OCS Study 

MMS 99-0031 

History of Coastal Alabama 

Natural Gas Exploration and Development : 

Final Report 

AM U .S. Department of the Interior 

Minerals Management Service 

Gulf of Mexico OCS Region 
OCS Study 

MMS 99-0031 

History of Coastal Alabama 

Natural Gas Exploration and Development : 

Final Report 

Authors 

William W. Wade 

Jason R . Plater 

Jacqueline Q . Kelley 

Prepared under MMS Contract 

1435-01-96-CT-30829 

by 

Foster Associates, Inc. 

120 Montgomery Street, Suite 1776 

San Francisco, California 94104 

Published by 

U.S. Department of the Interior 

Minerals Management Service New Orleans 

Gulf of Mexico OCS Region April 1999 

DISCLAIMER 

This report was prepared under contract between the Minerals Management 

Service (MMS) and Foster Associates, Inc. This report has been technically 

reviewed by the MMS and approved for publication. Approval does not signify 

that the contents necessarily reflect the views and policies of the MMS, nor does 

mention of trade names or commercial products constitute endorsement or 

recommendation for use. It is, however, exempt from review and compliance with 

MMS editorial standards. 

REPORT AVAILABILITY 

Extra copies of the report may be obtained from the Public Information Office 

(Mail Stop 5034) at the following address : 

U.S. Department of the Interior 

Minerals Management Service 

Gulf of Mexico OCS Region 

Public Information Office (MS 5034) 

1201 Elmwood Park Boulevard 

New Orleans, Louisiana 70123-2394 

Telephone Number: (504) 736-2519 or 

1-800-200-GULF 

CITATION 

Suggested citation : 

Wade, W.W., J.R. Plater, and J.Q. Kelley . 1999. History of Coastal Alabama 

Natural Gas Exploration and Development, Final Report. OCS Study 

MMS 99-0031 . U.S. Dept. of the Interior, Minerals Management Service, 

Gulf of Mexico OCS Region, New Orleans, La. 189 pp. 

COVER PHOTOGRAPH 

Cover photo of Platform 113a at Fairway Field, Offshore Alabama, is courtesy of 

Shell Offshore, Inc., an affiliate of Shell Oil Company. 

L11 

ACKNOWLEDGMENTS 

Foster Associates received substantial support for this project. Many people 

provided data and factual information. The following people and organizations 

were especially helpful in supplying information and resources, and in some 

cases, reviewing subsections. Without their contributions, this report could not 

have been written. Errors that remain are the authors' . 

Nancy Cone Alabama Department of Conservation, Lands Division, 

Montgomery, AL 

Dave Bolin Alabama Oil and Gas Board, Tuscaloosa, AL 

Ralph Hellmich Alabama Oil and Gas Board, Tuscaloosa, AL 

Dean Peeler Alabama Petroleum Council, Montgomery, AL 

Gary Jacobs Chevron USA Production Company, New Orleans, LA 

David Duplantier Chevron USA Production Company, New Orleans, LA 

Clay Vaughn Exxon Company USA, New Orleans, LA 

Richard Harman Exxon Company USA, New Orleans, LA 

Robert Mink Geological Survey of Alabama, Tuscaloosa, AL 

Tom Joiner Tom Joiner and Associates, Tuscaloosa, AL 

Mike Prendergrast MMS, GOMR, New Orleans, LA 

Dave Marin MMS, GOMR, New Orleans, LA 

Carl F. Southern Mobil Oil Exploration and Producing Company, New 

Orleans, LA 

Mike Kimmett Mobil Oil Company, New Orleans, LA 

Woods W. Allen Murphy Exploration Company, New Orleans, LA 

Rick Mykitta Shell Yellowhammer Plant and Unit, Coden, Alabama 

Robert Davis Spirit Oil Company, (UNOCAL) Lafayette, LA 

Henry Caddell Thiry & Caddell, Mobile, AL 

v 

EXECUTIVE SUMMARY 

Mobil Oil Company leased four tracts in lower Mobile Bay from the State of Alabama on 

October 24, 1969, for $78,822 with a 1/6th royalty . Following issuance of the leases, Mobil 

filed an application to drill a well to 16,500 feet on July 9, 1970, with a Smackover target in 

mind. Mobil endured a lengthy delay before obtaining approval to proceed with an exploratory 

drilling program. The permit was not signed until June 21, 1978-after two federal and one 

state court appearances by Mobil and posting a $55 million bond. The first well was spudded 

in tract 76 on November 17, 1978-nine years after the award of leases . The nine year 

regulatory delay and ultimate success make one marvel about what Mobil geologists and 

management knew that induced Mobil to maintain a nine year regulatory siege. The leases were 

a bargain; the permits were not. 

The Attorney General of Alabama expressed great concern about the need to protect Mobile Bay 

and the Mississippi Sound from exploration and development of hydrocarbons . The conflict was 

ultimately resolved when Mobil proposed to drill with no discharges of any kind ; the zero 

discharge policy continues to govern Mobile Bay operations . The oyster fishery remains 

healthy . 

Norphlet Discovery at the Apex of the Energy Crisis 

Mobil's first well encountered natural gas and tested 12 .2 MMCFD at a total depth of 21,113 

feet November 28, 1979, having discovered Norphlet formation gas-a mile below the top of 

the Smackover formation . At the apex of the Carter Administration's Energy Crisis, Mobil had 

discovered a giant gas field in 14 feet of water in America's back yard-not in some remote, 

politically unstable country, harsh environment, or 2,000+ feet of water. The prospect of $9 

per MCF gas after the NGPA passed in 1978 and the Norphlet geology were extraordinarily 

exciting to petroleum industry professionals, who recognized the potential for discovery of other 

very large natural gas accumulations. 

By 1981, prices for Norphlet production covered by NGPA Section 107 deep gas ranged 

between $7 and $9 per MCF. Mobil's Norphlet gas reserves had become a treasure beyond 

anyone's expectation years earlier when they applied for the exploration permit . Unfortunately, 

the "gas bubble" dropped prices below $2 MCF by the time Mobil's, Shell's and Exxon's 

production ultimately came on line . Even finding markets became a challenge unforeseen when 

bidding and exploration occurred . 

Lease Sale Bonanza 

Exxon's bids at the 1981 State of Alabama Lease Sale and the 1982 Federal Lease Sale reveal 

that they bet heavily on Norphlet geology and high gas prices . Exxon submitted high bids of 

$255 .9 million for seven of the 13 tracts awarded by the State of Alabama following the 1981 

sale . The industry bid on 35 tracts, but the state rejected bids for 22 tracts : with nearly $450 

million in the bank-more than ever imagined-the state simply rejected bids below $2,000 an 

VII 
acre. "We've struck oil," a jubilant Governor Fob James quipped after the bonuses were 

counted . 

Between 1981 and 1984 Alabama leased tracts in state waters for bids totaling $800 million. 

MMS leased tracts in federal Mobile Bay OCS waters between 1982 and 1985 for bids totaling 

$562 million-$1 .36 billion combined. Governor James subsequently agreed with the legislature 

to set up a perpetual trust fund to ensure that the State of Alabama would continue to benefit 

from the interest on the bonus proceeds . At the end of FY 1996, the balance of Alabama's trust 

funds had grown to $1 .35 billion, having increased with the receipt of state royalty payments 

and the state's 27 percent share of 8(g) federal royalty payments from producing federal leases 

within eight miles of Alabama shoreline . 

Annual interest from the funds has averaged about $100 million since 1986 . The interest is 

transferred into the state's General Fund, where it amounts to between 11 - 12 percent of the 

state's General Fund budget. The trust funds and interest earnings will continue to grow so long 

as gas is produced from state and nearby federal waters . Substantial increases in state 

production and federal production in 8(g) waters during 1997 and 1998 will increase Alabama 

royalty collections . 

High Exploration Success Rate 

Seventeen Norphlet wells were spudded between 1981 and 1984, 13 of which became gas 

discoveries-an extraordinary accomplishment before 3D seismic. Besides Mobil's Mary Ann 

discovery, three state Norphlet discoveries and one federal Norphlet discovery subsequently 

became development projects based on discoveries before year end 1984. 

Through year end 1997, 75 Norphlet wells have been drilled in state and federal waters off 

Coastal Alabama-28 exploration, the balance delineation and development wells. These wells 

discovered 20 gas fields . Twenty Norphlet discoveries for 28 exploration wells represents a 71 

percent success ratio . All but three of discovered fields are producing gas. Mobil abandoned 

the West Dauphin Island Field as uneconomic . Exxon maintains its 867 Field lease and plans 

to produce it in 1998 . Chevron and its partners, Conoco and Murphy, have filed a Development 

and Production Plan to develop Destin Dome. Exxon has drilled the most wells, 20; Mobil has 

drilled 19. 

Mobil amended its original application to change the target from 16,500 to 21,500 

feet-changing the target from Smackover to Norphlet-two years after the original application. 

One wonders what would have happened if Mobil had drilled to Smackover at 16,500 feet in 

1970. Mobil's decision to drill below the Smackover to the Norphlet in their original exploration 

of Lower Mobile Bay has been a bonanza for State of Alabama coffers and American 

consumers, even if the prices received for the gas have been sharply lower than operators 

anticipated . The Coastal Alabama/Panhandle Florida Norphlet trend is one of the most 

important U. S . gas producing regions. 

Viii 
Norphlet Development Challenges 

Norphlet gas is a hot, sour, high pressure, corrosive mixture of methane, hydrogen sulfide, 

carbon dioxide, and free water. Dealing with it is difficult, dangerous and expensive . 

Development requires an integrated system involving specialized technologies for production, 

dehydration, pipelines and processing . Over $4 billion has been spent since the early 1980s 

installing these systems and drilling wells in addition to nearly $1 .5 billion in bonus payments 

to acquire the leases . Mobil, Eon, and Shell constructed sour gas processing plants onshore 

Mobile County. BP, first, and subsequently Union and Chevron, decided to process Norphlet 

gas on the platform, shipping market-quality gas to shore. Shell alone transports corrosive wet 

gas to shore for dehydration and processing at the Yellowhammer Plant, relying on a proprietary 

corrosion inhibitor compound Shell developed in lieu of water separation on the platform . 

The frontier nature of the Norphlet geology and the associated production engineering and 

technology challenges in many ways parallel the equally daunting but different challenges of 

Alaska's harsh, remote locale . Only a few of the major oil and gas companies could afford the 

billions of dollars and years of lead times necessary to bring the Norphlet into production. The 

Mary Ann Field began production in 1988-nine years from first discovery to first production. 

Shell's Fairway Field started up in late 1991 along with Mobil's federal 823 Field-ten years 

after the lease sales. BP brought its 821/109 Field online in early 1992 and Exxon started its 

three fields in late 1993-12 years after the 1981 lease sale . Beyond Mobil's initial regulatory 

siege, no significant regulatory delays factor into these development schedules. 

Chevron, Mobil and Spirit Energy (Union) have dominated 1996-1997 development activity . 

Mobil's well 95-5, on the southern edge of its tract adjoining Exxon's producing North Central 

Gulf Field, came online November 1996 and produced as much as 70 MMCFD for several 

months before reducing production to a sustainable 50 MMCFD. Mobil's newest producing well 

in the OCS is 869-3 ; this well produced 85 MMCFD in March 1997. These two wells represent 

a new generation of technology using large-diameter production tubing . 

Union and Chevron have been developing the eastern and western edges of the Mobile Bay OCS 

in their 820, 904 and 916 Units . Chevron took nine years from its first Norphlet discovery in 

OCS 861 in 1985 to first production in 1994. Union was able to bring its 904 Field to 

production in a little over five years, discovering the 904 Field in 1988 and starting production 

in 1993 . But the well (904-1) failed due to mechanical problems . The field only came back into 

production three years after the first well, in December 1996 with 904-2. 

Mechanical and completion problems have plagued most of the operators . Production has been 

reduced due to plugging, scaling and water intrusion. Total gas production would have been 

greater sooner but for these problems. At least 150 MMCFD of production was lost during 

1996 and 1997 from failed wells and wells that are only limping along in comparison to start-up 

rates . Keeping Norphlet wells producing at design rates is as difficult as finding the reservoirs 

four miles beneath the surface . 

Thumbnail company performance in the Norphlet is compared on Table X.1, which shows 

summary information on leasing, exploration success, and production success. The primary 

ix 
objective of this report is to assemble the data summarized on Table X.1 . The following 

observations can be drawn from the table, which does not take into account time values of 

money. 

" Exxon acquired two to three times the acreage of its early 80s bidding competitors, 

Mobil and Shell, and spent 2.4 to 5.0 times as much. 

" Exxon paid 26 percent more per acre than Mobil; 56 percent more than Shell . 

" Union and Chevron, entering the game after energy prices came down, acquired large 

acreage at greatly less per acre-$588 - $645 . This amounts to an average of $0.16 for 

each of Exxon's bonus dollars . 

" Acreage is only real estate ; discovered reserves matter . While recognizing the 

speculative nature of discovered reserves, Mobil has tallied 4.7 TCF to Exxon's 3 .7 TCF 

GIP. 

" Mobil's discovered reserves cost five cents per MCF, one-third of Eon's 15-cent 

reserves . Chevron has done second best at finding reserves-six cents per MCF. 

" Producing reserves creates cash flows and Mobil has produced the most gas at year end, 

1997-655 BCF, 24 percent more than Exxon . Mobil started production first, 1988, 

compared to Exxon, which only started production in 1993 . 

" Shell has produced the most gas per well drilled, 52 .9 BCF, twice Exxon's recovery per 

well . Company strategies toward size of the entire production complex importantly 

govern recovery per well differences among Exxon, Mobil and Shell . Problem wells and 

later start-ups govern Union's and Chevron's low recovery per well. 

" Chevron's and Union's 1995 start-ups partially account for the much lower cumulative 

production at year end 1997. Their seven P&A'd, shut-in and constrained producing 

wells mostly accounts for low cumulative production and average production per well. 

Keeping wells producing matters to Norphlet economics . 

" Shell's average bonus per produced MCF, $0.31, is lowest among the operators. Shell 

has produced 42 percent of discovered gas compared to high bonus cost per MCF 

producers, Exxon and Chevron, which have produced only 14 and 4 percent of the 

discovered GIP. 

" Remaining discovered reserves show that all but Shell will be producing Norphlet for 

many years into the future . Shell's Fairway Field R/P ranges from 4 to 8 years . 

x 
Table X.1 

Coastal Alabama Norphtet Production Indicators 

Company Bonus 

Payments 

Acreage 

Leased 

Discovered 

Reserves 

(GIP) 

Cumulative 

Production 

12/97 

Wells 

Drilled 

12/97 

Average 

Production 

Per Well 

Average 

Bonus per 

Acre 

Average 

Bonus per 

Reserves 

Average 

Bonus per 

Cum Prod. 

Remaining 

Discovered 

Reserves 

Unit of Measure ($1000) (1000) BCF BCF # (BC F) ($/acre) ($/MCF) ($/MCF) 

Exxon $573,040 147.6 3720 529.9 20 26.5 $3,882 $0.15 $1 .08 86% 

Mobil $242,493 78.6 4725 655.1 19 34.5 $3,086 $0.05 $0.37 86% 

Shell $116,114 46.7 880 370.1 7 52.9 $2,487 $0.13 $0.31 58% 

Union et al $72,219 111 .9 885 85 7 12.1 $645 $0.08 $0.85 90% 

Chevron et al $73,097 124.3 1185 41 .5 15 2.8 $588 $0.06 $1 .76 96% 

Notes: 

1 . Mobil includes Texaco tract 869. 

2. Shell includes BP tract 821 . 

3 . Chevron includes Tenneco tracts 863 and 864, and Texaco tract 872. 

3 . Discovered Reserves from Section 6 Appendix. 

4. Cumulative Production from Tables 6.13 & 6.14. 

5 . Bonus Payments & Acreage from Table 3.8 . 

