration of 

technical feasibility prior to development of the current draft general discharge permit.

The 1999 Clean Water Act permit for Cook Inlet offshore oil and gas operations expired on April 

1, 2004 but has been extended until EPA issues a new permit, probably in 2006. The new permit 

can contain different permit conditions – including prohibiting discharges to Cook Inlet – so long 

as it is in compliance with the federal Clean Water Act. Prior to permit issuance in 1999, EPA’s 

stated rationale for the Cook Inlet exemption was: “The EPA rejected zero discharge for muds & 

cuttings in large part because the technology of grinding and injection has not been demonstrated 

to be available throughout Cook Inlet. The EPA rejected zero discharge of produced water 

because zero discharge is not economically achievable in Cook Inlet.”8

 

4

See 33 USC 1251(a)(1) which states that “it is the national goal that the discharge of pollutants into the navigable 

waters be eliminated by 1985.” EPA reiterates this goal in the preamble to the final rule covering coastal oil and gas 

extraction point source discharges, 61 Federal Register 66088 (December 16, 1996).

5

 U.S. EPA Permit Number AKG-28-5000. 

6 Development Document for Final Effluent Limitations Guidelines and Standards for the Coastal Subcategory of 

the Oil and Gas Extraction Point Source Category, U.S. Environmental Protection Agency, EPA-821-R-96-023, 

October 1996.

7

Technical Support Document for the 2004 Effluent Guidelines Program Plan, U.S. Environmental Protection 

Agency, EPA-821-R-04-014, p. 5-230 (for Drilling Fluids and Drill Cuttings) and p. 5-231 (for Produced Water), 

August 2004. 

8

 Response to Comments Received on the Proposed Reissuance of the Cook Inlet General NPDES Permit, U.S. 

EPA, p. 14 (undated).
Dishonorable Discharges 5

EPA issued the draft discharge permit in March 2006.9 In the draft permit, the offshore 

platforms are permitted to discharge in their produced water over 100,000 gallons of oil and 

grease annually and nearly 887,000 lbs of metals such as mercury, nickel, copper, manganese 

and zinc.10 The draft permit also allows nine Cook Inlet discharge locations, a significant 

increase from the four locations now discharging produced water (the current permit allows up to 

eight discharge locations). 

As a result of the earlier ELG and permitting decisions, Cook Inlet’s offshore oil and gas 

producers covered by the permit (i.e., Chevron/Unocal and XTO Energy11) do not pay the costs 

other companies with coastal offshore oil and gas operations in the U.S. pay to achieve zero 

discharge, i.e., conversion of platforms and wells so produced water and drilling wastes are 

injected. Additionally, these operators do not pay the true costs of production since they do not 

pay to discharge contaminants into public waters. When EPA allows operators to discharge 

pollution into Cook Inlet, that decision is a federal subsidy to Cook Inlet operators which – in 

turn – degrades the valuable Cook Inlet ecosystem.

Who and what are affected by the Cook Inlet exemption. Though Cook Inlet has relatively strong 

tides, at least some of the toxic pollutants discharged from drilling operations remain in Cook 

Inlet, dispersed and dissolved in the water column and adsorbed onto sediments.

12

Contamination near the platforms has not been measured, however. Marine organisms are 

exposed to these pollutants via consumption and/or dermally. Heavy metals are among the toxic 

discharges from offshore oil and gas operations that can persist in fish, shellfish, and marine 

mammals. Those who eat fish and shellfish from Cook Inlet may ingest some quantity of toxic 

pollutants from offshore oil and gas operations, though the lack of complete testing makes it 

difficult to know the full extent of the health impacts (see Section VI). 

Cook Inlet is a world-renown fishery, prized for its salmon (especially red, king, and silver), 

halibut and other groundfish, herring, and shellfish.

13 The value of upper and lower Cook Inlet 

 

9

 National Pollutant Discharge Elimination System Permit No.: AKG-31-5000. See 

http://yosemite.epa.gov/r10/WATER.NSF/NPDES+Permits/DraftPermitsAK for the draft permit and related 

information (last visited on May 24, 2006). 

10 Calculations based on the draft permit’s maximum projected discharge rates for produced water discharges by 

facility and facility-specific effluent limits. See Fact Sheet, Oil and Gas Exploration, Development and Production 

Facilities Located in State and Federal Waters in Cook Inlet, Permit Number AKG-31-5000, U.S. Environmental 

Protection Agency Region 10, February 23, 2006, Table 2 (p. 34) and Appendix B (pp. 69-73). 

11 ConocoPhillips and Marathon, which operate Cook Inlet platforms, currently do not discharge produced water 

into Cook Inlet.

12 Tides move materials both into and out of upper Cook Inlet, where the platforms are located. The hydraulics of 

Cook Inlet are extremely complicated and not fully understood. Only a sufficient net current out of the area 

containing the discharges throughout the year would disperse all the toxic materials, and that is not the case because 

there is little or no flow into Cook Inlet from upper Cook Inlet rivers in winter

13 See http://www.cf.adfg.state.ak.us/region2/finfish/salmon/uci/cookinlet.php (last visited on April 17, 2006).
Dishonorable Discharges 6

commercial salmon was $33 million in 2005,

14 which does not include the value of sportfishing, 

Alaska Native subsistence, personal use fishing for Alaska residents not practicing subsistence, 

and non-salmon fisheries. The “Kenai Wild” brand of salmon from Cook Inlet has, in recent 

years, gained market-share outside of Alaska as a high-quality, valuable, wild Alaskan salmon 

product from presumably unpolluted waters.

One in eight private-sector jobs in Alaska is tourism-related, Alaska’s fastest growing industry. 15 

According to the state Chamber of Commerce, approximately 1.2 million visitors traveled to 

Alaska in 2002 and spent between $1200 and $1300 on average per visitor.16 In 1993, the last 

year such data were collected, 67% of summer visitors to Alaska traveled in Southcentral Alaska 

including the Cook Inlet region. 17 Using these numbers, Southcentral Alaska received over $1 

billion in summer revenue from tourism in 2002.

Native communities including Port Graham, Nanwalek, Chickaloon, Eklutna, Seldovia, 

Ninilchik, and Tyonek, members of the Kenaitze Tribe, and others depend on the Cook Inlet 

watershed’s healthy waters and habitats for their livelihoods. These villages pursue a subsistence 

lifestyle that is centuries old, with wild, including marine, foods supplying a high percentage of 

villagers’ diets. Because a higher percentage of their food supply comes from Cook Inlet-related 

sources than for most non-Native individuals, many of those living in these communities may be 

disproportionately impacted by toxic chemicals in their foods compared with non-Natives.

As part of the draft general discharge permit’s Environmental Assessment, EPA “facilitated the 

collection of Traditional Ecological Knowledge (TEK) from Cook Inlet Area tribes.”18 While it 

is impossible to know if contaminants are the sole cause of the changes noted by Alaska Natives, 

EPA documented in its Fact Sheet for the draft permit that: 

Tribal members frequently noted an overall decline in the population of important food 

species being caught or harvested. These changes include salmon with thinner and less 

firm meat and smaller halibut with chalky and fibrous meat. In addition, Tribal members 

noted a disappearance in bull kelp and a decrease in the abundance of clams, cockles, 

bidarkis, cod, flounder, crab, shrimp, mussels, algae, seals and sea lions. Clams and 

mussels were observed to have thinner and sometimes transparent shells. Furthermore, 

Tribal members observed a higher incidence of red tide that has resulted in a decrease in 

the community’s ability to collect traditional food, including shellfish and octopus. 

 

14 Alaska Department of Fish and Game, Season Summaries, 

http://www.cf.adfg.state.ak.us/region2/finfish/salmon/salmhom2.php (last visited on May 9, 2006). 

15 See http://www.alaskachamber.com/artman/publish/tourism.html (last visited May 5, 2006).

16 Ibid.

17 Recreation and Tourism in South-Central Alaska: Patterns and Prospects, Steve Colt, Stephanie Martin, Jenna 

Mieren, and Martha Tomeo, prepared for the U.S. Forest Service, PNW-GTR-551, October 2002, p. 36. 