6. Wells from Table 4.10. 

k 
Production and . Forecast 

Coastal Alabama natural gas production surpassed 1 BCFD for the first time in February 1997, 

and averaged 1 .02 BCFD for the year, or 371 BCF--18 percent more than 1996 production of 

864 MMCFD Norphlet gas. Forty Norphlet wells produced 1 .1 BCFD in February, 1998, in 

17 Norphlet fields in Coastal Alabama. The expansion of Chevron's 820 and 864 Fields by two 

producing wells (819-1 and 864-4), Exxon's start-up of its 114-3 well, Shell's workover of well 

113-3, and Mobil's drilling wells 823-AS and 914-4 will likely sharply increase production from 

Coastal Alabama fields by winter 1998-if no other wells encounter production problems. 

Four to six Norphlet new wells have been drilled annually in every year of the 1990s. Currently 

drilling and planned wells for 1998 - 2000 will maintain that average . Fifteen new Norphlet 

wells may add to production by year end 2000 . These include temporarily abandoned wells 

awaiting either start-up, completion or a production decision ; wells drilling at year end and 

planned to spud; and wells being worked-over to correct mechanical problems such as scaling . 

All of these wells are either field expansion wells, replacements for problem wells or wells to 

maintain production . 

Forthcoming and planned wells will increase utilization of the sour gas processing capacity . 

Operators used 72 percent of existing processing plant capacity of 1 .5 BCFD during fourth 

quarter, 1997 . Planned activities appear matched to capacity, assuming that gas from some 

fields is shifted to other operators' plants to make the best use of facilities and capacity . For 

instance, Chevron processes its higher than anticipated HZS we11863-3 in Shell's Yellowhammer 

plant; part of Exxon's gas is processed in Mobil's 823 plant. 

Coastal Alabama Norphlet and Miocene production will rise to 1 .4 BCFD by 2000. Destin 

Dome's production comes online after Mobile Bay production from discovered reserves reaches 

peak, thereby sustaining supplies to interstate markets in the 1 .4 - 1 .6 BCFD through 2005 . 

Combining both the Alabama state and federal OCS offshore production, the Alabama-Destin 

Dome production forecast reaches and sustains 1 .6 BCFD between 2002 - 2004, as shown on 

Figure X.1 . 

Cumulative production for the forecast totals about 9 TCF of Norphlet and Miocene gas by 

2015 . Total discovered gas in place is estimated to exceed 10 .5 TCF, with ultimate recovery 

unknown. No one yet has produced a Norphlet reservoir to economic limit. Shell's Fairway 

Field evidences significant decline. Shell, uniquely, produced the field at reservoir limits and 

has extracted a much larger percentage of gas in place than any other operator to date . The 

other producers are facilities-constrained, having designed capacities to maintain nearly flat 

production longer . 

Norphlet Overcame Every Risk 

The Norphlet history mirrors the history of the petroleum industry . From halcyon beginnings, 

a hand-full of major oil and gas producers overcame regulatory risk, geology risk, technology 

risk, market risk, and price risk to develop a major domestic energy province . Mobil watched 

gas prices shoot up from $0.25 per MCF in 1969 to $9 .00 when they spudded its first well, only 

to discover that its market had disappeared by 1987 when they were ready to produce. Chevron 

xii 
found very low cost reserves, but has been beset with problems keeping the wells producing as 

designed . While gas prices will never see forecast levels that influenced Exxon's initial 

excitement about Norphlet, Exxon, like other operators, has cut costs to match $2.00 gas and 

continues to develop the Norphlet. Geology, not being politically influenced, suggests that 

substantial Norphlet potential extends east of the Florida-Alabama state line . 

1,800 

1,600 

1,400 

1,200 

V 1,000 

800 

600 

400 

200 

0 

Figure X.1 . Mobile Bay Offshore Gas Production History and Forecast 

Source: Foster Associates, 1998. 

xiii 

00 O N ~ IC 00 O N '~ 110 00 O N 

00 O~ ON ON ON O1~ O O O O O ~ O~ ~ Ol~ O1~ O~ O~ O O O O O O O O 

N N N N N N N N 

" AL State Norphlet 0 Mobile OCS Norphlet 

D Destin Dome OCS EN Miocene 

TABLE OF CONTENTS 

List of Figures xix 

List of Tables xxi 

1.0 Mobil's Dogged Persistence Led to Norphlet Discovery 1 

1 .1 The 1970s Regulatory Delay 

1 .1 .1 Drilling Opposition Emerges 3 

1 .1 .2 Lawsuits, Negotiations and Settlement 4 

1 .2 Exploration Success and Continued Regulatory Initiatives 

1 .2.1 The Norphlet! A Remarkable Discovery 7 

1 .2.2 Lower Mobile Bay Field Drilling Begins 7 

1 .2.3 Illegal Discharges Threaten Continued 1982 Activity 10 

2.0 Norphlet Geology & Vintage 1980 Price Forecasts 13 

2.1 Norphlet Geology and Reserve/Resource Estimates 13 

2.1 .1 Coastal Alabama Petroleum Geology 14 

2.1 .2 Alabama Waters Norphlet Reserve Estimates-1987 16 

2.1 .3 Alabama and Federal Mobile OCS Reserve/Resource Estimates-1997 17 

2 .2 Gas Price Outlooks-Early 1980s-and Subsequent Market Developments 18 

2 .2 .1 NGPA: 1978 - 1982 20 

2 .2 .2 Price Stabilization : 1982 - 1986 23 

2 .2 .3 Restructuring and Emergent Commodity Pricing: 1986 - 1992 24 

2 .2 .4 Commodity Pricing and Growth of Efficient Markets : Post 1993 25 

3.0 Mobile Bay Leasing History 30 

3 .1 State Sale #1 - 1981 30 

3 .2 OCS Lease Sale 67 - 1982 36 

3 .3 State Lease Sale #2 - 1982 and OCS Sale 72 - 1983 39 

3 .4 State Lease Sale #3 and OCS Sale 81 - 1984 39 

3 .5 OCS Lease Sale 98 - 1985 44 

3 .6 State and Federal Coastal Alabama Sales: After 1985 45 

3 .7 Industry Leases: 1997 45 

3.8 Alabama's Stake in the Bonus and Royalty Payments 45 

3.8 .1 Trust Funds Preserve Money for the Future 54 

3.8 .2 Royalty Payments Have Added to Alabama Trust Fund 56 

xv 
TABLE OF CONTENTS 

4.0 Exploration Expands Beyond Mary Ann Field 58 

4.1 MOEPSI Mary Ann Delineation: 1981 & 1982 59 

4.2 Exploration and Delineation Drilling : 1983 - 1985 59 

4.2 .1 Exxon Steps Out in State Water: 1983 and 1984 61 

4.2.2 MOEPSI Finds the First Federal Field 61 

4.2.3 Chevron Pioneers the Western Norphlet Trend (2 

4.2.4 First Disappointments : 1984 & 1985 (2 

4.2.5 Summary: Exploration Successes: 1983 - 1985 63 

4.3 Exploration and Delineation Wells : 1985 - 1989 63 

4.3 .1 Exxon Delineates Discoveries 66 

4.3 .2 Texaco Finds Federal 869 and 872 Reservoirs 66 

4.3 .3 MOEPSI's 823 Delineation Efforts 66 

4.3 .4 BP Finds Federal Field 821 66 

4 .3 .5 Shell Finds Fairway Field ('7 

4 .3 .6 Chevron/Union Confirm Western Edge Norphlet Trend 67 

4 .3 .7 Chevron Hits Destin Dome ('7 

4.3 .8 Conoco/BP/Texaco Disappointments 68 

4.3 .9 Major Exploration Achievements/Disappointment: 1985 - 1989 68 

4.4 Exploration and Development: 1990 to 1993 70 

4.4 .1 Exxon & Shell Complete Projects and Initiate Production 72 

4 .4 .2 MOEPSI's Development Drilling : Mary Ann and 823 72 

4.4 .3 MOEPSI's Aloe Bay Discovery 72 

4.4 .4 Chevron and Union: Eastern and Western Mobile OCS Successes 73 

4.5 Exploration and Development: 1993 - 1997 74 

4.5 .1 Mobil and Exxon Add to Existing Production 76 

4 .5 .2 Murphy's First Norphlet Exploration Venture 76 

4 .5 .3 Union and Chevron Bring New Fields into Production 76 

4 .5 .4 Chevron's Destin Dome 7g 

4 .5 .5 Drilling and Planned Norphlet Wells : 1998 78 

4 .5 .6 Norphlet Summary: December, 1997 79 

4 .6 Miocene Exploration, Development and Transportation in Coastal Alabama State 

and Federal Waters 82 

4 .6 .1 Miocene Geology Overview and Drilling Summary 83 

4 .6 .2 Dauphin Island Gathering System 86 

4 .6 .3 Chandeleur Connection gg 

4 .6 .4 Production Start-Up: Miocene gg 

XVZ 
TABLE OF CONTENTS 

5.0 State Field Definitions from AOGB Dockets 92 

5 .1 Exxon Bon Secour Bay Field 92 

5 .2 Exxon North Central Gulf Field 92 

5 .3 Exxon Northwest Gulf Field 9'7 

5 .4 Shell Fairway Field 9 

5 .5 MOEPSI Aloe Bay Field 104 

5 .6 Lower Mobile Bay-Mary Ann Field: Revisited 109 

5 .7 State Geologic Structures Summary 110 

6.0 Development Projects and Production History 118 

6 .1 Development and Production of Mary Ann Field 118 

6 .1 .1 Safety and Environmental Considerations 119 

6 .1 .2 Special Materials to Handle Norphlet Gas 119 

6 .1 .3 Pipelines Used Special Techniques 120 

6 .1 .4 Norphlet HZS Variability and Mary Ann Gas Plant 121 

6 .1 .5 Mary Ann Sales and Transport Problems 121 

6 .1 .6 Mobil Mary Ann Field Production Profile 122 

6 .1 .7 Aloe Bay Field and Mary Ann Plant Expansion 124 

6 .1 .8 Federal 823 and 869 Fields 127 

6 .1 .9 Mobil Production Summary: 1997 130 

6 .2 Development and Production of Exxon Project 130 

6 .2 .1 Integrated Norphlet Production and Processing Facilities 131 

6 .2.2 Project Management and Quality Control 132 

6 .2.3 Exxon Project Production Profile 136 

6 .2.4 Exxon Production Summary: 1997 140 

6 .3 Development and Production of Shell's Fairway Field and Yellowhammer Project 140 

6 .3 .1 Development Avoided Shipping Channel and Civil War Artifacts 140 

6.3 .2 Shell Fairway Field Production History 143 

6.3 .3 Federal 821 Field and Shell Summary 143 

6.4 Development and Production of Union and Chevron Federal Projects 143 

6.4 .1 Western Mobile OCS 147 

6.4.2 Eastern Mobile OCS 152 

6.5 Production Facilities Summary 155 

6.5 .1 Producing Fields and Production Increases by End of 1998 155 

6.5 .2 Sour Gas Processing Capacity and Utilization 158 

6.5 .3 Gas Production Summary through 1997 159 

XVZZ 
TABLE OF CONTENTS 

6.5 .4 Remaining Recoverable Reserves by Field 162 

6.5 .5 Norphlet and Miocene Platforms 1(4 

6.5 .6 Forecast of Mobile Bay Gas Development & Production 164 

Appendix: Offshore Gas Forecast Reserve and Decline Rate Assumptions 173 

7.0 Bibliography 181 

7 .1 Cited Articles/Sources 181 

7 .2 Magazine Articles 185 

7 .3 Newspaper Articles lgg 

7 .4 Alabama Oil and Gas Board Dockets 189 

xviii 
LIST OF FIGURES 

X. l Mobile Bay Offshore Gas Production History and Forecast xiii 

1 .1 Mobile Bay Area Lease Activity Map, 1969-1981 2 

1 .2 Lower Mobile Bay Field 8 

1 .3 Lower Mobile Bay Field, Norphlet Structure 9 

2 .1 Epochs of U.S. Natural Gas Market Conditions 19 

2.2 World Oil Prices, 1972-1983 21 

2.3 Average Crude Oil Prices, 1982-1995 26 

2.4 Estimated Initial Year Contract Price for Gas Produced from Deep Well Gas 27 

2.5 So . (Off) LA Spot Prices 28 

3 .1 Mobile Bay Area Lease Activity Map, March 1981 31 

3 .2 State of Alabama Cumulative Lease Bids, 1981 35 

3 .3 Mobile Bay Area Lease Activity Map, January 1995 53 

4.1 Norphlet Structures Off Coastal Alabama 69 

4.2 Dauphin Island Gathering System 87 

4.3 Summary of Mobile Bay State and Federal Miocene Production 91 

5.1 Bon Secour Bay Field Limits 93 

5.2 Bon Secour Bay: Top of Structure 94 

5 .3 North Central Gulf Field Structure 95 

5 .4 Exxon Tract 114 Unit Expansion 98 

5 .5 Exxon Tract 114 Reservoir Structure 99 

5 .6 Exxon Tract 114 Reservoir Dunes 100 

5 .7 Exxon Northwest Gulf Structure 101 

5 .8 Shell Fairway Field Structure 102 

5 .9 Shell Fairway Field Dunes 103 

5 .10 Exxon & Mobil Common Structure 105 

5 .11 Mobil Aloe Bay Field Location 106 

5 .12 Mobil Aloe Bay Field 107 

5 .13 Mobil Aloe Bay Top Norphlet Structure 108 

5 .14 Map of Mary Ann Development 111 

5 .15 Mobil Mary Ann Field Base Norphlet Structure 112 

xix 
LIST OF FIGURES 

5 .16 Mary Ann Field Norphlet Gross Isopach 113 

5 .17 Mobil Mary Ann Cross Section-95-5 114 

5 .18 Alabama Norphlet Structure Map 115 

5 .19 Norphlet Play Map 117 

6 .1 Mary Ann and Aloe Bay Fields Gas Production per Day 123 

6.2 The Aloe Bay Pipeline Route 126 

6 .3 Mobile 823 and 869 Fields Norphlet Production 128 

6.4 Mobile Bay Area 133 

6 .5 Exxon Project Contractor Hours Worked Offshore 135 

6 .6 North Central Gulf/Mobile 827 Field Gas Production per Day 137 

6 .7 Northwest Gulf Field Gas Production per Day 138 

6 .8 Bon Secour Bay Field Gas Production per Day 139 

6 .9 Shell Fairway Field Gas Production per Day 144 

6 .10 State 109/Mobile 821 Field Gas Production per Day 146 

6 .11 Western Mobile OCS Union & Chevron Fields 148 

6 .12 Mobile 820, 861, 863/4 and 904 Fields Norphlet Production 150 

6 .13 Mobile 916 & 872 Units 153 

6 .14 Mobile 916, 961, and 872 Fields Norphlet Production 154 

6 .15 State and Federal Norphlet Production, Offshore Alabama (1996-1997) 156 

6 .16 Mobile Bay Offshore Gas Production History and Forecast 171 

xx 
LIST OF TABLES 

X.1 Coastal Alabama Norphlet Production Indicators xi 

1 .1 Mary Ann Field Well Results 10 

2 .1 Recoverable Sales Gas Reserves for Alabama Coastal Waters (1987) TCF 17 

2 .2 Recoverable Sales Gas Reserves for Alabama Coastal Waters (1997) TCF 18 

2 .3 DOE Oil and Gas Price Forecasts 22 

2 .4 Comparison of Forecasts of 1990 Oil and Gas Prices 1980-1982 24 

3 .1 Bids Received for the March 1981 State Lease Sale 32 

3 .2 Leased Blocks in the Federal OCS Water Near Alabama's State Coastal 

Waters through 1985 37 

3 .3 Bids Received for the September 1982 State Lease Sale 40 

3 .4 Bids Received for the August 1984 State Lease Sale 41 

3 .5 1981 & 1982 Rejected State of Alabama Bids Compared to 1984 Bids 43 

3 .6 Comparison of 1984 Bids in State Sale #3 44 

3 .7A Leased Blocks in State of Alabama Waters, 1988 - 1997 46 

3 .7B Leased Blocks in the Alabama OCS, 1988 - 1997 47 

3 .8 Coastal Alabama Leases : 1997 48 

3 .9 State of Alabama Oil and Gas Trust Fund Balances and Interest Earned 55 

3.10 Annual Royalty Payments to Alabama 57 

4.1 Norphlet Exploration and Delineation Wells: 1979 - 1985 58 

4.2 Mobile Bay Wells Norphlet Drilled 1979 - 1985 60 

4.3 Norphlet Exploration and Delineation Wells Drilled : 1985 - 1989 64 

4.4 Mobile Bay Norphlet Wells Spudded and Tested : 1985 - 1989 65 

4.5 Norphlet Exploration and Delineation Wells Drilled: 1990 - 1993 70 

4 .6 Mobile Bay Norphlet Wells Tested: 1990 - 1993 71 

4 .7 Norphlet Exploration and Delineation Wells Drilled : 1993 - 1997 74 

4 .8 Mobile Bay Norphlet Wells Spudded and Tested : 1993 - 1997 75 

4 .9 Mobile Bay Norphlet Wells Drilling/Planned to Spud : 1998 79 

4 .10 Mobile Bay State and Federal Norphlet Exploration Summary: 12/97 80 

4.11 Active Norphlet Fields - February, 1998 81 

4.12 Norphlet Wells Tested by Year 82 

4.13 Mobile Bay Miocene Wells Spudded : 1979-1997 84 

X,CI 
LIST OF TABLES 

4.14 Mobile Bay Miocene Gas Wells 85 

4.15 Summary of Mobile Bay State and Federal Miocene Production 89 

5 .1 Exxon Wells 115-1 & 114-1 Full Wellstream Analyses 96 

5 .2 Aloe Bay Well 75-1 Full Wellstream Analysis 109 

6.1 HZS Content of Producing Mary Ann Field Wells 121 

6.2 Mobil Mary Ann Plant Gas Per Day 1/96 - 12/97 125 

6.3 Mobil 823 Plant Gas Per Day 1/96 - 12/97 129 

6.4 HZS Content of Exxon's Wells 131 

6 .5 Exxon Plant Gas Per Day 1/96 - 12/97 141 

6 .6 Shell Gas Per Day 1/96 - 12/97 145 

6 .7 Union's and Chevron's Problem Wells 147 

6 .8 MO 904, 861, 820 & 863/4 Production Summary & Plans 151 

6 .9 MO 916 Processing 155 

6 .10 Norphlet Wells Added to Production during 1996-97 157 

6 .11 Norphlet Wells to Add to Potential Production by Year-end, 2000 158 

6 .12 Gas Processing Facilities in Mobile Bay Region 159 

6 .13 Summary of Gas Production in Mobile Bay State Waters by Reservoir and Field 160 

6 .14 Summary of Gas Production in Federal OCS Waters by Reservoir and Field 161 

6 .15 Remaining Recoverable Reserves by Field : Year End 1996 163 

6 .16 Offshore Structures Located in Alabama State Waters 165 

6 .17 Platforms and Caissons in Mobile OCS Waters 166 

6 .18 Mobile Bay Offshore Structure Installations by Year 168 

6 .19 Mobile Bay Offshore Gas Production Forecast Annual Average (1996 - 2010) 169 

Appendix : Post-1997 Well Startups Assumed in Mobile Bay Gas Production Forecast 173 

Appendix: Offshore Gas Forecast Reserve and Decline Rate Assumptions 174 

X.xll 
1.0 Mobil's Dogged Persistence Led to Norphlet Discovery 

Mobil Oil Company leased four tracts in lower Mobile Bay (76, 77, 94 & 95) from the State of 

Alabama on October 24, 1969 for a term of five years . Figure 1 .1 shows the location of 

Mobil's original tracts . Bonus payment for the tracts totaling 19,695 acres was $78,822 with a 

1/6th royalty . Following issuance of the leases, Mobil endured a lengthy delay before obtaining 

approval to proceed with an exploratory drilling program. The Alabama Oil and Gas Board 

(AOGB) permit was not signed until June 21, 1978-after two federal court appearances by 

Mobil, one in state court, and the posting of a $55 million bond. The first well was spudded 

in tract 76 on November 17, 1978-nine years later . 

Mobil was not the first lease holder of the tracks . During the SOs and 60s, tract 94 had been 

leased three times prior to Mobil, and tracts 95, 76 and 77 had been leased twice before. 

Pioneer Oil Company held the leases on the four tracts until they expired, July 1969 . None of 

the tracts had been drilled. Mobil was the first to seek a permit to drill them . The subsequent 

nine year regulatory delay and ultimate success makes one marvel about what Mobil geologists 

and management knew that induced Mobil to maintain what became a nine year regulatory siege. 

"Mobil's dogged pursuit of an exploration development project . . . [required] patience and an 

unswerving belief in a prospect," wrote the Oil and Gas Journal (OGJ) .' The leases were a 

bargain; the permits were not. 

1 .1 The 1970s Regulatory Delay 

Mobil filed an application with the AOGB for a permit to drill a well to 16,500 feet on one of 

the four tracts on July 9, 1970, with a Smackover target in mind. Mobil filed a second 

application for a permit to drill wells and erect structures with the Corps of Engineers (COE) 

on July 17 . Mobil's proposed exploration came soon after the unfortunate 1969 Santa Barbara 

California oil spill . Sensitivity to protecting offshore and estuarine resources and beaches was 

very high. "Regulators shifted into a new higher gear, feeling the scrutiny and pressure of 

environmental organizations ."' Governor Albert Brewer wrote to Mobil that he wanted "to 

make certain that Alabama has taken every precaution to prevent major oil spills in our waters. " 

He requested the Oil and Gas Board Supervisor to form a study group to "review Alabama's 

present rules, regulations and laws governing offshore drilling and production and make 

recommendations deemed necessary to assure the very best system will be utilized by this 

State. "' 

'Oil and Gas Journal, "Mobil has first Mobile Bay production in sight," June 30, 1986, p . 36. 

'Tom Joiner, "The Significance of Alabama's Offshore Natural Gas Production," Speech to AOGB 

50th Anniversary Reception, September 22, 1994 . 

3 Quoted materials from a timeline provided by Alabama Petroleum Council, February 1997 . 

1 
MOBILE MOBILE BAY AREA 

LEASE ACTIVITY MAP 

ODORE 

ousTaIAL 

BELLINGRATH 

GARDENS 

BAYOU 

LA BATRE 

as 

(*FAIRHOPE 

POINT CLEAR 

MOBILE BAY 

7 6 7 7 

DAVpHIN -9 4 9 5 

0 MILES 8 ` 

0 KILOMETERS 12 

FORT MORGAN PENINSULA 

5.t a f_e--

Federol 

Figure 1 .1 . Mobile Bay Area Lease Activity Map, 1969-1981 . 

Source : MOEPSI, 1997. 

2 
1 .1.1 Drilling Opposition Emerges 

The Governor's Offshore Study Committee composed of 17 individuals from AOGB staff, 

wildlife groups, industry, plus state and federal agencies was formed in late July 1970 and began 

work to formulate reasonable rules and regulations . The following "March 26, 1971, the 

Committee, under the direction of State Oil and Gas Supervisor P. E. LaMoreaux, presented its 

recommendations and proposed rules to Governor George Wallace . These were largely based 

on the Department of the Interior's rules for the OCS, and were called by observers "some of 

the toughest in the world. "4 Drafting the rules turned out to be the easy part; the challenge 

became getting them adopted. 

During the rest of 1971, various state and Mobil officials met to discuss the proposed rules; they 

were not adopted and no permit was issued . On October 13, 1971-two years after the original 

application-Mobil amended its original permit request to change the target from 16,500 to 

21,500 feet. Mobil changed the target from Smackover to Norphlet. Makes you wonder what 

would have happened if Mobil had drilled to Smackover at 16,500 feet in 1970. 

State Attorney General Bill Bailey emerged as the leader of opposition to drilling on January 

10, 1972 . Mr. Bailey asked the COE to deny the permit for proposed drilling in Mobile Bay. 

Relying on information provided to him by the Audubon Society,' Mr . Bailey told reporters 

that "the seafood, wildlife and recreational resources of Mobile Bay are at least as valuable to 

the people of Alabama as are possible oil reserves . . . that oil wells in Mobile Bay would pose 

an unacceptable risk to the ecology of the bay . . . that a runaway oil well would spell ecological 

disaster for Mobile Bay. "6 Attorney General Bailey urged the state to give Mobil its money 

back. 

Industry representatives, led by Mobil's Ed Bell, General Manager for Exploration and 

Production, who was responsible for Mobile Bay exploration, provided information on drilling 

safeguards in meetings. Mr . Bailey, in concert with Assistant Attorney General Henry Caddell, 

Chief of the Environmental Protection Division, turned a deaf ear on the industry's position . 

Mr. Bailey, having received numerous letters of support "should he decide to run for governor, " 

had tapped into a politically popular issue . The fight was drawn. The Mobile Press Register 

weighed-in with an editorial describing the 30-year old Bailey as "the young gentleman who 

already has gone far in the field of state politics, [now] climbing on the bandwagon occupied by 

"'Oil, Gas Board to Hold Proposed Rules Hearing," undated news clip, 1972 Alabama newspaper. 

'Henry Caddell, Letter to William Wade, March 17, 1997. 

"'Bay oil drilling block asked," Birmingham Post-Herald, January 11, 1972. 

3 
zealous environmentalists . "' But for Mobil's persistence, the Norphlet offshore may never have 

been discovered .' 

Hearings were set on the proposed rules by the AOGB on August 30-31, 1972 in Mobile . The 

Hearings became so extensive that they spilled-over to September 26 and October 24. AOGB 

spokesperson Boyd Bailey summarized the proposed rules emphasizing their "toughness . " Mr. 

Caddell, representing the Attorney General, stood firm on Mr. Baxley's "absolute prohibition" 

position and Mr. Ed Bell, representing Mobil, provided industry's position . The meetings 

introduced outspoken interveners to drilling from Fairhope, Save Our Bay, who preferred to be 

called the "SOBs . " Mrs. Myrt Jones, President of the Mobile Bay Audubon Society, became 

and remains an outspoken advocate for environmental positions . A professor of Coastal 

Geomorphology from the University of California at Santa Barbara, Dr. Norman Sanders, 

delivered lengthy testimony about spills in the Gulf of Mexico, claiming that "Red Adair would 

be on welfare . . . if oil well drilling technology was as well developed as the oil companies 

say ." 9 The decision to adopt the proposed rules was delayed and pushed up to the Governor. 

In early June 1972, Mobil, concerned that it was three years into its five year lease term, 

requested the Director of the Alabama Department of Conservation (DOC) to suspend Mobil's 

lease obligations from July 9, 1970 until the permits were issued . This was denied June 26, 

1972 on the basis of Attorney General Baxley's opinion that the "State does not have the 

authority to suspend these obligations at the present time. " House Speaker Sage Lyons 

commented that "the Attorney General has made a political decision that he does not feel that 

there should be any drilling in Alabama offshore, regardless of the standards of safety and 

regulations imposed. 

"lo 

1.1.2 Lawsuits, Negotiations and Settlement 

Mobil filed a lawsuit in federal court on August 9, 1972 (Mobil v. Claude Kelly, Director of 

the Department of Conservation, et. al., C.A . No. 7277-72-P, U. S . District Court, Southern 

District of Alabama) seeking (among other relied a decree that Mobil was entitled to have the 

primary terms of the leases extended by a period of time equal to the period from July 9, 1970 

until the AOGB and the COE issued valid permits. This was resolved in Mobil's favor on 

January 11, 1973 when the federal district court entered a decision that subsequently extended 

the period of the leases by four years and 76 days after the AOGB issued a valid permit. 

"'Bailey's Negative Stand on Oil," Mobile Press, January 12, 1972. 

'Tom Joiner, "The Significance of Alabama's Offshore Natural Gas Production," Speech to AOGB 

50th Anniversary Reception, September 22 1994. 

'Norman K . Sanders, " Hazards of Offshore Oil Drilling Operations," Before the Alabama Oil and 

Gas Board, Mobile, Alabama, October 24, 1972 . 

`AP News Analysis, Phil Oramous, July 13, 1972 . 

4 
AWIC Flip-Flops 

New rules and regulations governing drilling, producing and pipeline operations finally were 

adopted by the AOGB on January 26, 1973 . Mobil then initiated an Environmental Impact 

Report (EIR) which went to hearings two and a half years later, in October 1975 . The Alabama 

Water Improvement Commission (AWIC) voted in December to certify Mobil's project to drill 

one test well pursuant to Section 401 of the Federal Water Pollution Control Act. But this 

wasn't the final decision. 

The Attorney General's office argued to state agencies that the state should have a single 

cohesive position . Dr . Robert Boucher, one of the members of AWIC and Dean of the Medical 

School of the University of South Alabama, moved his home to Dauphin Island about 1975 and 

became concerned about evacuation of the island in the event of a gas blow-out. l' AWIC met 

again in February 1976 and rescinded the earlier certification to reconsider the permit because 

it feared pollution of Mobile Bay. Dr. Boucher's concerns and the Attorney General's position 

had an effect on AWIC's February 1976 reversal ." 

Mobil quickly filed an application for rehearing and a special hearing occurred in April 1976, 

at which Mobil presented extensive testimony . On May 28, AWIC affirmed its earlier decision 

to deny certification . Mobil went back to court. 

Back to Court 

The following month Mobil filed an amended complaint in its case in federal court seeking an 

injunction against AWIC . The Alabama Attorney General filed to contend that state court, not 

federal, had jurisdiction, and in December 1976, federal court declined to assert jurisdiction . 

Mobil re-filed in state court in January 1977 . The case appeared to be headed to an April 10, 

1977 trial date. 

Zero Discharge Policy-Settlement Agreement 

Settlement talks emerged . From January 1977 to March 1978, Mobil and AWIC engaged in 

settlement negotiations, which included Mrs. Myrt Jones of the Audubon Society. Great concern 

was expressed about the need to protect oyster beds on the southwest shore of Mobile Bay and 

in Mississippi Sound. Mobil proposed to drill with no discharges of any kind. This became the 

zero discharge policy that continues to govern Mobile Bay operations . Nothing goes overboard . 

No drill cuttings, mud or wastewater may be discharged in Mobile Bay. No galley waste, 

sanitary waste or cooling water waste may be discharged . A public hearing was held in 

February 1978 and shortly thereafter Mobil, AWIC and other parties signed a Settlement 

Agreement. A Mobil spokesperson described the rules at the time as "the most stringent ever 

"Henry Caddell March 17 letter to William Wade. 

'ZTelcon with Craig Kneisel, Assistant Attorney General, State of Alabama, April 15, 1997. Mr. 

Kneisel was General Counsel for AWIC at the time and worked with Mr . Caddell from the A.G .'s office . 

5 
adopted by any state-much stiffer than federal rules .,' '13 The COE permit was issued on May 

18, 1978; Mr. Tom Joiner, Supervisor of AOGB, signed its permit on June 21, 1978 . Mobil 

filed for a permit to drill four appraisal wells in Mobile Bay on October 26, and spudded Well 

76-1 on November 17, 1978, about one mile northeast of Dauphin Island . Mobil Oil 

Exploration and Production Southeast, Inc (MOEPSI) was formed December 12, 1978 to take 

charge of the activity under Mr. Ken Keller, its first president. Mr. Keller had replaced Mr. 

Ed Bell as General Manager in 1976. 

Two key differences set the Settlement Agreement apart from the AOGB 1973-adopted 

regulations : 

" The zero discharge policy, and 

" The $55 million bond that MOEPSI was required to assure . 