18 Fact Sheet, Oil and Gas Exploration, Development and Production Facilities Located in State and Federal 

Waters in Cook Inlet, Permit Number AKG-31-5000, U.S. Environmental Protection Agency Region 10, February 

23, 2006, p. 47.
Dishonorable Discharges 7

Tribal members also observed a decrease in the number of sea ducks, such as mergansers 

and scoters. A number of Tribal members noted finding lesions, growths and deformities 

on fish. Some Tribal members noted that non-commercial fish, such as hooligans and 

sticklebacks, have declined in numbers; thus, indicating that commercial and recreational 

fishing are not the sole causes for the observed decline in population...

The impact[s] on Tribes include traveling farther to collect food and the inability to 

obtain a sufficient quantity of traditional food. Since a significant portion of a Tribal 

member’s diet consists of seafood from Cook Inlet, there is increasing concern regarding 

the impact on health from contaminants that may accumulate in seafood and the affect 

(sic) of eating lower quality fish. This fear has led some parents to stop feeding their 

children traditional foods.19

Last, the impact of the discharges on Cook Inlet’s beluga whale population is unknown, but it

may be significant. According to EPA, “The discharge of produced water may affect, but is not 

likely to adversely affect, all of the considered species except the Beluga whale...The Beluga 

whales, which frequent the upper Inlet, may be adversely affected by pollutants in produced 

water. This species may be affected either directly (through exposure) or indirectly (through 

ingestion and bioaccumulation) (Avanti 1992)” (emphasis in original).20 

 

19 Ibid., pp. 48-9.

20 Cook Inlet (Reissuance) Fact Sheet, September 7, 1995, p. 38. A recent EPA analysis which does not address the 

accumulation of persistent toxic chemicals, however, doubts the likelihood of adverse effects from the discharges on 

Cook Inlet’s beluga whales despite the lack of recovery of the population in recent years. This study states –

without backup documentation – that:

Drilling fluid discharges could adversely affect prey availability in the immediate vicinity of the discharges 

because of the burial of benthic organisms or changes in bottom habitat characteristics. Such effects would 

be of limited size and duration. Exposure to increased pollutant concentrations within designated mixing 

zones are unlikely to cause adverse effects to beluga whales because of the whales’ mobility and limited 

amount of time within (sic) spent within these areas. Exposure to discharge waters that comply with 

chronic water quality standards are not expected to adversely affect beluga whales (Biological Evaluation 

for the Cook Inlet NPDES Permit, prepared for U.S. EPA Region 10 Office of Water by Tetra Tech, Inc., 

January 20, 2006, p. 5-13).
Dishonorable Discharges 8

III. Cook Inlet Offshore Drilling Production and Injection Data

Table 2 contains production data for Cook Inlet offshore oil and gas wells by platform, compiled 

from Alaska Oil and Gas Conservation Commission (AOGCC) databases. The offshore oil wells 

produce crude oil, natural gas, and produced water, while the gas wells generate only natural gas 

and produced water.21 Table 2 also shows the total volume of seawater injected (i.e., 

“waterflooding”) to enhance or maintain oil production.

Figure 2, based on data from Table 2, graphically displays total oil, natural gas, and produced 

water generation from each Cook Inlet offshore platform through the end of 2005.

Figure 2

Production from Offshore Cook Inlet Wells through 2005

0

50,000,000

100,000,000

150,000,000

200,000,000

250,000,000

300,000,000

350,000,000

400,000,000

"A"

"C"

Anna

BakerBruce

Dillon

Dolly Varden

Granite Point

Grayling

King Salmon

Monopod

Osprey

Spark

Spurr

Steelhead

Tyonek

Platform

Crude oil and Produced Water Production (bbls)

0

200,000,000

400,000,000

600,000,000

800,000,000

1,000,000,000

1,200,000,000

1,400,000,000

1,600,000,000

1,800,000,000

Natural Gas Production (mcf)

Crude Oil

Produced Water

Natural Gas

 

21 AOGCC reporting instructions for Form 10-405, the Monthly Production Report, require producers to identify 

wells as either Type 1 – oil producer or Type 2 – gas producer.
Dishonorable Discharges 9

Table 2

Total Cook Inlet Oil, Natural Gas, and Produced Water Production and Seawater Injection from Start-up through 2005

TOTALS

Offshore

Platform

Oil Wells -

Crude Oil

(bbls)

Oil Wells -

Nat. Gas

(mcf)

Oil Wells -

Prod. H20

(bbls)

Gas Wells -

Nat. Gas 

(mcf)

Gas Wells -

Prod. H20

(bbls)

Total Cr. Oil

(bbls)

Total Nat. Gas

(mcf)

Total Prod.

H20*

(bbls)

Total Sea H2O

Injected

(bbls)

Yrs.

Operat.

"A" 78,084,542 36,407,113 16,576,152 476,535 0 78,084,542 36,883,648 16,576,152 110,056,531 41

Anna 54,220,394 46,819,728 11,236,296 54,220,394 46,819,728 11,236,296 62,636,913 39

Baker 31,931,536 20,618,600 15,747,129 15,907,806 131 31,931,536 36,526,406 15,747,260 83,202,736 40

Bruce 26,766,481 24,831,530 2,750,230 872,758 0 26,766,481 25,704,288 2,750,230 37,978,339 39

"C" 54,723,858 25,139,677 19,572,417 54,723,858 25,139,677 19,572,417 98,854,815 38

Dillon 28,323,625 10,337,409 56,624,197 28,323,625 10,337,409 56,624,197 44,365,995 39

Dolly Varden 213,694,235 72,213,308 243,277,390 34,550,784 0 213,694,235 106,764,092 243,277,390 457,415,259 38

Granite Point 62,027,630 55,873,666 3,065,934 62,027,630 55,873,666 3,065,934 56,697,019 39

Grayling 246,994,106 93,605,049 363,519,807 127,065,445 2,260 246,994,106 220,670,494 363,522,067 624,241,330 38

King Salmon 147,891,083 55,423,117 260,837,506 44,926,210 0 147,891,083 100,349,327 260,837,506 517,782,364 38

Monopod 75,308,434 63,434,084 70,881,514 75,308,434 63,434,084 70,881,514 132,396,589 39

Osprey** 1,830,072 448,057 2,052,463 1,830,072 448,057 2,052,463 1,747,751 3

Spark 17,508,888 4,603,045 23,694,809 2,165,027 198,430 17,508,888 6,768,072 23,893,239 27,276,029 37

Spurr 9,935,186 2,744,796 8,500,078 3,543,248 0 9,935,186 6,288,044 8,500,078 6,471,739 37

Steelhead 12,668,057 8,123,692 51,103,953 821,920,335 370,414 12,668,057 830,044,027 51,474,367 58,850,021 19

Tyonek 1,707,924,357 665,051 1,707,924,357 665,051 240,781 37

Total 1,061,908,127 520,622,871 1,149,439,875 2,759,352,505 1,236,286 1,061,908,127 3,279,975,376 1,150,676,161 2,320,214,211

Total (gals) 44,600,141,334 48,276,474,750 44,600,141,334 48,328,398,762 97,448,996,862

Notes: There are 42 gallons per barrel (bbl).

“mcf” means thousand cubic feet.

* A tiny fraction of the column Total, approximately 0.05%, has been injected (most of Osprey platform’s produced water and a small portion of Anna and Tyonek platforms’ 

produced water).

** Forest Oil’s Osprey platform is not included in the Cook Inlet general discharge permit.
Dishonorable Discharges 10

Table 2 shows that total injected seawater in Cook Inlet is approximately twice the amount of 

total produced water generated. Figure 3 compares the volume of produced water generated to 

the volume of treated seawater injected by platform for platforms covered by the general 

discharge permit. This figure shows that – with the exception of currently shut-in Dillon and 

Spurr platforms – the volume of injected seawater by platform has been less than the volume of 

produced water generated and discharged to Cook Inlet. Figure 3 indicates that there was 

enough capacity in each platform’s respective injection zone to accommodate the volume of 

produced water generated by the platforms’ wells had a decision been made during platform 

start-up to design the platforms for produced water injection.