Mr . Caddell, who worked closely with Mr. Baxley to urge the safeguards in place today, wrote 

in March 1997, "There has been a very extensive amount of drilling . I am convinced that, if 

they had been allowed to discharge drilling fluids, the quality of our estuary and waters would 

be quite different today-with more degradation."" Hart's Oil and Gas World claimed that the 

gas industry has had less impact on the waters of Mobile Bay than a small power boat." The 

oyster fishery remains healthy. 

1 .2 Exploration Success and Continued Regulatory Initiatives 

A month after Well 76-1 was spudded, the COE determined that an EIR for the appraisal 

program would be required . Because of the delays in the exploration permit, MOEPSI initiated 

the EIR right away. This led to extensive development of environmental information over 1979 

and 1980, and culminated with a Draft EIR on August 15, 1980. Mobil's first well encountered 

natural gas and was tested at a total depth of 21,113 feet November 28, 1979, having discovered 

the Norphlet formation gas-a mile below the original Smackover target . 

Numerous problems beset MOEPSI's drilling including Hurricane Frederic whose eye passed 

directly over the drilling rig without inflicting damage before it moved on and knocked out the 

bridge to Dauphin Island a mile to the west of the drilling rig. The final cost of the well totalled 

$20 million-$13 million above Mobil's 1978 cost estimate . Ultimately drilling wells to four 

miles beneath the surface of the earth has proven to be difficult and costly . Twenty million 

dollars remains the benchmark in 1997 for drilling a Norphlet well . Some have cost twice that . 

'30GJ, "Mobile Bay Permit may come this fall," April 23, 1978, p. 34. 

"Henry Caddell March 17 letter to William Wade. 

"Harts Oil and Gas World, "Mobile Bay operators bring more gas into production at high rates, high 

costs," April, 1995, p . 28-29 . 

6 
1 .2 .1 The Norphlet! A Remarkable Discovery 

The subsequently named Lower Mobile Bay-Mary Ann Field was the first offshore Jurassic 

discovery in the northern Gulf of Mexico, significantly extending the area of known onshore 

Jurassic production at Hatter's Pond, 50 miles north of the Mary Ann field, and the Flomaton 

field, 40 miles northeast of tract 76 in Escambia County, Alabama . The productive interval 

tested November 28 - 29, 1979 revealed 283 feet of net pay with as much as 20 percent porosity 

and 1 milli-darcy of permeability . Mobil Chief Geologist Roy Roadifer later termed the 

discovery "remarkable" at a 1986 AAPG meeting in Atlanta . 

16 John McCaslin, Exploration 

Editor of the OGJ, described the net pay as "awesome," with 6,000 acres of productive 

formation and average pay thickness of 100 feet. 

17 The gas tested 5 percent carbon dioxide and 

9 percent hydrogen sulfide-sour, corrosive gas-thereby creating a significant challenge in the 

development plan. 

MOEPSI spent 1980 working on the EIR and ocean dumping permit issues while further 

exploration stood still. On November 7, 1980 MOEPSI petitioned the AOGB to name their 

discovered field the Lower Mobile Bay Field, define the Norphlet Gas Pool and establish Special 

Field Rules ." Figures 1 .2 and 1 .3 were submitted as exhibits to show the location of the field 

and the contours of the Norphlet structure . Mr . F. T. Musson and Mr. Joseph B. Fryer 

appeared as MOEPSI's witnesses presented by attorneys Dewitt Reams and Bob Jorden. Mr . 

Fryer identified himself as a geologist who had worked on the project since 1969 ; he must have 

been the person who believed in the potential of the offshore Jurassic . Figure 1 .2 shows the 

location of the discovery well in the southeast area of tract 76 along with the planned locations 

of two appraisal wells in tract 94, and one each in tracts 77 and 95 . A single norphlet gas pool 

underlay all four of the tracts . This is visible on Figure 1 .3, a seismic structure map that shows 

the discovery well virtually in the center of the reservoir . AOGB Order 80-209 named and 

defined the Lower Mobile Bay Field. 

1.2 .2 Lower Mobile Bay Field Drilling Begins 

Following final approvals from the Corps and AOGB in late January 1981, Rowan 004 and 

Penrod 65 drilling rigs moved into Mobile Bay. Mobil spudded two appraisal wells on tracts 94 

and 95 in February 1981 and constructed an operations base in Bayou La Batre . Following 

another year of environmental research, the Mobile Bay Norphlet gas play finally gained 

momentum. 

MOEPSI's two appraisal wells both tested Norphlet gas in the range of 21,000 feet : 94-2 on 

May 27, 1982 ; 95-1 on August 24, 1982 . (Well 94-1 was permitted twice, but never drilled. 

'60GJ, "Mobile has first Mobile Bay Production in sight," June 30, 1986, p.36. 

"OGJ, "Mobil eyes new Norphlet test off Alabama," Jan 11 1988, p. 76. 

'$AOGB Docket 11-7-808 . MOEPSI subsequently renamed the field Lower Mobile Bay-Mary Ann 

field in 1983, Docket 6-30-83, after the wife of Raleigh Warner, CEO Mobil Oil at the time . This is the 

only Alabama field that is not named after a geographic location. 

7 
00 61 62 ~ I 63 64 

I 

~---- Moei~-- - 76 ~~ MOBIL--- 771 78 I S.L .347 I 

I 

~ SL 349 

, O l 

V 

~ I 

1 I I I 

OAUPN/N /SL AND ~ I 

~ 

~ 

FpqT GA/NES l 

jj, 

--= ~ -0~9 Z =94 1- - - `~ ~~===95 96 

~ / 

i 

FORT MOFGAN ; T 0 8,240' 

9 

Z 

~S~9y 

O 

I 

I 

I 

/// 

I 

I I /~l 

- J ~. - -i 

112 113 114 115 

DOCKET No . 11-7-808 EXHIBIT No. Z LEGEND 

ISCOVERY WELL 

0 MILES 2 

PROPOSED APPRAISAL WELL 

0 KILOMETERS 4 AFIELD OUTLINE 

--- DRILLING & PRODUCING UNIT OUTLINE 

Figure 1 .2 . Lower Mobile Bay Field . 
61 62 ~ ~ 63 64 

75 ""I) t4' 8'~ 76 R~ S, +ap 77 . 78 

-41 

20 800 

`~f'f0 

"" 4fiPH~ti SC ENO ~ I 

(,4Ives0~~ I LL 

93 ~°

0 414 

~Mi'"

B4~ 2 94 95 96 

v -.21

.000 `~ ` fop, w~~q ;ati~ , ~ h . 4 

~` v y I '`1 , oo 

a2 ~ , 

,( . .i 

~. 

n 

T 

I I 2 113 115 

I LEGEND 

DOCKET No. 11-7-808 EXHIBIT No. 2 ISCOVERY WELL. 

NORPHLET STRUCTURE PROPOSED APPRAISAL WELL 

AFIELD OUTLINE CONTOUR INTERVAL 100' DRILLING & PRODUCING UNIT OUTLINE 

o Z ml I DRILLING & PRODUCING UNIT NUMBER 

Figure 1 .3 . Lower Mobile Bay Field, Norphlet Structure. 

%10 1 
94-2 was the first well drilled .) These wells required 15 and 18 months respectively to drill . 

Well 94-2 was drilled from the same surface location as the discovery well but was deviated to 

a bottom-hole location 4,600 south in tract 94. The deviation avoided the Mobile Bay shipping 

channel and eliminated a surface structure . The third well, 95-1, was drilled half a mile north 

of Fort Morgan. A fourth appraisal well, 77-1, about 2 miles north of Fort Morgan, was 

spudded July 17, 1982 . This subsequently tested gas on March 28, 1983 . Shallow well 95-2 

into Miocene was successful on October 11, 1982 . This was used as fuel for the subsequent 

platform . Well 76-2 quickly followed MOEPSI's successful Miocene well, spudding January 10, 

1983 . Well 77-2, the sixth Norphlet well, spudded on March 12, 1984. Both 76-2 and 77-2 

were cored but not tested for gas until several years later. Mobil actually drilled six successful 

Norphlet wells producing between 10 and 26 MMCFD of gas between November 1978 and mid1984-a remarkable exploration achievement in previously unexplored offshore Jurassic 

Norphlet. Table 1 .1 lists the wells drilled to delineate the Mary Ann Field. 

Table 1 .1 

Mary Ann Field Well Results 

Well Spud Date Test Date Depth Test Results 

76-1 11/17/78 11/28/79 21,113 12.2 MMCFD 

94-2 2/27/81 5/27/82 21,859 15 .5 MMCFD 

95-1 2/1/81 8/24/82 20,935 10.5 MMCFD 

77-1 7/17/82 3/28/83 20,984 19.4 MMCFD 

95-2 9/18/82 10/11/82 2,750 4 .0 MMCFD 

(Miocene) 

76-2 1/10/83 6/29/88 20,931 gas 

77-2 3/12/84 8/13/87 21,710 gas 

Source: AOGB 

1.2.3 Illegal Discharges Threaten Continued 1982 Activity 

During the course of drilling wells 94-2 and 95-1, contractors under MOEPSI's direct control 

were discovered in June 1982 discharging into Mobile Bay at night what was subsequently 

revealed to be water that had accumulated in the drilling mud barge .'9 This violated the "no 

discharge" policy . The Mobile Bay Venture Manager, Mr. F. D. Musson, received a phone call 

Friday, June 18 from an attorney, Mr. Jimmy L.angford, who passed along an anonymous 

message that "a Mobil rig in Mobile Bay was observed to have turned its lights off at night and 

dumped liquid waste in the Bay." Mobil immediately looked into the allegation. "Early on 

Tuesday morning, June 29, " Mr. Ken Keller, President of MOEPSI, subsequently testified, 

`90GJ, "Discharges cloud action off Alabama," September 6, 1982, p . 56. 

10 
" . . . I received verbal reports that I can best describe as shocking . . . . On at least one occasion 

in April 1982 water had been pumped into the Bay from the hopper barge which is based to 

collect the rig liquids and solids . We immediately on the same day reported the matter to [all 

appropriate state and federal agencies] . . . and issued a press release on July 1 . "Z° 

Mr. Charles Gradick, the Attorney General who replaced Mr. Bill Baxley, AWIC, the U. S. 

Coast Guard, the AOGB, and Mobil itself immediately initiated investigations, along with the 

Audubon Society . Mobil retained its Mobile law firm Reams, Woods, Vollmer, et al to conduct 

an independent investigation . The firm brought in a retired FBI investigator, Mr. James A. 

Day, to interview drilling personnel. 

MOEPSI President Ken Keller appeared before AWIC on July 12, 1982 and AOGB on July 30, 

1982 and acknowledged that the discharges were not accidental and that they had occurred in 

the Bay "intermittently over a period of time between spring 1981 and June 1982 . . . generally 

at nights to avoid detection. " The exact nature and quantify of the fluids was unknown, except 

that only water was intended to be released by the persons responsible for the improper 

discharge . Mr. Day's investigation revealed that motivation was apparently a "few individuals 

. . . trying to save tune and money by sending less waste to the approved disposal sites. " Mr. 

Keller stated that strict compliance was the company policy and that "policy and directives [had] 

been widely disseminated through all levels of the Mobil organization . . . . Virtually to the man 

. . . the [interviewed personnel] were well aware of the no discharge requirements ." 2' Mr. 

Reams testified that the senior MOEPSI person knowledgeable was the drilling supervisor ." 

The most likely reason given by Mr. Keller for why the dumping occurred was that the drilling 

personnel, having worked mostly in the Gulf of Mexico, had never encountered such stringent 

requirements and simply ignored them because they believed them "simply unnecessary ." 

MOEPSI agreed to pay a fine of $2 .0 million plus clean-up costs, which exceeded $500,000. 

OGJ wrote that "Mobil fired 15 employees and disciplined eight others who were involved in 

Mobile Bay drilling operations . "23 A MOEPSI management level person was directed to 

personally supervise drilling activities on the rig . 

Swift actions by both the agencies and Mobil eliminated the problem, cleaned up the waters, and 

punished the guilty . MOEPSI was awaiting a COE decision on its production phase application 

at the time, which was delayed but subsequently issued . Exploration and development, which 

might otherwise have been stopped, resumed. Mobil executives today recollect that "Mr. 

Keller's swift action and emphatic response had a positive effect" in demonstrating to state 

'Testimony of Mr. Kenneth Keller to Special Session of AOGB, July 30, 1982, p. 8 - 10 . 

Z'Testimony of Mr. Kenneth Keller to Special Session of AOGB, July 30, 1982, p. 10, 15 - 16. 

'Testimony of Mr. Dewitt Reams to Special Session of AOGB, July 30, 1982, p . 45 . 

13OGJ, "Mobil to pay for Mobile Bay discharges," October 4, 1982, p . 46. Mobil confirmed that 

17, in fact, were fired. Mobil Public Affairs telcon April 29, 1997. 

11 
regulators that they fully intended to operate within the "no discharge" and all other 

restrictions .' 

The one black mark on the exploration effort had an inoculation effect on the industry . The 

natural gas industry has coexisted peacefully with the other resource-based industries in Coastal 

Alabama, including the booming tourism industry . Experiences among the other Coastal 

Alabama resource industries are described in Foster Associates "Case Studies" within "Social 

and Economic Consequences of Onshore OCS-Related Activities in Coastal Alabama, Economic 

Baseline of the Alabama Coastal Region," Draft March 1998 . 

Z4Telcon with Mike Kimmitt, Mobil Public Affairs, April 29, 1997 . 

12 
2.0 Norphlet Geology & Vintage 1980 Price Forecasts 

At perhaps the apex of the Carter Administration's Energy Crisis, MOEPSI had discovered a 

giant gas field in 14 feet of water in America's back yard-not in some remote, politically 

unstable country, harsh environment, or 2,000+ feet deep water . Both the prospect of $9 .00 

per MCF gas and the Norphlet geology that MOEPSI's 1979 discovery in Mobile Bay confirmed 

were extraordinarily exciting to petroleum industry professionals . Even with 2D seismic 

technology, explorationists other than MOEPSI's recognized immediately the potential for 

discovery of other very large natural gas reservoirs. 

The bidding and bonuses seen in the 1981 State of Alabama and 1982 federal OCS Lease Sales 

make sense with an understanding of industry confidence about the hydrocarbon potential and 

the price outlook. Section 2.1 discusses the regional geologic setting that MOEPSI had 

discovered . Section 2.2 discusses gas price and gas market outlooks vintage 1980 - 1984. 

2.1 Norphlet Geology and Reserve/Resource Estimates 

The discovery of the Flomaton Field at 15,500 feet in Escambia County in 1968 marked 

Alabama's first discovered hydrocarbons from the Jurassic age Norphlet Formation, and 

extended the eastern limit of Jurassic production about 75 miles southeast of prior discoveries 

in Choctaw and Clarke Counties, Alabama. This discovery led to a period of intense leasing 

and drilling that resulted in the discovery of the Jay and Little Escambia Creek Fields onshore 

the Florida Panhandle.' Deep oil and gas exploration gained momentum in late 1974 when 

the large Hatter's Pond and Chunchula Smackover-Norphlet Fields were discovered at 18,120 

feet in Mobile County, about 40 miles north of MOEPSI's ultimate discovery . 

MOEPSI's 1979 deep Norphlet discovery, which is similar to the Flomaton reservoir in that the 

gas is trapped in a faulted salt-pillow structure overlain by tight, nonproductive Smackover,26 

confirmed what geologists had believed. Tom Joiner, Chief Geologist of the State of Alabama, 

wrote in 1980 that the "flank of the Wiggins-Conecuh trend and updip Smackover grainstones 

associated with salt structures are excellent areas for petroleum exploration in Southwest 

Alabama. " The Wiggins arch sits between the Hatter's Pond Field and the Lower Mobile Bay 

Field. Joiner summed it up in 1980 with these words: "Discovery of the Lower Mobile Bay 

Field opened up a potentially very large hydrocarbon province . "z' 

'OGJ, "Leasing, drilling state and federal Alabama waters," April 22, 1985, p. 134 - 135 . 

'Marzano, Michael S ., Glenn M. Pense and Peter Andronaco, "A look at the Norphlet in Mary Ann 

field," OGJ, March 6, 1989, p . 55 . 

z'Joiner, Thomas, Markel Wyatt and John H. Massingill, "A Discussion of Oil and Gas Development 

in Southwest Alabama," State Oil and Gas Board, Report 6, 1980 . 

13 
2.1.1 Coastal Alabama Petroleum Geology 

More than 135 million years ago, during Jurassic times, Mobile Bay and Southwest Alabama 

was a desert adjacent to a shallow sea. The Appalachians, a very old range, were much higher 

than today . This mountain range was heavily eroded in Jurassic times and became distributed 

in the present day Coastal Alabama area as an extensive sand body--the Norphlet. Streams and 

rivers from the Appalachian mountains carried sediments from the eroding Appalachians far out 

into this desert . Prevailing winds from the north reworked and redeposited these sands forming 

the sand dunes and different sorts of sandstones found in the Norphlet . In addition to the eolian 

dunes, Norphlet deposits include fluvial, interdune (wadi) and marine sediments in the areas 

offshore Mississippi, Alabama, and Florida . Dramatically thicker Norphlet deposits occur in 

the Mobile Bay area and offshore the Florida Panhandle." Chevron Senior (Norphlet) 

Geologist Gary Jacobs described "the ancient Norphlet desert [as] similar to today's Namibia 

along the west coast of Africa [with] towering sand dunes two- to four-hundred feed high, with 

much sand between the individual dunes . It was an entire eolian depositional system or "sand 

sea," not individual dunes accumulating regionally."" 

These sand dune deposits have been discovered four miles deep as the Norphlet Formation. The 

eolian Norphlet Formation is found in a narrow band along the Mississippi, Alabama and Florida 

Panhandle coast. Norphlet reservoirs are characterized as wind-deposited dunes and interdune 

sandstones, which vary in thickness to more than 1000 feet . Productive Norphlet gas reservoirs 

can be extensive and thick. Gas pays can exceed 280 feet in thickness . 

State of Alabama Geologist Ernest Mancini, with colleagues Robert Mink, Bennett Bearden and 

Richard Wilkerson wrote the first definitive article on the Norphlet geology .3° They called the 

hydrocarbon potential of the Coastal Alabama area "excellent, with structural traps primarily 

involving salt anticlines, faulted salt anticlines and extensional fault traps associated with salt 

movement. Reservoir rocks consist primarily of quartz-rich eolian, wadi, and marine sandstones 

having principally secondary . . . porosity with some intergranular porosity ."" The desert 

plain extends west to Mississippi but the area with perhaps the maximum dune development is 

Coastal Alabama." In 1988, they described the Norphlet as "part of a deep Jurassic natural 

gas trend that extends across southern Mississippi and Alabama into the Gulf of Mexico . . . . 

"Nat Turner and Gordon Fiedler, "Geophysical Interpretation of Jurassic Structures and Norphlet 

Deposition, Alabama State and Federal Waters," Seismic 4, 1985, p . 355 - 357 . 

29Gary Jacobs letter to Wade, July 23, 1997. 

3°Mancini, Ernest, Robert M. Mink, Bennett Bearden and Richard Wilkerson, "Norphlet Formation 

(Upper Jurassic) of Southwestern and Offshore Alabama: Environments of Deposition and Petroleum 

Geology," AAPG Bulletin, 69, 6, June, 1985, 881-898. 

3'Mancini, Mink, et al, 1985, p. 896. 

32Mancini, Mink et al, 1985, p . 891 . 

14 
The trend should continue from Alabama coastal waters . . . into the Pensacola and Destin 

Dome areas."" 

The offshore Norphlet fields mostly produce from the eolian dune facies . The porosity of the 

sands tends to be higher in the federal fields, which average 14 percent, than in the state fields, 

which average 12 percent. 

14 Another important facies in the offshore Norphlet is the presence 

of marine reworked sands at the top of the formation. This very low porosity zone is not 

considered productive and constitutes a waste zone, which where present, greatly improves 

recoverable reserve estimates . This zone ranges in thickness from zero to over 100 feet and is 

relatively unpredictable. Capping the Norphlet is a thin tight pyrite rich sandstone . 

The natural gas in Norphlet reservoirs is found in generally northwest-southeast trending sand 

dunes . The primary trapping structural style is broad, low-relief, faulted, salt anticlines 

associated with small-scale growth faults . The seal for natural gas is generally a tight upper 

section of the Norphlet overlain by nonpermeable Smackover carbonates . The primary source 

of the natural gas is Smackover algal carbonate mudstones. Thermogenic dry methane gas 

produced as a result of thermal degradation of crude oil commonly is associated with hydrogen 

sulfide and carboy dioxide, which are present in all of the Norphlet discoveries ." 

Subsequent to the Mancini, Mink et al papers, Mobil made available information developed by 

its research geology staff. The 1988 paper by Michael Marzano, Glenn Pense and Peter 

Andronaco added to the geologic knowledge of the Norphlet.36 A subsequent paper by Tew, 

Mink et al summarized Norphlet regional geologic patterns that commonly accompany the 

presence of natural gas." 

Productive Norphlet natural gas reservoirs are found in anticlinal traps where there is a 

fortuitous combination of source rock. The mechanism of structure formation appears to be 

basinward salt flowage that formed large, broad and subtle anticlines, most of which are faulted . 

The seal for natural gas in the Norphlet is a generally tight section of the Norphlet in the upper 

part of the formation, overlain by lower Smackover carbonates which are also nonpermeable . 

33M8I1C1Ill, Mink, Bearden and Hamilton, "A look at recoverable gas reserves in the Jurassic Norphlet 

formation off Alabama," OGJ, January 18, 1988, p. 62 - 64 . 

"U.S. DOI, Minerals Management Service, "Atlas of Northern Gulf of Mexico Gas and Oil 

Reservoirs," Volume I, Table 4 . 

3sMancini, Mink, et al, 1988, p. 64. 

36Marzano, Michael S ., Glenn M. Pence, and Peter Andronaco, "A Comparison of the Jurassic 

Norphlet Formation in Mary Ann Field, Mobile Bay, Alabama, to Onshore Regional Norphlet Trends," 

Transactions-Gulf Coast Association of Geological Societies, XXXVIII, 1988, p . 85 - 100 . 

3'Tew, Berry H., Robert M. Mink, Steven D. Mann, Bennett L. Bearde, and Ernest A. Mancini, 

"Geologic Framework of Norphlet and Pre-Norphlet Strata of the Onshore and Offshore Eastern Gulf of 

Mexico Area," AOGB Reprint Series 83, 1991, p . 596. 

15 
The majority of the Norphlet fields in the Mississippi, Alabama, Florida (MAFLA) region are 

found in the following geologic settings . 

" Major basement highs affected sedimentation in the eastern Gulf-the Wiggins Arch 

complex, which includes the Baldwin High, the Conecuh Ridge, and Pensacola-Decatur 

Ridge in northwestern Florida. 

" The best Norphlet facies are eolian sandstones that accumulated as thick dune, interdune, 

and marine sandstones . 

" The key factor controlling hydrocarbon potential are areas that have thick accumulations 

of Louann Salt, characterized by salt-produced peripheral faults, salt-produced anticlines, 

and low relief domes. 

Though unproductive at this time, potential undiscovered traps may be found where the Norphlet 

either thins or terminates over or against the basement highs, notably the Wiggins arch and the 

Pensacola-Decatur ridge complex. Regional stratigraphic and production data show that optimal 

reservoir sands and structures abound in the MAFLA region . AOGB Bulletin 140 concluded 

in 1991 that "the probability is high for numerous additional Norphlet fields" to be established 

in these areas." Especially in federal waters, many low relief faulted salt cored anticlines 

remain to be tested to the east of discoveries offshore Coastal Alabama. 

2.1 .2 Alabama Waters Norphlet Reserve Estimates-1987 

Mink, Hamilton, et al estimated recoverable reserves for sales gas (net of impurities, notably 

HZS and C02) in Alabama state waters to range between 5 .7 and 6 .5 TCF in 1987 .39 The 

proved estimates shown on Table 2.1 represent reserves in reservoirs that had been penetrated 

by wells which provided significant geologic and engineering data by 1987 . The potential 

reserves included natural gas that may be found in state waters in prospective reservoirs and in 

reservoirs that required further delineation. The 70 - 80 percent range shown on the table 

represents the amount of reserves in place assumed recoverable with existing technology and 

economic conditions . 

38Mink, Robert M., Berry Tew, Steven Mann, Bennett Bearden and Ernest Mancini, "Norphlet and 

Pre-Norphlet Geologic Framework of Alabama and Panhandle Florida Coastal Waters Area and Adjacent 

Federal Waters Area," AOGB Bulletin 140, 1990, p . 52 . 

39M1I11C, Robert M., Richard P. Hamilton, Bennett L. Bearden and Ernest A. Mancini, "Determination 

of Recoverable Natural Gas Reserves for the Alabama Coastal Waters Area," Oil and Gas Report 13, 

AOGB, 1987 . 

16 
Table 2.1 

Recoverable Sales Gas Reserves for Alabama Coastal Waters 

(1987) TCF 

Recovery Factors 70% 80 

Proven 3.65 4.17 

Potential 2.06 2.35 

Total 5 .71 6.52 

Source: AOGB, 1987 . 

2 .1.3 Alabama and Federal Mobile OCS Reserve/Resource Estimates-1997 

MMS and AOGB officials provided proved recoverable reserve estimates to Foster Associates 

for Norphlet fields . These are shown on Table 2.2 . Assuming a 75 percent recovery factor, 

nearly 9.0 TCF of recoverable, marketable Norphlet gas has been discovered in state and federal 

leased areas . These reserves are tied to volumetric estimates of specific reservoirs . The 

estimates do not include more speculative notions of undiscovered reserves or potential resource 

estimates. The most uncertain aspect of these reserve estimates is the recovery factor . No one 

has any experience with ultimate recovery from Norphlet reservoirs . Judging by some of the 

problems operators have encountered with scaling and water intrusion, maintaining production 

in Norphlet wells is a risk beyond the usual geologic risks anticipated in recoverable reserve 

estimates. (Mechanical and water problems are discussed in Section 6.0.) 

Achievement of the 75 percent recovery factor is clearly not certain. If the ultimate recovery 

is only 55 percent of gas in place, the discovered recoverable reserves drops to about 7 TCF and 

remaining reserves is about 4 .8 TCF. At the 1997 average production rate of 1 .0 BCFD, the 

reserve to production ratio (R/P) is between 13 - 19 years of remaining Norphlet production at 

55-75 percent recovery . 

Another speculative element of the reserve estimate is the OCS Destin Dome > 1 TCF estimate . 

This only reflects Chevron's discovery. The Norphlet potential beyond that is not addressed in 

Table 2 .2. 

17 
Table 2.2 

Recoverable Sales Gas Reserves for Alabama Coastal Waters 

(199 TCF 

State 

Mobile 

Bay 

OCS 

Destin 

Dome 

OCS 

Total 

Recovery Factor 75% 75% 75% 75 

Proven 5 .0 2.9 > 1 > 8 .9 

Cumulative Production, 1 .1 .6 0 1 .7 

Year end, 1997 

Remaining Recoverable 3 .9 2 .3 > 1 > 7 .2 

Source: AOGB, 1997 ; USDI, MMS, 1997. 

The Norphlet may yet become "another Prudhoe Bay," as Exxon Exploration V. P. Stephen M., 

Cassiani announced after the 1984 State Lease Sale . Norphlet reserve estimates by the Gas 

Research Institute in their 1996 projections, predict that discovered reserves in the Norphlet 

trend will reach 13 - 15 TCF between 2000 - 2005 .'° This estimate includes the entire 

Norphlet that extends east from Louisiana across Mississippi, Alabama and eastward beyond the 

OCS Destin Dome. While there will be continued drilling of known but unprobed Norphlet 

structures in Coastal Alabama and Mississippi between now and 2000, there is no other Norphlet 

leased acreage to drill to yield GRI's reserve estimate of twice that of Table 2 .2 by 2005 . 

Offshore Panhandle Florida may yet prove to fulfill GRI's prediction. 

2.2 Gas Price Outlooks-Early 1980s-and Subsequent Market Developments 

Since the 1954 Phillips case," the U.S. natural gas market has exhibited substantial price 

variations primarily caused by changes in macroeconomic growth, interfuel competition 

(primarily from fuel oil), and federal price regulations . One of the high price outlook periods 

stemmed from the passage of the Natural Gas Policy Act (NGPA) of 1978 and lasted until about 

1982. During this brief period the State of Alabama was fortunate enough to conduct its first 

offshore lease sale in March 1981, and MMS conducted Lease Sale 67 in February 1982. 

Figure 2.1 provides an overview in the forces affecting U.S . natural gas market conditions 

during five epochs from the mid-1970s to 1996. MOEPSI's regulatory struggle with the State 

'Paul Holtberg, Thomas J . Woods, Marie L. Lihn and Kathy D. Nice, "Baseline Projection Data 

Book," GRI, 1996, p. 517. 

"Phillips Petroleum Co . v . Wisconsin, 347 U.S . 672 (1954), 53, 128, 624 . 

18 
" Stringent Federal Wellhead Price Controls 

" High Gas Mental Growth 

" Low Drilling Activity 

-RA Replace only 45% of Production 

" Supply Shortages Occur & Peak 1976/77 

" Shortages not as bad In Rocky Mountain area 

-Higher reserve life -Less Curtailment 

-Limited market opportunity for Rocky Mountain production 

" NGPA Passes Congress -1978 

-Establishes Max. Lawful Price -Schedules Deregulation (1985) 

" NGPA's Immediate Impacts 

-Drilling AcUvlty Doubles -RA up 86% 

-Gas Consumption Grows -Sharp Increase In Average Gas Prices 

-U.S Supply / Demand In Reasonable Balance 

" Cont racting Practices 

-Long-Term Contracts -High Min . Take Req. 

-High Contract Prices at Max. Lawful Price 

" Carter Energy Plan Legislation 

" U,3. Gas Demand Declines " Oil Price Declines - Eap. 1988 

" Deregulation of New Gas In 1885 " Spot Market Emerges 

" Surpluses emerge, especially In 

Rocky Mountain Area 

" FERC Initiates Pro Competition Programs 

" Contracting Practices 

-Many Pipelines Cease Contracting for New Supplies 

-Low Minimum Take Requirements -Market Price Protection Clauses 

" Restructuring of U.S Gas Markets (re FERC Order 836) 

-Unbundlinp of Sales Service -Capacity Release Program 

-Pass Through of Transition Costs 

" Futures Market Grows (NYMIX 4/90) 

" Transportation as opposed to sales volumes 

" Gas Demand Recovers 

" Improved Supply Technology (e .g . Lower Discovery Costs) 

. Contracting Practices 

-Direct Purchases by Pipeline Customers 

-Shorter Terms -Price Tied to Soot Market 

" Continued Growth In Gas Market ' " Development of Derivatives Market (e.g . NYM" 

" Greater Gas Price Transparency (e .g . Reliable Price Indies) " Commencement of Deregulation of Core Retail Markets 

" Increased Price Volatility " Improved Supply Technology (e .g. Production from Deeper Waters) 

-High Demand -low Storage Inventory . Increased Competition of Trensporadon (e.g . Capacity Release Market) -Oil Price Volatility 

-Only Moderate Increase In U.S . Dellverabllity a Increased Canadian Gas Imports 

01 

1970 1975 1980 1985 1990 1995 

.<. . . . t 

Figure 2.1 . Epochs of U.S. Natural Gas Market Conditions . 

Source: Foster Associates, 1997. 
of Alabama fortunately occurred during the 1970s, the period of wellhead price controls . When 

MOEPSI filed for a permit in 1970, gas was selling for about $0.25 per MCF. The world crude 

oil price was about $3 .00 per barrel . International crude oil price shocks related to the 1973 oil 

embargo and Middle East political instability in 1979 increased the price of world crude oil more 

than ten-fold, as can be seen on Figure 2.2., while domestic crude oil and gas prices remained 

controlled at lower levels throughout the 1970s . 