Figure 3

Produced Water vs. Injected Seawater by Platform through 2005

0

100,000,000

200,000,000

300,000,000

400,000,000

500,000,000

600,000,000

700,000,000

"A""C"

Anna

BakerBruce

Dillon

Dolly Varden

Granite Point

Grayling

King Salmon

Monopod

Spark

Spurr

Steelhead

Tyonek

Platform

Volume (bbls)

Produced Water

Injected Seawater

Injection of liquids serves two key purposes: it increases formation pressure which helps oil 

production, and it provides a well-regulated (by the AOGCC) means of wastewater disposal, e.g., 

of produced water. Both industry and public needs are well-served by produced water injection

into oil-producing formations.

Figure 4 shows total annual production from Cook Inlet’s offshore oil and gas wells (AOGCC 

data). As field development proceeds, oil and gas production initially increases quickly and then 

declines over a longer period. As shown in Figure 4, produced water generation increases as oil 

and gas fields age, though this quantity may be affected by the water injection rate into oil and 

gas reservoirs. Note that the quantity of Cook Inlet produced water generation has remained 

roughly unchanged or decreased since 1991. Nevertheless, the draft Clean Water Act permit 
Dishonorable Discharges 11

Figure 4

Annual Production from Offshore Cook Inlet Wells (including Osprey platform)

0

20,000,000

40,000,000

60,000,000

80,000,000

100,000,000

120,000,000

140,000,000

160,000,000

196519671969197119731975197719791981198319851987198919911993199519971999200120032005

Year

Production

Crude Oil (bbls)

Natural Gas (mcf)

Produced Water (bbls)

allows an increase in annual produced water discharge from Cook Inlet offshore platforms of 

69%. 

IV. Cook Inlet Produced Water Discharge Data

Cook Inlet oil and gas producers report offshore discharges from their platforms monthly to EPA 

and the state under EPA’s general discharge permit requirements in “Discharge Monitoring 

Reports” (DMRs). Nearly all states have “delegated” programs under the federal Clean Water

Act where the states issue and enforce discharge permits, however Alaska does not.22 Thus, EPA 

currently issues and enforces Alaskan water discharge permits from its Seattle office, but the 

State of Alaska provides input into EPA’s development of the permits. Monthly DMRs contain 

information on produced water (this section) and drilling wastes (Section V), as well as other 

forms of wastewater discharges covered by the Clean Water Act (e.g., deck drainage, sanitary 

wastes, etc.; these other discharges are not covered in this report). 

Produced water discharge locations, volume, and composition. Not all produced water generated 

by Cook Inlet offshore oil and gas platforms is discharged into the marine environment directly. 

Figure 5 illustrates which platforms send their produced water onshore, where operators separate 

 

22 The State of Alaska enacted legislation in 2005 which enables the state to apply for Clean Water Act delegation 

from EPA.
Dishonorable Discharges 12

Figure 5

Platform Discharge Locations for Produced Water as of January 2006

 A C Dillon Baker Dolly Steel- Grayling King Mono- Spark Spurr Granite Anna Bruce Tyonek

 Varden head Salmon pod Point

 

 Shut-in Shut-in Zero Zero

 Discharge Discharge

 

 East Foreland Trading Bay Injection Only Granite Point Direct

Treatment Fac. Production Facility (zero discharge) Production Fac. Discharge to

 (onshore) (onshore) (onshore) Cook Inlet

 (16 m. depth)

 Discharge to Discharge to Discharge to

 Cook Inlet Cook Inlet Cook Inlet

 (8 m. depth) (11 m. depth) (17 m. depth)
Dishonorable Discharges 13

the crude oil, natural gas, and produced water and discharge the still-contaminated produced 

water into Cook Inlet. Figure 5 also shows that Bruce platform is the only platform currently

discharging produced water directly into Cook Inlet.

Table 3 compares current produced water discharge locations shown in Figure 5 with discharge 

locations allowed in the draft Clean Water Act permit. There are five locations where discharges 

are allowed in the draft permit which are not discharging at the present time. 

Table 3

Cook Inlet Platform and Onshore Facility Produced Water Discharge Locations,

Currently and in the Draft Permit

Platform/Onshore Facility Discharge Location as of 

January ‘06

Discharge Allowed in the 

Draft Permit?

Platform

“A” Sent onshore No – unchanged

Anna Zero discharge Yes – new

Baker Shut-in Yes – new

Bruce Direct discharge Yes – not new

“C” Sent onshore No – unchanged

Dillon Shut-in Yes – new

Dolly Varden Sent onshore No – unchanged

Granite Point Sent onshore Yes – new

Grayling Sent onshore No – unchanged

King Salmon Sent onshore No – unchanged

Monopod Sent onshore No – unchanged

Spark Injection only No – unchanged

Spurr Shut-in No – unchanged

Steelhead Sent onshore No – unchanged

Tyonek Zero discharge Yes – new

Onshore Facility

East Foreland

Treatment Facility

Discharge to Cook Inlet Yes – not new

Granite Point Production 

Facility

Discharge to Cook Inlet Yes – not new

Trading Bay Production 

Facility

Discharge to Cook Inlet Yes – not new

Table 4 shows average daily produced water generation rates from Cook Inlet’s offshore oil and 

gas operations and the average concentration of the pollutants reported to EPA for 2005 on 

DMRs (see Appendix 2 for monthly DMR data). Although they are operating under a general 

discharge permit, each facility has different monitoring and reporting requirements based on the 

likelihood of the discharge to exceed water quality standards at the edge of the discharge’s 

“mixing zone”23 whose distance is determined by the state. The Table 4 value for annual 

produced water generation reported to EPA agrees with that reported to AOGCC within 0.3%.

 

23 A “mixing zone” is the area within a receiving water body where the State of Alaska allows discharged 

contaminants to exceed traditional water quality standards designed to protect people and fish. At the zone’s edge, 
Dishonorable Discharges 14

Table 4

Produced Water Generation Rate and Annual Average Concentrations of EPA-Permitted Pollutants, 2005

Platform/Facility Prod. H2O Oil/Grease Copper Mercury Zinc Silver Lead Arsenic TAH24 TAqH25

(mgd) (ppm) (ug/l) (ug/l) (ug/l) (ug/l) (ug/l) (ug/l) (ppb) (ppb)

Anna Platform26 0

Bruce Platform 0.006984 16.3 3617 2.5 15734

Granite Point Prod. Fac. 0.015691 18.1 17.11 0.2311 4.134 13181

Trading Bay Prod. Fac. 4.369068 19.6 12.11 2.583 8722 8932

East Foreland Trtmt. Fac. 0.160833 11.5 0.69 0.0000 6.65 0.099 31.85 14140 14475

Total 4.552576

Total (gals/year) 1,661,690,240

Total (bbls/year) 39,564,053

Column Average 16.4 9.97 0.1156 3617 4.58 2.272 31.85 12944 11704

Table 5 shows the percentage of produced water and oil and grease generated by each Cook Inlet 

discharge location for 2005. This table shows that:

1. The Trading Bay Production Facility, located onshore on the west side of Cook Inlet, 

represents nearly 96% of the produced water and over 97% of the oil and grease 

discharged into Cook Inlet from offshore oil and gas operations in 2005; 

2. If all three onshore facilities (Trading Bay Production Facility, Granite Point Production 

Facility, and East Foreland Treatment Facility) injected their discharges to the 

subsurface, over 99.8% of the produced water discharges into Cook Inlet in 2005 would 

be eliminated. 

Table 5

Breakdown of Produced Water and Oil and Grease Generation by Cook Inlet Discharger, 2005

Platform/Facility Prod. H20 gen. Prod. H20 Oil/Grease Oil/Grease

(gallons/yr) (percent) (gallons/yr) (percent)

Bruce Platform 2,549,160 0.15 42 0.13

Granite Point Prod. Fac. 5,727,215 0.34 104 0.32

Trading Bay Prod. Fac. 1,594,709,820 95.97 31,256 97.44

East Foreland Trtmt. Fac. 58,704,045 3.53 675 2.10

Total 1,661,690,240 32,077

 

the permit writers consider dilution sufficient to meet the standards. Permit writers use hydraulic models to 

determine the level of dilution necessary.