High gas demand growth matched by low reserve replacement caused interstate gas shortages 

beginning in the early 1970s that worsened during the severe 1976/77 winter . Something had 

to be done . President Carter's Project Energy Independence was born. 

2.2.1 NGPA: 1978 - 1982 

The NGPA was passed by Congress in late 1978 in response to gas shortages that resulted from 

stringent federal price regulatory policy by the Federal Power Commission (succeeded by the 

Federal Energy Regulatory Commission in late 1977) . The NGPA represented a series of 

compromises to mollify both consumer and producer interests . Among the provisions protecting 

consumers, the existing field price ceilings generally were retained (e .g ., vintage pricing) for 

gas dedicated to interstate commerce at the enactment of the NGPA. New and higher price 

ceilings were created for gas discovered after 1978 . In total, about 25 different pricing 

categories were created. Producers' interests were satisfied by immediately removing the price 

ceilings for certain new gas categories, beginning with "deep gas" (gas produced below 15,000 

feet), and finally, by scheduling removal of price regulations for most post-NGPA gas in 1985 . 

The federal regulatory policy also included the determination of pipelines' resale rates based on 

the weighted average price of gas purchased by regulated companies (e .g ., interstate pipelines) . 

Because of this pricing mechanism that averaged all gas costs, new deregulated gas prices could 

increase substantially and yet the resale rate would remain competitive with fuel oil, at least for 

a while. Eventually, as producers concentrated their drilling efforts on the higher price 

categories and production from lower price vintage gas sources declined, average gas prices 

increased and gas became less competitive with alternatives . To illustrate, the U.S . wellhead 

average price increased from about $0.91 per MCF in 1978 to about $2 .50 per MCF in the early 

1980s. 

Immediately after the NGPA was passed through about 1981, the price of unregulated new gas 

shot up . During this period, prices for NGPA Section 107 deep gas, which included Norphlet 

production, ranged between $7 and $9 per MCF. MOEPSI's discovered Norphlet gas reserves 

were now a treasure beyond anyone's expectation years earlier when they applied for the 

exploration permit. 

A typical pipeline/producer contract executed during this period reflected these high prices, a 

"favored nation" provision, a minimum take provision, a take-or-pay provision and no 

mechanism for reducing the contract price even if subsequent market conditions warranted. 

Forecasts of U.S . gas prices by authoritative sources (e .g ., the U.S . Dept. of Energy) during 

this period show the expectation of continuously high and rising prices . One reason for the 

20 
40 

30 

20 

--- 

10 

"-- - 

0 - -1--~------ ~ -----~-----1-

1972 1973 1974 1975 1976 

Figure 2 .2 . World Oil Prices, 1972-1983 . 

Source : USDOE, EIA, Annual Energy Reveiw, 1983 ; Annual Energy Outlook, 1983 . 

N 

1977 1978 1979 1980 1981 1982 1983 
forecast of high gas prices was the fact that experts were forecasting high oil prices . Table 2 .3 

summarizes DOE's oil and gas price forecasts made in 1981, 1983 and 1985, compared with the 

actual prices that ensued. Prices shown for natural gas are the average of all categories of 

regulated and unregulated gas . 

Table 2.3 

DOE Oil and Gas Price Forecasts 

Actual 

1980 1985 

Projected (mid range) 

1990 1995 2000 

Forecasted in 1981 (1980 dollars) 

Oil ($/Barrel) $34 $33 $49 $67 $75 

Gas ($/MCF) $1 .59 $3 .33 $6.02 $7.63 $8.28 

Forecasted in 1983 (1983 dollars) 

Oil ($/Barrel) $34 $27 $37 $50 NA 

Gas ($/MCF) $1 .59 $2 .68 $3 .62 $6.33 NA 

Forecasted in 1985 (1985 dollars) 

Oil ($/Barrel) $34 $27 $34 $50 NA 

Gas ($/MCF) $1 .59 $2 .60 $2 .68 $4.03 NA 

Actual (nominal dollars) 

Oil ($/Barrel) $34 $27 $22 $22 $151 

Gas ($/MCF) $1 .59 $2 .51 $1 .71 $1 .75 $2 .24' 

Sources: USDOE(EIA) Annual Energy Outlook, 1981, 1982, and 1983. 

USDOE(EIA), Monthly Energy Review, (11/96) 

'USDOE(EIA), Short-Term Energy Outlook, (4/98), 1998 data . 

EIA's 1980 Annual Report to Congress4Z reported that "the world is-and has been for some 

time-running out of relatively cheap sources of energy ." The 1981 DOE forecast called for 

oil prices of $67 by 1995-in 1980 dollars. The 1981 DOE Annual Report to Congress 

projected oil prices in nominal dollars to reach $246 per barrel by 2000 on the first page of the 

report . Keep in mind that the Iranian revolution and Iran-Iraq conflicts reduced OPEC exports 

in 1979, while demand for OPEC oil had grown over the prosperous 1970s. Couple this with 

the March, 1979, Three Mile Island incident, which eliminated America's nuclear 

panacea-virtually overnight-and the Energy Crisis was born. Oil prices shot up to more than 

$40 per barrel in late 1979 from --$11 .00 in 1978. This is why price forecasts for more than 

$100 per barrel were common. Those were turbulent times . 

In 1983 and 1985 DOE was still forecasting $50 oil and $4 - $6 average wellhead gas prices, 

even though it had dropped its novel "fly-up" assumption ; i . e., that regulated gas prices would 

fly up to the $7 - $9 prices seen for deregulated prices in 1981 when all gas prices were 

°ZUSDOE, EIA, Annual Report to Congress, May 27, 1981, Executive Summary. 

22 
decontrolled in 1985 . Remarkably, the 1983 Annual Energy Outlook discovered supply elasticity 

and noted that the significant supply response since 1981 caused it to reduce its 1990 gas price 

forecast . 

These DOE forecasts of high gas prices were not unique, as illustrated by a comparison of oil 

and gas price forecasts prepared by others during the 1980-82 period . Table 2 .4 shows the 1981 

world oil price as $37 per barrel and forecasts to 1990 ranging between $41 and $64 in real 

dollars . U.S . average wellhead gas prices were forecast to range upward to $6.50 per MMBtu. 

Exxon called for a "50 percent increase in the purchase prices of Middle East crude oil in real 

terms between 1980 and 2000" in its 1980 World Energy Outlook." Exxon was pessimistic 

about the outlook for U.S . gas supplies, projecting the decline in lower 48 production between 

1973 and 1980 into the future and calling for completion of a pipeline from Alaska to the lower 

48 to bring-in Alaska's huge gas reserves . Exxon projected that syngas would provide nearly 

10 percent of U.S . gas supply by 2000. New gas discoveries were anticipated to account for 44 

percent of the 2000 gas supply mix'-no doubt induced by the $5 - $6 gas price forecast. 

2.2.2 Price Stabilization : 1982 - 1986 

Forecasters began to reduce their price outlooks in the mid-1980s. Beginning in about 1982, 

energy market conditions changed dramatically . Oil prices declined for the first time since the 

sharp run-ups that began in 1973 . An economic recession occurred in 1982 and excesses of 

natural gas supplies began to emerge . The "gas bubble" set in. So much new gas had been 

discovered within a few years that supplies overhung demand . By 1986, as MOEPSI was to 

discover, finding markets for new gas became difficult. 

Gas prices began to decline . Gas contracting practices changed. In particular, purchasers began 

to negotiate market-sensitive pricing provisions into their contracts (e .g ., market-out provisions). 

Because of the high-cost gas contracts that remained in effect, new gas prices had to be kept low 

in order for the average prices to be competitive . A typical market price during 1982-1984 for 

the new deep gas was in the range of $2 .50 per MCF, compared with the $7 to $9 per MCF 

price of high cost gas under contracts with 1979-81 execution dates . 

FERC initiated a pro-competitive policy . In October 1985, FERC issued a keystone rule, Order 

No . 436, that required interstate pipelines to become open-access carriers . As a result of these 

events, forecasters revised their subsequent price outlooks sharply downward. Table 2.3 shows 

that DOE's gas price forecast for 1990 dropped from $6.02 per MCF (1981 dollars) forecast in 

1981, to $3 .62 per MCF (1983 dollars) forecast in 1983, to $2.68 per MCF (1985 dollars), 

forecast in 1985 . 

'Exxon, World Energy Outlook, December, 1980, p. 3 . 

'Exxon Company U .S .A.'s Energy Outlook : 1980 - 2000, p . 12. 

23 
Table 2.4 

Comparison of Forecasts of 1990 Oil and Gas Prices 

1980-1982 

$(1981) 

Product and Forecaster Actual 

1981 

Projected 

1990 

World Crude Oil (per barrel) 

DOE - EIA (2/82) 37 54 

NEPP (7/81) 37 52 

OPPA (8/82) 37 42 

DRI 37 41 

A.G.A 37 46 

Exxon 37 46 

Sherman Clark Associates 37 64 

U.S . GAS (wellhead per MMBtu) 

DOE - EIA (2/82) 1 .98 6 .54 

NEPP (7/81) 1 .98 6 .61 

OPPA (8/82) 1 .98 5 .67 

Sources: American Gas Association, TERA Analysis, November 21, 1980. 

U.S . Department of Energy, Office of Policy, Planning and Analysis, Energy Projections to the 

Year 2000. A Sunnlement to the National Energy Policy Plan, July 1981 . 

U.S . Department of Energy, Office of Policy, Planning and Analysis, Energy Projections to the 

Year 2000. A Supylement to the National Energy Policy Plan, August 1982 . 

U.S . Department of Energy, Energy Information Administration, 1981 Annual Report to 

Congress , February 1982 . 

Data Resources, Inc. Enerjzy Review, Summer 1982. 

Exxon Corporation, World Energy Outlook, December 1980 . 

Sherman Clark Associates, Evaluation of World Energy Developments and Their Economic 

Significance , March 1981 . 

2.2.3 Restructuring and Emergent Commodity Pricing: 1986 - 1992 

The petroleum industry experienced a "reverse price shock" in 1986, when price-induced 

reductions in demand for OPEC oil supplies resulted in excess OPEC producibility that the cartel 

was unable to manage. Saudi Arabia, in particular, concluded that it was no longer in its selfinterest to continue to withhold production from markets. Saudi Arabia moved to netback 

pricing, thereby guaranteeing the competitiveness of its oil in world markets. As a consequence, 

24 
it increased its production at substantially lower prices than had prevailed in late 1985/early 

1986. 

Oil prices plunged to less than $10 per barrel, before stabilizing generally in the $15 - $20 per 

barrel range since 1987 as shown on Figure 2.3 . The resultant competitiveness of fuel oil in 

fuel-switchable markets further dampened natural gas demand growth, and the supply overhang 

continued to suppress natural gas wellhead prices . Average gas prices shown on Figure 2.4 

stabilized under $2.00 per MCF. MOEPSI's discovered Norphlet gas had gone from less than 

a dollar per MCF to $9.00 per MCF and back to about $2 .00 while permitting, exploration and 

development ensued. Quite a wild ride. 

Confronted with the "gas bubble," natural gas producers in particular sought to increase the 

market for natural gas . The advent of non-discriminatory open-access transportation service on 

FERC-regulated natural gas pipelines under Order 436 held out the promise for market 

penetration and sales growth for producers, or marketers representing them . However, the dualrole of interstate pipelines as both transporter of gas owned by others, and merchant of gas sold 

to pipeline customers was an obvious conflict. Producers raised concerns at FERC that the 

institutional setting was impeding the market growth for a clean-burning essentially 100 

domestic energy source . For example, the pipelines still had gas purchase contracts that made 

it logical for them to promote their bundled gas-plus-transportation service at the expense of 

limited progress on opening up markets for gas producers. 

This tension led to FERC issuing Order 636 in April 1992. Order 636 effectively eliminated 

the interstate pipelines' gas sales role, streamlined the mechanisms for gas shippers to obtain 

pipeline transportation rights, and substantially advanced the FERC's objective of attaining 

robust competition in natural gas supply and acquisition. The resultant competitive gas supply 

markets have been further enhanced by the growth of short-term market price discovery, both 

in the cash and futures markets, through electronic communication systems . Pipeline usage 

planning centers around monthly forecasts, and therefore much gas is sold and priced just prior 

to the calendar month. Monthly natural gas pricing information is widely-disseminated by 

reliable trade publications, and longer-term contracts commonly have their prices set monthly 

based on such prices . Figure 2.5 shows the monthly average contract price series governing 

offshore Louisiana production . Month price volatility is apparent as seasonal demands, gas 

storage adequacy and colder winters significantly affect prices . Eastern U. S. had two 

successive cold winters-1995/96 and 96/97 . Market conditions drove monthly contract prices 

above $3 .00 per MCF for the first time since regulatory interference had pushed them that high 

15 years earlier. 

2 .2.4 Commodity Pricing and Growth of Efficient Markets: Post 1993 

Active and price-responsive markets for most of the natural gas sold in the U.S . have resulted 

from FERC initiatives and institutional changes. These institutional changes-away from 

regulatory rigidities and inefficient markets-combined with relatively low and fairly stable crude 

oil prices, and with technological advances in natural gas supply discovery and development, 

have kept natural gas wellhead prices at fairly stable and low levels . At the same time, 

dependence upon monthly pricing regime and the emergence of active day-by-day short term 

25 
N 

30 

25 

as 

a 20 

0 

Q 

15 I10 

1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 

Figure 2 .3 . Average Crude Oil Prices, 1982-1995 . 

Source: USDOE, EIA, Annual Energy Review, various years. 

1993 1994 1995 
$8 .00 

$6 .00 

w 

$4.00 

$2 .00 

$0.00 1 i--I - --I-! - -1----i - - - . -I -L- - t _ _ 

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 

Figure 2 .4 . Estimated Initial Year Contract Price for Deep Well Gas. 

Source : Foster Associates, Inc. 1996 estimates based on interstate gas pipeline PGA filings w/ FERC, trade press articles and EIA's Monthly Energy Review . 

N 

v 
N 00 $4.0 

$3.0 f-- 

$2.0 - 

$1 .0 ~ 

$0.0 

Figure 2.5 . So. (Ofd LA Spot Prices . 

Source: USDOE, Federal Energy Regulatory Commission, 1997. 

199015 7990/10 199113 1991f8 1992101 1992/8 1997111 199314 1993/9 1994/2 199417 1994/12 7995/5 1995/10 199613 199818 1997/1 1987/8 1997/11 
markets, have resulted in some price volatility . While some of this can be managed through 

contract pricing provisions that dampen day-to-day price changes, and by hedging with futures 

and derivatives contracts, much natural gas is sold under potentially volatile market-responsive 

pricing typical of commodity markets . 

As U.S . gas markets have become more efficient, transportation profits have become more 

subject to market forces than to assured recovery of costs including a return on investment. 

Responses to such profit pressures include consolidation within the pipeline sector via mergers 

and acquisitions . Additionally, gas marketing combinations have occurred (e.g. Mobil and Pan 

Energy, Chevron and NGC Corp) to achieve scale and scope economies in a low margin 

business. Some firms have focused on "mid-stream" operations (gathering, processing and liquid 

extraction and marketing to apply market savvy to niche operations . Finally, exploration and 

development technological advances have enabled producers to bring economic energy supplies 

to market in a low price environment, while still making a profit . Norphlet exploration and 

development projects are not as profitable as lease purchasers might have anticipated, but 

Norphlet supplies continue to increase . 

29 
3.0 Mobile Bay Leasing History 

During the period of peak outlooks for energy prices-between 1981 and 1984-Alabama leased 

tracts in state waters for bids totalling $800 million. MMS leased tracts in federal Mobile Bay 

OCS waters between 1982 and 1985 for bids totalling $562 million-$1 .36 billion total . 

Seventeen Norphlet wells were spudded between 1981 and 1984, 13 of which became discovered 

gas wells-an amazing accomplishment. While changes in gas prices after 1982 and after 1986 

no longer justify the extremely large bids seen in the 1981 and 1982 lease sales, nonetheless 

three new state Norphlet discoveries and one federal Norphlet discovery became development 

projects based on discoveries before year end 1984. 

3 .1 State Sale #1 - 1981 

One important result of MOEPSI's discovery well 76-1 was the bidding interest in the state's 

March 1981 lease sale. Although Mobil had drilled only the single discovery well, with over 

15 months to assess the implications of the discovery, industry bidders exposed $1 .16 billion and 

the State of Alabama accepted bids on 13 tracts totalling $449.3 million plus royalty payments 

between 25 and 28 percent . Exxon submitted high bids of $255 .9 million for seven of the 13 

tracts awarded . Figure 3 .1 shows the 13 tracts leased in the 1981 sale plus MOEPSI's four 

tracts . 

Table 3 .1 shows that bids were submitted on 35 tracts, but Commissioner John M. McMillan, 

Jr., Department of Conservation and Natural Resources and Edward Reynolds, Director of State 

Lands, rejected bids for 22 tracts . Asked why they accepted only a third of the bids, Mr . 

McMillan stated that "with nearly $450 million in the bank-more than we ever imagined-we 

simply rejected all the bids below about $2,000 an acre."" Figure 3 .2 shows that the gain to 

Alabama from the 22 rejected tracts would have added $55 million to state coffers, about 12 

percent more, bringing the total to $505 million. The largest bid rejected was Exxon's $8 .6 

million for tract 114; the largest bid per acre rejected was Getty's $2,222 for tract 110. (The 

tract was small and only would have added $2.9 million to Alabama's bonus receipts.) The sale 

tripled Louisiana's previous high cash bonus payday of $157 .7 million.a6 

"We've struck oil," a jubilant Governor Fob James quipped after the cash bonuses were counted. 

Commissioner McMillan was shocked by the amounts bid. Industry observers stated before the 

bids were opened that maybe $250 million at risk might have been expected.' The $1 .16 

billion amount was nearly five times higher . Current Lands Division manager James Griggs 

described the industry's bids as "gold fever . "4$ Exxon clearly bet serious money on their 1980 

World Energy Outlook projections . 

'Personal 'communication, Montgomery, Alabama, February 11, 1997. 

'OGJ, "Mobil strike helps spark Alabama tract bidding," April 13, 1981, p. 36-37 . 

"'Oil bonanza couldn't have come at better time for state," Cullman Times, April 21, 1981 . 

"Personal communication, Montgomery, Alabama, February 11, 1997. 

30 
xkok MO LE BAY AREA 

NION.~ULF & Porn LEASE ACTIVITY MAP. 

MOW*

 & 'SHELL _ t 

HELL . : _: . :., . I ~~ -----/I` 

THEODORE 

I INDUSTRIAL 

m 

t 

BELLINGRATH 

GARDENS 

BAYOU 

LA BATRE 

71 721 

MOBILE BAY 

761 77 

FAIRHOPE 

) 

I 

POINT CLEAR 

ISLAND `- _-'g q ` 95 

89 ~ F MpRGAN PEN 1 NSULA 

_~ . _ . 

Skate _ .~,,F ;

. . . . . . 

0 MILES 8 = ~ ~~" Federal 

l-3 2 

0 KILOMETERS 12 

Figure 3 .1 . Mobile Bay Area Lease Activity Map, March 1981 . 

Source: MOEPSI, 1997 . 

31 
Table 3.1 

Bids Received for the March 1981 State Lease Sale 

State 

Block No. Acreage Bidder Total Bonus 

$ 

Bonus Per 

Acre 

$ 

Royalty Result' 

49 5,164 Conoco, et al . 1,780,000 344 .69 28.7 R 

50 5,164 Conoco, et al . 780,000 151 .05 28.7 R 

52 5,164 Exxon 9,112,000 1,764 .52 25 A 

Shell 533,000 103 .22 25 R 

59 4,720 Getty, Conoco, et al . 722,160 153 .00 25 R 

60 4,711 Getty, Conoco, et al . 720,783 153 .00 25 R 

62 5,164 Exxon 10,522,000 2,037 .57 27 A 

Getry, Conoco, et al . 3,940,132 763.00 28.7 R 

Sunlite International, Inc . 581,040 112 .52 26.1 R 

63 5,164 Exxon 15,226,000 2,948 .49 27 A 

First Energy Corp. 4,389,400 850.00 25 R 

Geay, Conoco, et al . 2,752,412 533.00 28.7 R 

Shell 533,000 103 .21 25 R 

64 5,164 Sunlite International, Inc . 581,040 112 .52 26.1 R 

71 4,196 MOEPSI 40,425,000 9,634 .17 25 A 

SOHIO and Hunt 37,510,000 8,939 .47 25 R 

SOHIO and Hunt 32,200,000 7,673 .97 30.4 R 

SOHIO and Hunt 17,300,000 4,122 .97 51 R 

Getty, Conoco, et al . 15,537,788 3,703 .00 28.7 R 

Shell and Amoco 9,270,000 2,209 .25 25 R 

Union, Gulf, Pennzoil & Total Pet . 7,381,000 1,759 .06 25 R 

Chevron 2,142,000 510.49 26.2 R 

Louisiana Land & Exploration 839,200 200.00 37.5 R 

72 5,164 MOEPSI 31,535,000 6,106 .70 25 A 

SOEIIO and Hunt 23,700,000 4,589 .46 25 R 

SOHIO and Hunt 21,200,000 4,10534 30.4 R 

Getry, Conoco, et al . 17,573,092 3,403 .00 26.7 R 

Union, Gulf, Pennzoil & Total Pet . 14,676,000 2,841 .98 25 R 

Shell and Amoco 9,130,000 1,768 .01 25 R 

SOHIO and Hunt 7,300,000 1,413 .63 51 R 

Exxon 5,104,000 988.38 25 R 

Chevron 2,142,000 414.79 26.2 R 

Louisiana Land & Exploration 1,032,800 200.00 37.5 R 

73 3,690 Shell 5,674,000 1,537 .67 25 R 

Union, Naromas & Pennzoil 5,130,000 1,390 .24 30 R 

Eon 5,106,000 1,383 .74 25 R 

Louisiana Land & Exploration 959,400 260.00 37.5 R 

88 5,112 Getty, Conoco, et al . 7,427,736 1,453 .00 26.7 R 

Hunt and SOHIO 1,538,712 301.00 34 R 

Chevron 555,000 108 .57 26.2 R 

32 
Table 3.1 (continued) 

Bids Received for the March 1981 State Lease Sale 

State Bonus Per 

Block No. Acreage Bidder Total Bonus Acre Royalty Results 

89 4,811 Phillips, Hunt and SOHIO 42,712,059 8,878 .00 25 A 

Phillips, Hunt and SOHIO 35,666,022 7,413 .43 30.4 R 

Phillips, Hunt and SOHIO 20,277,024 4,214 .72 51 R 

Union, Gulf, Pogo, Naromas, 9,632,000 2,002 .08 25 R 

I Pennzoil and Total Pet. 

I Getty, Conoco, et al . 6,749,833 1,403 .00 26.7 R 

MOEPSI 5,145,000 1,069 .42 25 R 

Shell and Amoco 1,180,000 245.27 25 R 

90 4,612 Union, Gulf, Pogo, Naromas, 21,879,000 4,743 .93 25 

i 

A 

Pennzoil and Total Pet . i 

SOHIO and Hunt 13,353,000 2,895 .27 25 R 

SOHIO and Hunt 11,317,848 2,454 .00 30.4 R I 

Getty, Conoco, et al . 9,652,916 2,093 .00 26.7 R 

MOEPSI 5,235,000 1,135 .08 25 R 

SOHIO and Hunt 3,613,734 783 .55 51 R I 

Shell and Amoco 570,000 123 .59 25 R 

91 5,010 Pennzoil and Naromas 5,105,000 1,018 .96 30 R 

92 5,164 Naromas 3,000,000 580.94 35 R 

Hunt and SOHIO 2,210,192 428.00 34 R 

Conoco, et al. 1,337,000 258.91 28.7 R 

Shell 887,000 171 .77 25 R 

93 4,823 Conoco, et al . 3,713,000 769.85 28.7 

i 

R 

MOEPSI 1,010,000 209.41 25 R I! 

96 

I 

3,834 First Energy Corp. 5,751,000 1,500 .00 25 R 

Geay, Conoco, et al . 3,768,000 982.78 25 R 

Getry, Conoco, et al . 975,400 254.41 33.7 R 

Hunt and SOHIO 475,416 124.00 34 R 

97 3,217 Hunt and SOHIO 2,100,701 653 .00 34 R 

i 98 3,697 Hunt and SOHIO 2,101,745 568.50 34 R 

I Naromas 897,271 242.70 25 R li 

99 2,806 Naromas 684,355 243.89 25 

l 

R 

Hunt and SOHIO 352,153 125 .50 34 R 

100 3,479 Naromas 357,711 102 .82 25 R 

101 4,438 Naromas 456,315 102 .82 25 R 

103 5,062 Conoco, et al . 837,000 16535 28.7 R 

104 3,846 Conoco, et al . 647,000 168 .23 28.7 R II 

110 1,295 Getty, Conoco, et al . 2,878,000 2,222 .39 25 R I 

i Chevron 

Hunt and SOHIO 

2,620,000 

450,660 

2,023

348

.17 

.00 

26

34 

.2 R 

R I 

33 
Table 3.1 (continued) 

Bids Received for the March 1981 State Lease Sale 

State Bonus Per 

Block No. Acreage Bidder Total Bonus Acre Royalty Resultl 

111 1,687 Exxon 53,168,000 31,516 .30 28 A 

MOEPSI 22,225,000 13,174 .27 25 R 

', Shell and Amoco 21,340,000 12,649 .67 25 R 

Getty, Conoco, et al . 12,078,000 7,159 .45 28.7 R 

Pennzoil and Naromas 10,133,000 6,006 .52 25 R 

j Chevron 8,560,000 5,074 .10 26.2 R 

Chevron 3,725,000 2,208 .06 35 R 

Hunt and SOHIO 655,400 388.50 34 R 

112 4,932 Exxon 137,254,000 27,829 .28 28 A 

Getty, Conoco, et al . 37,067,000 7,515 .61 26 .7 R 

Getty, Conoco, et al . 25,137,000 5,096 .71 33 .7 R 

Shell and Amoco 10,580,000 2,145 .17 25 R 

MOEPSI 5,815,000 1,179 .03 25 R 

Pennzoil and Naromas 5,077,000 1,029 .40 25 R 

', Chevron 2,112,000 428.22 26.2 R 

Hunt and SOHIO 759,528 154.00 34 R 

I 113 5,123 Shell and Amoco 34,370,000 6,708 .96 25 A 

Exxon 26,154,000 5,105.21 27 R 

Getty, Conoco, et al . 12,157,000 2,373 .02 25 R 

Getty, Conoco, et al . 9,243,000 1,804 .22 33.7 R 

Union, Naromas & Pennzoil 9,177,000 1,791 .33 25 R 

i Hunt and SOHIO 1,308,927 255.50 34 R 

114 4,782 Exxon 8,608,000 1,800 .08 25 R 

Getry, Conoco, et al . 7,273,000 1,520 .91 28.7 R 

Union, Pennzoil & Total Pet. 4,171,000 872.23 25 R 

Hunt and SOHIO 755,556 158 .00 34 R 

115 3,416 Exxon 12,308,000 3,603 .04 27 A 

Conoco, et al . 7,129,000 2,086 .94 28 .7 R 

Union 1,817,000 531 .91 25 R 

First Energy Corp. 1,708,000 500.00 25 R 

I Hunt and SOHIO 1,310,036 383.50 34 R 

116 3,254 Exxon 18,323,000 5,602 .95 27 A 

Conoco, et al . 12,840,000 3,945 .91 28 .7 R 

Hunt and SOHIO 1,630,254 501 .00 34 R 

117 3,479 Hunt and SOHIO 1,612,518 463 .50 34 R 

Exxon 1,104,000 317.33 25 R 

118 3,429 Exxon 1,102,000 321 .38 25 R 

Hunt and SOHIO 353,188 103 .00 34 R 

132 2,367 Shell 22,435,000 9,478 .24 25 A 

1 R - rejected ; A - accepted 

Source : Alabama Dept. of Conservation and Natural Resources, 1997 ; 

Alabama Oil and Gas Board, 1986 . 

34 
600 

500 

400 

0 

300 

Rejected 

Zoo 

ioo 

High Lease Tract Bids 

Figure 3 .2 . State of Alabama Cumulative Lease Bids, 1981 . 

Source: Table 3 .1 . 

w 
The bonanza couldn't have come at a better time because interest rates were at record highs . 

The money was invested in 90-day time deposits earning 13 .9 to 14 .4 percent while the governor 

and state legislators decided what to do with the bonanza. 

Exxon, which exposed $303 million in 13 bids, paid the highest two bonuses to lease tracts 111 

and 112 for $53 .2 million and $137 .3 million, leaving a total of $131 .2 million "on the table" 

for tracts 111 and 112. Exxon described their exuberance as simply "reflecting their interest in 

the area" and wouldn't discuss their high bids with the Oil and Gas Journal's reporter .a9 

MOEPSI, holding the discovery well just northeast of these two tracts, offered only $28 million 

for them, bidding only $5 .8 million for tract 112 compared to Exxon's $137 .3 million. Exxon 

substantially overbid to win tracts 62 and 63 as well, leaving $17 .4 million "on the table" for 

those tracts . MOEPSI, which held the leases for tracts 76 and 77 immediately south of tracts 

62 and 63, didn't even bid on them. MOEPSI's interest lay to the west; they bid their highest 

amounts, $71 .9 million, to win tracts 71 and 72. Tract 72 attracted the highest number of 

bidders-eight-in the sale . 

Exxon acquired leases for tracts 115 and 116 for $30 .5 million. These winning bids were in line 

with the losers' bids . Shell was the other big winner in the sale, acquiring leases on tracts 113 

and 132 for $57.1 million-overbidding Exxon by 35 percent on tract 113, and submitting the 

only bid on 132 . 

To jump ahead of the story : Exxon and Shell successfully bought their way into the Norphlet 

game . Exxon's tracts subsequently became three Norphlet fields-Bon Secour Bay, North 

Central Gulf and Northwest Gulf. Shell's acreage, between Eon's Gulf of Mexico fields, 

became the Fairway field . 

3.2 OCS Lease Sale 67 - 1982 

The following February 1982 MMS leased its first acreage contiguous to state waters of Coastal 

Alabama as part of OCS Sale 67, which also included tracts off Texas and Louisiana in deep 

water . MOEPSI, bidding with Conoco and Getty (now Texaco), was the biggest winner in 

Coastal Alabama OCS, leasing tracts 778, 779, 822, 823, and 824 for $100 .2 million to beat 

Exxon which bid $76.5 million for the tracts . The tracts adjoin Exxon's previous high bid state 

tracts 111 and 112 . Exxon, having overbid $131 million for tracts 111 and 112 in the 1981 state 

sale, now was $24 million short of controlling the highest priced leases acquired in the OCS 

sale-and all the acreage in the neighborhood of their high bid state tracts 111 and 112 . 

A group comprised of Chevron, Gulf, Pennzoil, and Union acquired tracts 861 and 862 for 

$41 .2 million. Groups led by Shell and ARCO were the other major winning bidders picking 

up tracts 908 and 909 for $52.5 million. MMS accepted a total of $218.7 winning bids for 17 

Alabama OCS tracts, shown on Table 3 .2 . The 1981 state sale and 1982 federal sale introduced 

all the subsequent Norphlet operators to Coastal Alabama-MOEPSI, Exxon, Shell, Chevron, 

BP and Unocal . 

490GJ, "Mobil strike helps spark Alabama tract bidding," April 13, 1981, p . 36-37. 