 

24 TAH is Total Aromatic Hydrocarbons.

25 TaqH is Total Aqueous Hydrocarbons.

26 As of January 12, 2005, Anna Platform began injecting its produced water (February 18, 2005 letter from Dale A. 

Haines of Chevron/Unocal to Mr. Chae Park of U.S. EPA Region 10).
Dishonorable Discharges 15

Toxic chemicals in produced water discharges. Cook Inlet offshore oil and gas operations’ 

DMRs for produced water for 2005 can be used to assess the quantity of metals released into 

Cook Inlet from these facilities. Table 4 shows that many pollutants are not measured for every 

discharge location, however. In order to calculate total discharges into Cook Inlet from these 

facilities, Cook Inletkeeper calculated a weighted average concentration for each pollutant based 

on produced water flow rates and data from the facilities which measured particular chemical

concentrations. The weighted average concentrations for the discharges’ various metals for 2005 

are shown in Table 6. 

Table 6

Weighted Average Concentration of Metals in Offshore Discharges to Cook Inlet, 2005

Metal Weighted Average Concentration (micrograms/liter)

Copper 11.72 

Mercury 0.02 

Zinc 3617 

Silver 6.48 

Lead 2.73 

Arsenic 31.85

Using the data from Table 6 and the total produced water generation rate listed in Table 5 results 

in the annual quantities of metals released into Cook Inlet from offshore oil and gas operations 

shown in Table 7.

Table 7

Annual Quantity of Metals in Offshore Drilling Discharges to Cook Inlet, 2005

Metal Annual Discharge (lbs)

Copper 163

Mercury 0.28 

Zinc 50,162

Silver 90

Lead 38

Arsenic 442

V. Cook Inlet Offshore Drilling Waste Discharges

When wells are drilled, drilling fluids (commonly referred to as drilling muds) lubricate and cool 

the drill bit, carry drill cuttings (rock solids) to the surface, and maintain down-hole pressure to 

prevent well blowouts. These fluids are specially formulated to achieve appropriate pressure, 

viscosity (ease of flow), corrosion prevention, and other characteristics. The fluids include 

minerals such as barite, which may contain cadmium and mercury contaminants. As drilling 

proceeds and the fluids become mixed with drill cuttings from the hole, the fluids must be 

diluted and have solids, or cuttings, removed to ensure proper flow characteristics. Excess fluid 

volume generated is disposed of as drilling waste; the removed cuttings, with some residual

drilling fluid, are disposed of as drill cuttings. Drilling fluids can be oil-based, water-based, or 

synthetic-based.
Dishonorable Discharges 16

Drilling waste discharges, representing drilling fluids and drill cuttings, do not occur on a regular 

basis. These discharges occur periodically over a multi-month period when wells are drilled 

from offshore platforms or when well workovers occur to increase production. Drilling waste 

discharges also occur during exploratory operations, i.e., drilling in areas without an existing 

platform or wells in order to determine whether a formation(s) is commercially viable 

(“exploratory” operations differ from “production” operations; production operations are the 

main focus of this report).

Cook Inlet operators are precluded from discharging oil-based drilling fluids into Cook Inlet by 

the requirements of the existing general discharge permit. Drilling wastes that do not meet the 

general discharge permit requirements and are not discharged offshore into Cook Inlet or into an 

offshore Class II disposal well27 are sent onshore for disposal.

EPA allows discharges of water-based drilling fluids and drill cuttings from coastal operators in 

Cook Inlet, but not from other coastal operators in the U.S. (see Appendix 1). This is due to 

EPA’s presuming (in its mid-1990s ELG analyses) that Cook Inlet contained large areas unfit for 

grinding and injection of drilling wastes. As discussed in Section VI, the existence of two new 

grind and inject facilities and several Class II disposal wells in the region belie this assumption.

In Cook Inlet in 2005, operators reported that no drilling wastes (fluids/muds and cuttings) were 

discharged directly into Cook Inlet from platforms covered by the general discharge permit. It is 

unclear if the lack of water-based drilling wastes discharged into Cook Inlet in 2005 will 

continue. Escopeta Oil, a new operator in Cook Inlet, recently stated that it intends to inject its

exploratory and production-related drilling wastes28 even though EPA does not require operators 

to inject exploratory drilling wastes. In 2001 and 2002, Cook Inlet oil and gas operators reported 

over 27,410 barrels of drilling wastes discharged directly into Cook Inlet from five platforms: 

XTO’s “A” and “C” platforms, Chevron/Unocal’s Steelhead and Monopod platforms, and Forest 

Oil’s Osprey platform (exploratory drilling wastes only).29 

VI. Current Conditions Warrant a Shift to Zero Discharge

The new general discharge permit for Cook Inlet’s offshore oil and gas operations is the critical 

means the federal government uses to protect Cook Inlet waters (the state provides input into 

federal permit issuance). EPA accepted comments on the draft permit through May 31, 2005.

Among the most favorable economic changes for Cook Inlet offshore oil operations which have

occurred since EPA made its 1999 decision to allow discharges is the dramatic increase in the 

price of oil. The wellhead price of Cook Inlet oil has increased from $12.56 per barrel in 1999 to 

 

27 Class II disposal wells – part of U.S. EPA’s Underground Injection Control program under the Safe Drinking 

Water Act – are disposal injection wells permitted to accept wastes from oil and gas operations. 

28 Steve Sutherland, Escopeta Oil, Cook Inlet Regional Citizens Advisory Council board meeting on May 19, 2006.

29 Cook Inletkeeper review of operator-submitted Discharge Monitoring Reports for 2001-2.
Dishonorable Discharges 17

$56.33 per barrel in 2006, an increase of 448% in constant 2006 dollars.

30 This extraordinary 

increase should completely change the economic analysis which resulted in the previous EPA 

decision allowing produced water and drilling waste to be discharged into Cook Inlet.

Using data from the Alaska Department of Revenue Tax Division, the average Cook Inlet 

wellhead price for a barrel of crude oil in 2005 was $50.21.31 Given the $30-45 costs of 

production in Cook Inlet presented to the legislature in April 2006 by Chevron, 32 earnings were 

approximately $10 per barrel for a total of nearly $59 million profit for Cook Inlet operations in 

2005 (almost 5.9 million barrels of oil were produced in Cook Inlet; AOGCC data). 

In addition to the enormous increase in the price of oil, Cook Inlet’s offshore oil operations 

benefit from royalty reductions given the companies by the Alaska legislature in 200333 when 

Cook Inlet crude oil was selling for less than $27 per barrel. 34 These royalty reductions, i.e., 

reductions in the amount of money paid to the state for oil produced on its leased acreage

(typically 12.5%), range from 2.5% to 7.5% depending on the oil production rate per platform. 

Four of the ten Cook Inlet platforms producing oil and cove red by the general discharge permit

currently receive royalty reductions (Bruce, Monopod, and Steelhead platforms owned by 

Chevron/Unocal and “C” platform owned by XTO Energy).

Another economic change likely to benefit the industry is the Alaska legislature’s probable

passage of some version of the Petroleum Production Tax, including a 20% or more tax credit for 

qualified capital expenditures. Upgrading Cook Inlet platforms’ treatment and disposal systems 

for produced water and drilling wastes certainly would qualify for this tax credit.

Other new economic, technologic, and scientific and TEK evidence and data since the 1999 

general discharge permit issuance follow:

Drilling economics: produced water. EPA used a 1994 industry-developed zero discharge study35

to develop its estimate of the cost to Cook Inlet operators to achieve zero discharge of produced 

water. The industry’s cost analysis included construction of four new pipelines from onshore to 

offshore platforms for produced water injection and modifications to ten (of the fifteen general 

 

30 Spring 2006 Revenue Sources Book , Alaska Department of Revenue, Tax Division, Real $2006 Crude Oil & 

Natural Gas Prices, http://www.tax.state.ak.us/sourcesbook/Real$2006Oil&NatGasPrices.pdf. 

31 See http://www.tax.state.ak.us/programs/oil/prices/historicaldata/Cookwellhead.asp (last visited on May 11, 

2006).

32 See http://www.akdemocrats.org/ppt/chevron_testimony_4_6_06.pdf, p. 9 (last visited on May 11, 2006).

33 See SB185, http://www.legis.state.ak.us/basis/get_bill.asp?session=23&bill=SB185 (last visited on May 11, 

2006).

34 See http://www.tax.state.ak.us/programs/oil/prices/historicaldata/Cookwellhead.asp (last visited on May 11, 

2006).

35 Zero Discharge Analysis: Trading Bay Production Facility, Cook Inlet, Alaska, Marathon Oil Company, Unocal 

Corporation, March 1994.
Dishonorable Discharges 18

discharge permit) platforms in preparation for injection. The capital costs of constructing four 

new offshore pipelines to transport produced water for injection (three new pipelines from 

Trading Bay Production Facility and one new pipeline from the East Foreland Treatment 

Facility) are the single most expensive items in industry’s/EPA’s zero discharge cost estimate.

These four pipelines and their associated equipment represent 71% of the predicted $96.9 million 

capital costs,36 or $69.0 million for the pipelines (all costs are in 1995$).

Additionally, the estimate included the following currently-unnecessary capital costs for 

modifications to: 1) two shut-in platforms (Dillon and Baker) - $4.6 million, and 2) three

platforms that already inject produced water (Anna, Spark, and Tyonek) - $9.5 million. These 

currently-unnecessary capital costs represent an additional 15% of the predicted capital costs.

A re-examination of industry’s/EPA’s zero discharge analysis based on current platform 

operating conditions would result in substantially less cost to achieve zero discharge because 

there currently is no need for four new onshore to offshore pipelines, nor for multiple, new 

platform injection sites. Consider the following, two, lower-cost zero discharge scenarios: 

 

36 Development Document, op. cit., Appendix XI-2, Capital Costs for Option 3, Zero Discharge Via Injection, pp. A33 – A-42.
Dishonorable Discharges 19

Figure 6

Two Zero Discharge Scenarios for Produced Water Based on 

Current Cook Inlet Drilling Conditions

Scenario 1:

First, if it is in good repair, use the existing pipeline connecting the closed Dillon platform to the 

East Foreland Treatment Facility as a return line for produced water from onshore, with 

injection occurring either at Dillon or at “C” platform (connected to Dillon by pipeline), rather 

than injecting treated seawater at “C” to maintain oil field pressure;

Second, continue using the pipeline(s) from the Granite Point Production Facility to Spark 

platform as a return line(s) for produced water injection at Spark platform. This line(s) should 

be able to carry produced water from Bruce and Granite Point platforms for injection at Spark

platform; and

Third, there are two, comparatively low-cost zero discharge options for the Trading Bay

Production Facility. One or both of these options might need to be utilized to address the large 

volume of Trading Bay produced water. These options are: 1) construct a single, new largediameter produced water pipeline from Trading Bay Production Facility to an offshore platform 

in the McArthur River (King Salmon, Grayling, Steelhead, or Dolly Varden platforms) or 

Trading Bay (Monopod platform) fields for injection at a platform(s), with optional feeder lines 

to nearby platforms (assuming the injection formation could assimilate the quantity of produced 

water generated); 2) when one of the McArthur River field’s platforms shuts down or when 

Monopod shuts down, require that one of the pipelines connecting these platforms to the Trading 

Bay Production Facility be used (if it is good repair) as a return line for produced water, 

followed by injection at the shut-in platform.

Scenario 2:

Utilize current geologic (including recent well) data and modern subsurface analysis techniques

and drill a Class II disposal well(s) near the Trading Bay Production Facility for produced 

water disposal. Given the studies pointing to problems with an injection well within three miles 

of the Trading Bay facility,37 however,such a well may need to be as much as five miles away.

Under Scenario 1, there may need to be zero or perhaps only one new major underwater pipeline 

constructed. Even with existing discharges from the Bruce platform continuing (EPA estimates 

this platform will cost $4.6 million to upgrade in 1995$38), more than 99% of current produced 

water discharges would be eliminated under Scenario 1. Thus, by eliminating up to 71% of the 

estimated capital costs for new pipelines plus the 15% of the estimated capital costs which are 

unnecessary due to changes in platform status since the industry/EPA zero discharge analysis,

 

37 Zero Discharge Analysis, op. cit., p. 2.30 ff.

38 Development Document, op. cit., p. A-39.
Dishonorable Discharges 20

86% of the estimated capital costs likely are unnecessary. As a result, EPA’s previous overall 

cost estimate may be as much as seven times as high as today’s conditions warrant:

100% / (100% - 86%) = 7.1 times too high an estimate

In its Development Document for the ELG, EPA states that potential scaling and well-plugging 

problems due to produced water injection in the seawater injection wells can be overcome with 

proper water treatment:

EPA reviewed the effects of produced water injection and concluded that downhole 

problems such as calcium carbonate scale precipitation and bacterial growth can be 

mitigated through the use of proper operating procedures. These procedures consist of 

pretreatment of the produced water for oil and grease and [total suspended solids], and 

continued chemical treatment of the injection stream. The proper usage of scale 

inhibitors can minimize scale deposits in the injection equipment, tubing flow lines, and 

injectors. The usage of biocides can minimize bacterial growth, thus reducing the 

formation of hydrogen sulfide. In addition to chemical treatment, annual well workovers 

can minimize scale build-up.39

As for Scenario 2, drilling one or more onshore disposal injection wells near the Trading Bay 

Production Facility would eliminate 96% of the produced water now discharged into Cook Inlet. 

While the 1994 industry-developed Zero Discharge Analysis study concluded that a disposal 

injection well in the vicinity of the Trading Bay Production Facility was not technically feasible 40

or cost effective, the study provided very limited documentation and raised a number of 

questions which need to be resolved by independent, EPA technical experts familiar with the 

region’s subsurface geology. Additionally, since the time of the study, Forest Oil has 

successfully drilled and operated a Class II disposal well nearby, drilled into the Kenai formation

approximately three miles from the Trading Bay Production Facility.

41

Savings from the zero discharge scenarios proposed above include the lack of need for the 

existing onshore oil/water separation operations now used to meet permit discharge requirements 

since produced water (which is contaminated with hydrocarbons) could be injected; and no need 

for a diffuser for the Trading Bay Production Facility discharge.42 Costs likely would include 

analysis of injection strata; pumping costs; modification of wastewater treatment operations prior 

 

39 Ibid., p. XI-39.

40 Zero Discharge Analysis, op. cit. p. 2.30 ff. The two technical concerns raised in the study were the potential for 

an over-pressurized formation which could result in undesirable vertical fractures (potentially contaminating a 

drinking water aquifer), and injection of produced water negatively impacting permeability of the formation’s clays. 

The authors acknowledge the uncertain nature of both concerns, however. In fact, numerous water injection wells 

exist 5-9 miles from Trading Bay Production Facility (data from Stephen Davies, AOGCC).

41 West McArthur River Unit 4 Class II disposal injection well.

42 See draft U.S. EPA Pemit No.: AKG-31-5000, section G.2.
Dishonorable Discharges 21

to injection; permitting of injection wells; and pipeline and injection well construction and/or 

reconditioning costs (as needed). 

UK Offshore Operators Association and member companies issued a zero discharge study in 

200543 where the authors found the average cost of converting seawater injection wells to 

produced water injection wells, not including new pipeline costs, was 5,000 British Pounds per 

ton of oil removed, or approximately $30 per gallon of oil not entering the marine environment.

44

 

This industry-derived figure is far less than calculated by EPA in its Development Document for 

the ELG; EPA’s estimate for platform modifications and well injection costs alone (i.e., not 

including engineering, insurance and other costs, as well as not including expensive new 

pipelines) based on designs submitted by industry was $36.4 million (1995$)45 for capital and 

operations & maintenance costs. Assuming 10 years of operation with 32,077 gallons of oil 

generated annually (see Table 5), the cost of platform-based injection would be at least $113 per 

gallon of oil (1995$) not entering the marine environment. Since 2005$ are worth over onefourth more than 1995$, EPA’s Development Document figure is likely to be low. EPA’s

cost/gallon figure is nearly four times higher than estimated by industry in the UK for injection 

of produced water into platform-based wells rather than seawater injection.

Table 8 lists all active Class II oil and gas waste injection wells in the Cook Inlet watershed, i.e.,

permitted wells designed to accept oil and gas-related wastewaters such as the produced water

generated by the Cook Inlet offshore platform wells. This table shows that all offshore platform 

operators have at least one offshore Class II injection well in operation during 2005 which can 

be used for produced water disposal. Currently, ConocoPhillips injects produced water from its 

Tyonek platform, Chevron/Unocal injects water from its Anna platform and, since late 2002, 

Forest Oil injects its produced water at the Osprey platform following onshore oil-water 

separation. Clearly, the industry already has started moving towards injection of produced water,

with each of these examples supporting the assertion that produced water injection is 

economically viable for Cook Inlet’s offshore platforms.

Because of:

• the high price of oil and state royalty reductions, 

• the lack of adequate technical evaluation by EPA to date of lower-cost, zero discharge 

scenarios,

• the number and ownership of usable Class II wells offshore, and 

• the fact that three of twelve (25%) operating Cook Inlet platforms already inject their 

produced water, 

 

43 Management of Produced Water on Offshore Oil Installations: A Comparative Assessment Using Flow Analysis –

Final Report, Policy Studies Institute for the UK Offshore Operators Association and its member companies, March 

2005. See http://www.psi.org.uk/docs/2005/UKOOA/ProducedWater-Workingpaper.pdf (last visited on May 9, 

2006).

44 Ibid., p. 50.

45 Development Document, op. cit., Table XI-18 (including only Platform Modification, Injection Equipment, 

Injection Well, and O & M costs), p. XI-41.
Dishonorable Discharges 22

EPA needs to update its economic analysis of zero discharge for Cook Inlet produced water to 

incorporate these factors.

Table 8

Active Class II Disposal Wells in the Cook Inlet Watershed46

Facility Owner/

Operator

Location Yr. 

Opened

Class II Injection Wells (for produced water)

Beaver Creek Unit 2 Marathon Beaver Creek Gas Field 1967

Beluga River Unit BRWD-1 ConocoPhillips Beluga Gas Field 1986

Deep Creek NNA 1 Chevron/Unocal Ninilchik area 2002

Granite Point ST 44-11 Chevron/Unocal Granite Point Field (offshore) 1968

Ivan River Unit 14-31 Chevron/Unocal Beluga area 1975

Kenai Unit 11-17 Marathon Kenai Gas Field 1982

Kenai Unit 24-7RD Marathon Kenai Gas Field 2005

Kenai Unit WD-1 Marathon Kenai Gas Field 1982

Middle Ground Shoal C44-14RD XTO Energy Middle Ground Shoal Field (offshore) 1978

North Cook Inlet Unit A-12 ConocoPhillips North Cook Inlet Gas Field (offshore) 1970

North Trading Bay S-05 Marathon Trading Bay Field (offshore) 1969

Redoubt Unit D1 Forest Oil Redoubt Shoal Field (offshore) 2001

Sterling Unit 43-09 Marathon Soldotna area 1963

Swanson River Unit 31-33WD Chevron/Unocal Kenai National Wildlife Refuge 1981

Swanson River Unit 32-33 WD Chevron/Unocal Kenai National Wildlife Refuge 1981

West McArthur River Unit 4 Forest Oil W. McArthur River Field 1998

Drilling economics: drilling wastes. In its 1996 final rule covering coastal oil and gas extraction 

point source discharges,47 EPA assumed that Cook Inlet drilling wastes would be disposed of in a 

landfill because it could not evaluate the availability of local grind and inject facilities. At the 

time, EPA knew of only a single landfill for drilling wastes within Cook Inlet (the Kustatan 

landfill), and it was unclear if all producers of drilling wastes would be able to use this landfill. 

Thus, EPA utilized land disposal costs that were far too high for current conditions in its 

economic analysis, i.e., EPA assumed that the drilling wastes would be sent to a landfill in

Oregon. 48 

Table 9 lists all active drilling waste management facilities in the Cook Inlet watershed. This 

table shows that – for drilling wastes – Chevron/Unocal and Marathon opened facilities to grind 

and inject drilling wastes since the 1999 Cook Inlet general discharge permit was issued. 

Additionally, XTO Energy sends its drilling wastes to a nearby Class II injection well the 

company operates49 (see Table 8). Moreover, since beginning oil production on the Osprey 

 

46 Class II well data from the Alaska Oil and Gas Conservation Commission.

47 See 61 Federal Register 66090 (December 16, 1996).

48 Ibid.

49 Personal communication with Brad Hill, XTO Energy, May 9, 2006.
Dishonorable Discharges 23

Table 9

Active Drilling Waste Management Facilities in the Cook Inlet Watershed50 

Facility Owner/

Operator

Location Yr. 

Opened

Landfills (for drilling wastes)

Beaver Creek Drilling Waste LF Marathon Beaver Creek Gas Field Early 

1980s

Beluga Central Drilling Waste LF ConocoPhillips Beluga Gas Field 1987

Envirotech Drilling Waste Treatment 

Facility and Inert Waste LF

Envirotech Tyonek area 2003

Envirotech Nikiski Drilling Waste 

Treatment Facility

Envirotech Nikiski 2004

Kustatan Ridge Drilling Waste LF Chevron/Unocal Trading Bay 1990

Swanson River Central Drilling Waste LF Chevron/Unocal Swanson River Oil and Gas 

Field

1986

West McArthur River Drilling Waste LF Forest Oil Trading Bay 1996

Grind & Inject Facilities (for drilling wastes)

Bruce Platform G & I Facility Chevron/Unocal Bruce Platform 2002

41-18 G & I Treatment Facility Marathon Kenai Gas Field 1999

platform and for its fifth and last exploratory well, Forest Oil has grinded and injected its drilling 

wastes.

51 The industry already has moved towards injection of drilling wastes, with each of these 

examples showing that grinding and injecting drilling wastes is economically viable for Cook 

Inlet’s offshore platforms.

 

Because of:

• the high price of oil and state royalty reductions, and 

• the construction of several new drilling waste management facilities in the area,

EPA needs to update its economic analysis of zero discharge for Cook Inlet drilling wastes to 

incorporate these factors.

Disposal technology: drilling wastes. EPA needs to re-evaluate its previous assessment that 

shows injection of drilling wastes to be technically infeasible in the Cook Inlet region given 

Forest Oil’s current practice with Osprey, Chevron/Unocal and Marathon’s recently-opened 

grind and inject facilities, and XTO Energy’s use of its Class II disposal well for drilling wastes.

 

50 Drilling waste management facility data from Bob Blankenburg, Alaska Department of Environmental 

Conservation.

51 Correspondence from Matt Rader, Alaska Department of Natural Resources to Lois Epstein, July 10, 2003.
Dishonorable Discharges 24

Recent technological developments to prevent injection well plugging mean it is more feasible 

than ever for Cook Inlet operators to inject drilling wastes.52 In its 1996 Development Document, 

EPA stated that the Agency was “unable to estimate the degree to which injection would be 

available in Cook Inlet.”

53 Given the technology and facility changes since, EPA clearly should 

re-examine this portion of its analysis in consultation with the AOGCC prior to issuance of a 

new general discharge permit.

Further, in 2003 Marathon stated it had reduced its exploration and production disposal costs for 

its Cook Inlet operations by using water-based drilling fluids and beneficial reuse of materials 

following water-washing, thus reducing the amount of its drilling wastes requiring Class II

disposal wells. These changes reduced Marathon’s disposal costs from $53.63 per barrel in 1995 

to $5.85 per barrel in the 2000-2003 time period.

54

Because:

• Cook Inlet operators now are injecting substantial amounts of Cook Inlet drilling wastes,

• improved drilling waste injection technologies are available throughout the Cook Inlet 

region, and 

• Marathon has developed innovative ways to reduce the amount of drilling wastes 

requiring injection, 

EPA – in conjunction with AOGCC – needs to update its technological analysis of zero 

discharge for Cook Inlet drilling wastes to incorporate these factors.

Oil impacts on salmon. National Marine Fisheries Service (NMFS) scientists who have done 

research following the 1989 Exxon Valdez crude oil spill found that crude oil constituents are 

significantly more toxic to pink salmon and herring than previously recognized. Instead of 

toxicities in the parts per million (ppm) range, NMFS researchers observed toxicities in the parts 

per billion (ppb) range for salmon and herring eggs. Hatchlings were deformed at levels of 

contaminants 1,000 times less than previously measured.55

Because salmon and herring eggs are adversely impacted by oil contamination at levels 1,000 

times less than previously recognized, EPA needs to update its scientific analysis of the impacts 

of offshore discharges on Cook Inlet marine organisms.

 

52 “Problem solver: Invention can handle rock disposal on Slope,” Sarana Schell, Anchorage Daily News, 

September 8, 2003.

53 Development Document, op. cit., p. VII-52.

54 Onshore Drilling Waste Management: Beneficial Reuse of Cuttings, Mark L. Susich (Marathon Oil Company) and 

Max W. Schwenne (OASIS Environmental, Inc.), undated.

55 See http://www.afsc.noaa.gov/abl/oilspill/fish.htm (last visited on April 17, 2006).
Dishonorable Discharges 25

Contamination in Cook Inlet subsistence foods. A 2003 EPA study56 shows that Cook Inlet 

seafoods contain varying levels of polycyclic aromatic hydrocarbons (chemicals from petroleum 

production) and metals (including mercury, cadmium, and lead, which are contained in oil

industry discharges) for seafood samples collected in 1997. The contaminants found were not –

and are not – at levels affecting fish populations, however, the contaminants can contribute to the 

adverse changes in seafood described by Tribal members and documented by EPA, described in 

Section II.

Importantly, the EPA study focused solely on the effects of individual pollutants, not the impacts 

of two or more pollutants simultaneously contained in fish tissues consumed by humans. A 

study of multiple pollutants acting in concert to produce biological impacts could help shed light 

on the adverse changes in seafood described by Tribal members. 

The presence of toxic contaminants in subsistence foods documented in EPA’s study, however, 

argues against allowing additional toxic discharges into Cook Inlet because of potential, adverse

cumulative impacts over time.

Recent collection of scientific and TEK data on Cook Inlet seafoods show levels of contamination 

that may be impairing seafood quality, so EPA should update its scientific analysis of the 

impacts of offshore discharges on Cook Inlet marine organisms.

Cook Inlet beluga whales. Cook Inlet’s beluga whale population was classified as “depleted” 

under the Marine Mammal Protection Act in 2000 by NMFS. Declining beluga whale 

populations are shown in Figure 7, based on data from NMFS.

57

 

56 Survey of Chemical Contaminants in Seafoods Collected in the Vicinity of Tyonek, Seldovia, Port Graham and 

Nanwalek in Cook Inlet, Alaska, U.S. Environmental Protection Agency, Region 10, EPA 910-R-01-003, December 

2003.

57 U.S. Marine Mammal Commission – Annual Report for 2004, Bethesda, MD, May 2005, p. 40 

(http://www.mmc.gov/reports/annual/pdf/2004annualreport.pdf, last visited on May 25, 2006).
Dishonorable Discharges 26

Figure 7

Abundance Estimates for Cook Inlet Beluga Whales, 1994-2004

As noted in Section II, EPA acknowledged in the past that Cook Inlet’s offshore oil and gas 

operations’ discharges may be contributing to the beluga whale’s decline. There have not been 

any studies to date looking at whether Cook Inlet belugas are metabolizing oil. One chemical 

discharged by Cook Inlet operations in particular however, copper, has been found in high

concentrations in Cook Inlet beluga whales58 – the toxicologic implications of high copper levels 

currently are unknown.

Based on NMFS’ data on the lack of growth in the number of the relatively few Cook Inlet 

beluga whales (see Figure 7), NMFS recently began a process to determine whether the Cook 

Inlet beluga whale should be classified as a “threatened” or “endangered” species under the 

federal Endangered Species Act.59

EPA – in conjunction with NMFS – needs to determine based on recent scientific data whether 

zero discharge is necessary to protect Cook Inlet’s “depleted” and potentially “threatened” or 

“endangered” beluga whale population.

 

58 Concentrations of polychlorinated biphenyls (PCB’s), chlorinated pesticides, and heavy metals and other 

elements in tissues of beluga, Delphinapterus leucas, from Cook Inlet, Alaska, Stephen A. Wise, Marine Fisheries 

Review, June 22, 2000.

59 See 71 Federal Register 14836 (March 24, 2006). This Federal Register notice from NMFS is a request for 

information relevant to reassessing the status of the Cook Inlet beluga whale. 
Dishonorable Discharges 27

VIII. Conclusion

EPA likely will issue a new discharge permit for Cook Inlet offshore oil and gas operations in 

2006. This new permit’s discharge specifications, including pollutant limits, monitoring 

frequency and techniques, and reporting requirements, are the primary means the federal 

government uses to keep Cook Inlet marine waters healthy. 

The aging, and consequently less productive nature, of nearly all Cook Inlet offshore oil and gas 

fields – illustrated in Figure 4 – means that additional platform closures are possible regardless 

of EPA’s actions on this permit. Bearing this in mind, Cook Inletkeeper makes the following 

key recommendation to EPA for consideration in general discharge permit renewal:

EPA needs to update the economic, technologic, and scientific information used in the 1999

general discharge permit process. EPA should re-evaluate its decision that zero discharge 

is not warranted in the renewed permit given known and projected, adverse, economic and 

environmental impacts on the Cook Inlet region should the discharges continue.
Dishonorable Discharges 28

Appendices
Dishonorable Discharges 29

Appendix 1

EPA’s Regulations for Coastal Oil and Gas Operations

Excerpted from 40 CFR 435.43:

----------------------------------------------------------------------------------------------------------------

 Stream Pollutant parameter BAT effluent limitations

----------------------------------------------------------------------------------------------------------------

Produced Water:

 (A) All coastal areas except Cook .................................... No discharge.

 Inlet.

 (B) Cook Inlet...................... Oil & Grease..................... The maximum for any one day

 shall not exceed 42 mg/l, and

 the 30-day average shall not

 exceed 29 mg/l.

Drilling Fluids, Drill Cuttings, and

 Dewatering Effluent: \1\

 (A) All coastal areas except Cook .................................... No discharge.

 Inlet.

 (B) Cook Inlet:.....................

 Water-based drilling fluids, drill SPP Toxicity....................... Minimum 96-hour LC5. of the SPP

 cuttings, and dewatering effluent. Toxicity Test \4\ shall be 3%

 by volume.

 Free oil............................ No discharge. \2\

 Diesel oil.......................... No discharge.

 Mercury............................. 1 mg/kg dry weight maximum in

 the stock barite.

 Cadmium............................. 3 mg/kg dry weight maximum in

 the stock barite.

 Non-aqueous drilling fluids and .................................... No discharge.

 dewatering effluent.

 Drill cuttings associated with non-.................................... No discharge. \5\

 aqueous drilling fluids.

Well Treatment, Workover and Completion

 Fluids:

 (A) All coastal areas except Cook ..................................... No discharge.

 Inlet.

 (B) Cook Inlet...................... Oil & Grease...................... The maximum for any one day

 shall not exceed 42 mg/l, and

 the 30-day average shall not

 exceed 29 mg/l.

Produced Sand........................... ..................................... No discharge.

Deck Drainage........................... Free Oil \3\......................... No discharge.

Domestic Waste.......................... Foam................................. No discharge.

----------------------------------------------------------------------------------------------------------------

 
Dishonorable Discharges 30

Appendix 1, continued

1\ BAT limitations for dewatering effluent are applicable prospectively, BAT limitations in this rule are not

 applicable to discharges of dewatering effluent from reserve pits which as of the effective date of this rule

 no longer receive drilling fluids and drill cuttings. Limitations on such discharges shall be determined by

 the NPDES permit issuing authority.

2\ As determined by the static sheen test (see appendix 1 to 40 CFR Part 435, subpart A).

3\ As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving

 water (visual sheen).

4\ As determined by the suspended particulate phase (SPP) toxicity test (see Appendix 2 of Subpart A of this

 part).

5\ When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see

 Appendix 1 of Subpart D of this part), Cook Inlet operators shall meet the same stock limitations (C16-C18

 internal olefin) and discharge limitations for drill cuttings associated with non-aqueous drilling fluids for

 operators in Offshore waters (see § 435.13) in order to discharge drill cuttings associated with non-

 aqueous drilling fluids.
Dishonorable Discharges 31

Appendix 2

Discharge Monitoring Reports for Produced Water from Cook Inlet’s

Offshore Platforms for 2005

Operator/Facility

Pr. H2O 

(mgd)

O/G 

(av)

O/G 

(max)

Cu 

(av)

Cu 

(max)

Hg 

(av)

Hg 

(max)

Zn 

(av)

Zn 

(max) Ag (av)

Ag 

(max) Pb (av)

Pb 

(max) As (av) As (max)

TAH 

(av)

TAH 

(max)

TAqH 

(av)

TAqH 

(max)

Chevron/Unocal

Anna Platform

12/5 0.000000

11/5 0.000000

10/5 0.000000

9/5 0.000000

8/5 0.000000

7/5 0.000000

6/5 0.000000

5/5 0.000000

4/5 0.000000

3/5 0.000000

2/5 0.000000

1/5 0.000000

Average

Bruce Platform

12/5 0.007277 14.0 16.0 154 154 2.0000 2.0000 15640 15640

11/5 0.000000

10/5 0.005229 20.0 20.0 631 631 3.0000 3.0000 15640 15640

9/5 0.009904 22.0 29.0 683 683 8.0000 8.0000 14890 14890

8/5 0.007509 13.0 15.0 274 274 2.0000 2.0000 16440 16440

7/5 0.007680 19.0 20.0 609 609 2.0000 2.0000 13720 13720

6/5 0.007212 17.0 21.0 994 994 1.0000 1.0000 14390 14390

5/5 0.007494 16.0 28.0 1270 1270 2.0000 2.0000 14790 14790

4/5 0.008013 15.0 18.0 1230 1230 1.0000 1.0000 17480 17480

3/5 0.007160 13.0 21.0 1870 1870 2.0000 2.0000 15660 15660

2/5 0.007306 19.0 23.0 23900 23900 2.0000 2.0000 15455 15455

1/5 0.009027 11.0 14.0 4710 4710 2.0000 2.0000 18870 18870

Average 0.006984 16.3 20.5 3617 3617 2.5000 2.5000 15734 15734

Granite Pt. Prod. Fac.

12/5 0.018627 19.0 26.0 7.00 7.00 0.2000 0.2000 2.000 2.000 13900 13900

11/5 0.019458 16.0 17.0 7.00 7.00 0.2000 0.2000 7.600 7.600 10740 10740

10/5 0.017983 14.0 19.0 84.00 84.00 0.2000 0.2000 11.000 11.000 12590 12590

9/5 0.019360 15.0 23.0 10.00 10.00 0.2000 0.2000 1.000 1.000 15200 15200

8/5 0.016867 20.0 28.0 11.00 11.00 0.2000 0.2000 3.700 3.700 13000 13000

7/5 0.016715 20.0 28.0 15.00 15.00 0.2000 0.2000 3.300 3.300 11630 11630
Dishonorable Discharges 32

Appendix 2, continued

Operator/Facility

Pr. H2O 

(mgd)

O/G 

(av)

O/G 

(max)

Cu 

(av)

Cu 

(max)

Hg 

(av)

Hg 

(max)

Zn 

(av)

Zn 

(max) Ag (av)

Ag 

(max) Pb (av)

Pb 

(max) As (av) As (max)

TAH 

(av)

TAH 

(max)

TAqH 

(av)

TAqH 

(max)

Granite Pt. Prod. Fac.

6/5 0.012440 21.0 28.0 10.00 10.00 0.2000 0.2000 1.610 1.610 14190 14190

5/5 0.015539 18.0 22.0 5.00 5.00 0.2000 0.2000 5.000 5.000 13840 14390

4/5 0.028644 18.0 18.0 - - - - - - - -

3/5 0.000000

2/5 0.000000

1/5 0.022662 20.0 22.0 5.00 5.00 0.4800 0.4800 2.000 2.000 13540 13540

Average 0.015691 18.1 23.1 17.11 17.11 0.2311 0.2311 4.134 4.134 13181 13242

Trading Bay Production. Fac.

12/5 4.254137 24.0 33.0 6.80 8.00 2.000 3.000 8280 9820 8374 9919

11/5 4.473566 21.0 28.0 37.30 93.00 4.000 9.000 12320 22920 12429 23023

10/5 4.402039 19.0 22.0 23.80 86.00 5.000 8.000 8388 9100 8505 9250

9/5 4.410095 20.0 24.0 27.70 50.00 1.000 2.000 7763 8620 7887 8760

8/5 4.437456 19.0 27.0 7.70 10.00 5.000 10.000 9083 9890 9177 9972

7/5 4.611490 16.0 22.0 6.70 8.00 2.000 3.000 7254 8160 7348 8280

6/5 4.481904 18.0 24.0 5.60 6.00 2.000 3.000 9520 14700 9644 14819

5/5 4.459338 17.0 24.0 5.00 5.00 2.000 2.000 10208 21020 10356 21174

4/5 4.380642 29.0 60.0 5.40 12.00 2.000 3.000 7788 8380 7928 8516

3/5 4.129437 18.0 24.0 4.80 7.00 2.000 2.000 7618 8080 7754 8237

2/5 4.236486 16.0 27.0 9.70 25.00 2.000 2.000 7382 8090 7818 8707

1/5 4.152223 18.0 26.0 4.80 8.00 2.000 3.000 9059 9760 9968 10816

Average 4.369068 19.6 28.4 12.11 26.50 2.583 4.167 8722 11545 8932 11789

XTO Energy

E. Foreland Trtmt. Fac.

12/5 0.218000 11.0 15.0 0.00 0.00 0.0000 0.0000 61.2000 61.2000 0.000 0.000 186.0000 186.0000 15340 15340 15340 15340

11/5 0.212000 8.0 9.0 0.00 0.00 0.0000 0.0000 0.0381 0.0381 0.000 0.000 0.0985 0.0985 15990 15990 16191 16191

10/5 0.177000 8.0 13.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.000 0.000 0.0000 0.0000 14260 14260 14438 14438

9/5 0.159000 11.0 12.0 7.54 7.54 0.0000 0.0000 11.8000 11.8000 1.080 1.080 163.0000 163.0000 14000 14000 14229 14229

8/5 0.137000 12.0 16.0 - - - - - - - - - - - - - -

7/5 0.141000 12.0 16.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.007 0.007 0.0400 0.0400 11530 11530 11702 11702

6/5 0.138000 14.0 20.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.000 0.000 0.0400 0.0400 11010 11010 11242 11242

5/5 0.138000 11.0 14.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.000 0.000 0.0400 0.0400 9821 9821 10151 10151

4/5 0.140000 15.0 23.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.003 0.003 0.0400 0.0400 17900 17900 18136 18136

3/5 0.148000 13.0 20.0 0.00 0.00 0.0000 0.0000 0.0016 0.0016 0.000 0.000 0.0362 0.0362 15790 15790 16026 16026

2/5 0.165000 6.0 7.0 0.01 0.01 0.0002 0.0002 0.1000 0.1000 0.001 0.001 0.0025 0.0025 14120 14120 14518 14518

1/5 0.157000 17.0 23.0 0.00 0.00 0.0000 0.0000 0.0000 0.0000 0.000 0.000 1.0000 1.0000 15780 15780 17254 17254

Average 0.160833 11.5 15.7 0.69 0.69 0.0000 0.0000 6.6491 6.6491 0.099 0.099 31.8452 31.8452 14140 14140 14475 14475
Dishonorable Discharges 33

Appendix 2, continued

Operator/Facility

Pr. H2O 

(mgd)

O/G 

(av)

O/G 

(max)

Cu 

(av)

Cu 

(max)

Hg 

(av)

Hg 

(max)

Zn 

(av)

Zn 

(max) Ag (av)

Ag 

(max) Pb (av)

Pb 

(max) As (av) As (max)

TAH 

(av)

TAH 

(max)

TAqH 

(av)

TAqH 

(max)

Phillips Petroleum

Tyonek A Platform

12/5 0.000000

11/5 0.000000

10/5 0.000000

9/5 0.000000

8/5 0.000000

7/5 0.000000

6/5 0.000000

5/5 0.000000

4/5 0.000000

3/5 0.000000

2/5 0.000000

1/5 0.000000

Average 0.000000