36 
Table 3.2 

Leased Blocks in the Federal OCS Water Near Alabama's State Coastal Waters through 1985 

Offshore 

(Block aoa Acres Original Lessee 

OCS Lease 

Sale Do. Total Bonus 

$ 

Bonus 

per acre 

$ 

M 779, 823, 824 5,585 MOEPSI, Conoco and Geay 67 55 119 000 9 856 

M 778, 822 5,324 MOEPSI, Conoco and Getry 67 

, , 

45,117,000 

, 

8,471 

M 909 5,760 Shell, Florida Exploration, Fluor Oil & Gas and Crown Central 67 28,277,000 4,909 

M 908 5,760 ARCO, Texas Gulf, Murphy, and ODECO 67 ?A,197,760 4,201 

M 861 5,198 Gulf, Union, Pennzoil and Chevron 67 23,616,000 4,543 

M 862 5,618 Chevron, Gulf, Pennzoil and Union 67 17,616,000 3,135 

M 867 5,760 Exxon 67 6,747,000 1,171 

iM 870 5,618 Placid 67 5,084,643 905 

~M 864 5,760 Tenneco 67 4,880,000 847 

M 821 4,028 SOHIO 67 3,000,000 745 

M 906 5,760 Chevron 67 2,110,000 366 

~M 866 5,760 Exxon 67 1,211,000 210 

M 868 5,687 Exxon 67 1 014 000 

I 

178 

IM 827 3,174 Exxon 67 

, , 

718,000 226 

Subtotal 1982 218, 707, 403 

M 905 5,760 Union 69 (Part I1) 881,900 153 

Subtotal 881,900 

M 863 5,760 Tenneco, ARCO, Murphy, ODECO and Elf Aquitaine 72 7,930,000 1,377 ', 

M 952 5,760 ODECO, Koch and Santa Fe Energy 72 5,667,000 984 

M 959 5,760 ARCO and Elf Aquitaine 72 5,553,000 964 

M 955 5,760 ODECO, Koch and Santa Fe Energy 72 4,'778,000 830 

M 953 5,760 ODECO, Koch and Santa Fe Energy 72 3,642,000 632 

M 826 1,430 Placid 72 3,563,560 2,492 

M 961 5,760 Chevron and Union 72 2.572~000 447 II 

M 915 5,60 Chevron and Union 72 1,300,000 226 

M 958 5,760 Chevron and Union 72 1,300,000 226 

M 916 5,760 Chevron and Union 72 1,300,000 226 

M 917 5,760 Chevron and Union 72 1,227,000 213 

M 960 5,760 ARCO and Elf Aquitaine 72 1,053,000 183 

M 904 5,760 Union 72 900,000 156 

Subtotal 1983 40,785,560 

P 881 5,760 Conceo 79 957,000 166 I 

P 970 5,760 Conoco and Getty 79 1,214,000 211 

P 969 5,760 Conoco and Geay 79 1,515,000 263 

Subtotal 3,686,000 

M 869 

~ 

4,503 Geay, Conceo and Pennzoil 81 32,078,000 7,123 

M 913 5,760 Exxon 81 18,887,000 3,279 

IM 828 3,090 Exxon 81 10,302,000 3,334 

~M 912 5,760 Exxon 81 9,090,000 1,578 

IM 962 5,760 Getty, Conoco and Pennzoil 81 6,818,000 1,184 II 

M 872 5,760 Geay, Conoco and Pennzoil 81 3,518,000 611 I, 

M 1005 5,760 Geay, Conoco and Pennzoil 81 3,518,000 611 

M 1006 5,760 Getty, Conoco and Pennzoil 81 3,037,000 527 

M 873 5,760 Getty, Conoco and Pennzoil 81 2,518,000 437 

IM 829 2,775 Exxon 81 2,424,000 873 

1M 918 5,760 Getty 81 1,616,600 281 

M 865 5,760 Union 81 1,567,000 272 

M 830 2,909 Geay, Conoco and Pennzoil 81 1,518,000 522 I 

37 
Table 3.2 (continued) 

Leased Blocks in the Federal OCS Water Near Alabama's State Coastal Waters through 1985 

Offshore OCS Lease 

Block uoa Acres Original Lessee Sale no . Total Bonus 

M 860 5,760 Union, Chevron, Gulf and Pennzoil 

M 996 5,760 Conoco and Getty 

IM 1002 5,760 Union 

I, M 1003 5,760 Union 

~M 1004 5,760 ARCO and elf Aquitaine 

M 995 5,760 Conoco and Geay 

M 911 5,760 Exxon 

Subtotal 1984 

IP 471 5,760 ODECO, Murphy, Petrofina, Felmont and Minatome 

', P 925 5,760 ODECO, Murphy, Petrofina, Felmont and Minatome 

P 837G 2,828 Union 

I Subtotal 

i 

IM991 5,740 Conoco, Pennzoil and Amoco 

~i M 999 5,760 SOHIO, Petrofina and Monsanto 

M 992 5,760 Conoco, Pennzoil and Amoco 

M 1000 5,760 SOHIO, Petrofina and Monsanto 

IM 956 5,760 Conoco and Amoco 

IM 950 5,960 Union 

M 874 5,760 Union 

M 871 5,760 Conoco, Union, Pennzoil and Amoco 

M 948 5,760 Union 

M 1001 5,760 SOHIO, Petrofina and Monsanto 

M 914 5,760 Santa Fe and HNG 

M 994 5,760 SOHIO, Petrofina and Monsanto 

M 998 5,760 SOHIO, Petrofina and Monsanto 

M 951 5,760 Union and Chevron 

M 993 5,760 SOHIO, Petrofina and Monsanto 

M 949 5,760 Union 

'M 910 5,760 Exxon 

IM 997 5,760 Exxon 

IM 957 5,760 Exxon 

IM 90'1 5,760 Tenneco, ARCO, Elf Aquitaine, Murphy and ODECO 

Subtotal 1985 

81 

81 

81 

81 

81 

81 

81 

94 

94 

94 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

98 

1,351,000 

1,108,000 

989,000 

989,000 

920,000 

918,000 

909,000 

104,075,600 

1,020,000 

1,020,000 

454,000 

2,494, 000 

51,096,000 

27,137,000 

20,325,000 

12,625,000 

11,767,800 

11,260,000 

9,750,000 

7,657,000 

5,137,000 

5,127,000 

5,076,000 

4,256,000 

3,712,000 

3,660.000 

3,471,000 

2,875,000 

2,220,000 

1,614,000 

1,510,000 

1,459,000 

191,734,800 

per acre 

235 

192 

172 

172 

160 

159 

158 

177 

177 

161 

8,188 

4,711 

3,529 I 

2,192 

2 .043 

1,955 

1,693 

1,329 

892 

890 

881 

739 

644 

635 

603 

499 I, 

385 

280 i 

262 I 

253 

,TOTAL OF ALL LEASES 562,365,263 

i M - Mobile Area, P - Pensacola Area (western area only). 

All Federal blocks have a primary lease term of 5 years, an annual rental of $3.00 per acre, and a royalty payment of 16.67 percent. 

Source : U .S . Department of the Interior, Minerals Management Service, 1998 ; 

Alabama Oil and Gas Board, 1986. 

38 
3 .3 State Lease Sale #2 - 1982 and OCS Sale 72 - 1983 

The state had a second lease sale in September 1982 . Table 3 .3 shows that nine bids were 

received for six tracts ; only $12.5 million was exposed and only one tract, 110, north of federal 

tract 822, was leased to MOEPSI's group for $3 .1 million with a 25 percent royalty . Shell bid 

$1 .7 million for tract 114, well under Exxon's rejected bid in 1981, and the state rejected the 

offer for the second time. MOEPSI's winning bid for tract 110 was the only bid over $2,000 

per acre . 

MMS had a second small sale in May 1983 at which the highest bid tract was $7.9 million for 

tract 863 . Tenneco and a group comprised of ARCO, Murphy, ODECO and Elf leased this tract 

adjoining Tenneco's tract 864 that was leased the year before . Union and Chevron acquired 

tracts 904, 916 and 961 for bids near $1 .0 million that subsequently became Norphlet 

discoveries. The highest bid per acre, $2,492, came for tract 826, adjoining Exxon's tracts 114 

and 115, west of Exxon's 827 . Total accepted bids amounted to $40 .8 million as shown on 

Table 3 .2. 

A number of tracts were bought for their Miocene prospects. Bids in the range of $5 .0 million 

were received for tracts 952, 955, and 959, which became producing Miocene properties. 

3.4 State Lease Sale #3 and OCS Sale 81 - 1984 

Two important lease sales in 1984 added to the Alabama acreage available for exploration: OCS 

Lease Sale 81, April 1984; and state Lease Sale #3, August 1984 . Table 3 .2 shows that Sale 

81 leased 20 federal tracts in Coastal Alabama for $104 .1 million. The highest bid, $32.1 

million, was paid for tract 869, just south of Shell's state tract 132 . Getty (now Texaco), 

Conoco and Pennzoil acquired this tract. Getty, bidding alone and with this group, acquired ten 

leases to become the most active participant. Exxon was the second most active, winning the 

second highest bid tract, 913, for $18 .9 million, and adding to its acreage south of state tracts 

115 and 116 by acquiring tracts 828 and 829 for $12.7 million. Exxon acquired a total of five 

tracts . MOEPSI acquired none . 

State Lease Sale #3 exposed $493 .2 million and awarded 19 state tracts for $347 .5 million plus 

royalties of between 16 .67 and 20 percent, as shown on Table 3 .4 . Exxon dominated the sale, 

with high bids of $289.8 million accepted by the state for 14 tracts . Exxon's highest two bids 

were $53 million for tract 114 and $46 million for tract 78 . Exxon acquired all the state acreage 

surrounding their 1981 leases . The state, which had rejected an $8 .4 million bid from Exxon 

in 1981 for tract 114, clearly benefitted by its strategy as tract 114 received the highest bid in 

the 1984 sale . In fact, the state bettered its financial position by $247.6 million on the bids for 

tracts it rejected in 1981 and 1982, as shown on Table 3 .5 . Exxon contributed $238.8 million 

of the increase in bids . 

Mobil acquired no new acreage in the sale, bidding on only five tracts and bidding an average 

of 6 .4 percent of Exxon's winning bids for tracts 78, 91, 92, 93, and 96 as shown on Table 3 .6. 

39 
Table 3.3 

Bids Received for the September 1982 State Lease Sale 

State 

Block No. Acreage Bidder Total Bonus 

$ 

Bonus Per 

Acre 

$ 

Royalty Result' 

91 4,991 Pennzoil 1,500,000 300.54 25 R 

92 5,164 Shell 1,033,000 200.04 25 R 

93 4,723 Exxon 1,408,000 298.12 25 R 

Shell 1,047,000 221 .68 25 R 

109 2,329 SOHIO 852,577 366.07 25 R 

110 1,295 MOEPSI, Getty & Concoco 3,117,000 2,406.95 25 A 

Exxon 1,206,000 931 .27 25 R 

Chevron 611,000 471 .81 25 R 

114 4,782 Shell 1,713,000 358.22 25 R 

Total Industry Exposure 12,487,577 

' R - rejected; A - accepted 

Source: Alabama Dept. of Conservation and Natural Resources, 1997; 

Alabama Oil and Gas Board, 1986 

40 
Table 3.4 

Bids Received for the August 1984 State Lease Sale 

State 

Block No. Acreage Bidder Total Bonus 

$ 

Bonus Per 

Acre 

$ 

Royalty' Rcsult2 

13 4,650 Exxon 1,412,000 303.66 16 .67 R 

14 5,165 Exxon 2,723,000 527.20 16.67 A 

40 5,040 Exxon 1,212,000 240.48 16.67 R 

50 5,165 Exxon 1,518,000 293.90 16.67 R 

51 5,165 Exxon 1,413,000 273.57 16.67 R 

59 4,665 Exxon 4,244,000 909.75 20 A 

Conoco and Getty 1,212,000 259.80 20 R 

64 5,165 Exxon 32,828,000 6,355 .86 20 A 

Conoco and Getty 1,414,000 273.77 20 R 

73 4,795 Exxon 12,624,000 2,632 .74 20 A 

Pennzoil & Total Pet. 12,000,014 2,502 .61 20 R 

ARCO 6,095,000 1,271 .16 20 R 

Tenneco 2,496,000 520.54 20 R 

Conoco and Getty 1,111,000 231 .70 20 R 

78 4,980 Exxon 45,972,000 9,231 .33 20 A 

Conoco and Geay 3,416,000 685.94 20 R 

Shell 1,674,000 336.14 20 R 

Amoco 1,215,120 244.00 20 R 

MOEPSI 1,027,500 206.33 20 R 

79 4,438 Exxon 1,313,000 295.85 16 .67 R 

Amoco 1,127,252 254.00 16 .67 R 

88 5,131 SOHI0 7,610,000 1,483 .14 16 .67 A 

Conoco and Getry 3,213,000 626.19 16 .67 R 

91 5,012 Exxon 16,540,000 3,300 .08 20 A 

Union and Pennzoil 7,360,000 1,468 .48 20 R 

MOEPSI, Conoco, 2,127,000 424.38 20 R 

Getty and AGIP 

92 5,165 Exxon 39,672,000 424.38 20 A 

Union, Pennzoil & Pogo 15,350,000 7,680 .93 20 R 

MOEPSI, Conoco, 5,203,300 2,971 .93 20 R 

Getty and AGIP 

93 4,831 Exxon 39,364,000 8,148 .21 20 A 

Union, Pennzoil & Pogo 8,350,000 1,728 .41 20 R 

MOEPSI, Conoco, 2,027,000 419.58 20 R 

Getty and AGIP 20 R 

SOHIO 1,259,000 260.61 20 R 

Shell 989,000 204.72 20 R 

96 4,093 Exxon 43,738,000 10,686 .05 20 A 

Union 5,889,000 1,438 .80 20 R 

Conoco and Getty 2,317,000 566.08 20 R 

Shell 1,674,000 408.99 20 R 

MOEPSI 1,527,500 373 .20 20 R 

41 
Table 3.4 (Continued) 

Bids Received for the August 1984 State Lease Sale 

State Bonus Per 

Block No. Acreage Bidder Total Bonus Acre Royalty' Resutt2 

$ $ 

97 3,395 Exxon 14,634,000 4,310.46 16.67 A 

98 3,652 Exxon 6,664,000 1,824.75 16.67 A 

99 2,770 Exxon 608,000 219.49 16.67 R 

109 2,511 SOHIO 1,100,000 438.07 16.67 A 

Getty 555,200 221 .11 16 .67 R 

114 4,807 Exxon and Louisiana Hunt 52,984,000 11,022 .26 16 .67 A 

Union, Pennzoil & Pogo 15,370,000 3,197 .42 16 .67 R 

Shell and Amoco 11,326,000 2,356.15 16 .67 R 

Conoco and Getty 5,419,000 1,127 .31 16 .67 R 

117 3,541 Eon 14,428,000 4,074.56 16 .67 A 

Union 3,367,000 950.86 16 .67 R 

Amoco 1,157,907 327.00 16 .67 R 

Conoco and Getty 1,121,000 316.58 16 .67 R 

118 3,669 Union and Pogo 9,310,000 2,537.48 16 .67 A 

Exxon 7,572,000 2,063 .78 16 .67 R 

Amoco 1,185,087 323 .00 16.67 R 

Conoco, Getty and Pennzoil 1,127,000 307 .17 16 .67 R 

119 2,945 Exxon 1,820,000 618 .00 16 .67 A 

131/133 1,535 Exxon and Louisiana Hunt 1,228,000 800.00 16 .67 A 

Total Accepted Bids 347,483,000 

Total Industry Exposure 493,232,880 --I 

'Escalates to 25 percent on payout. 

ZR - rejected; A - accepted 

Source: Alabama Dept . of Conservation and Natural Resources, 1997 ; 

Alabama Oil and Gas Board, 1986 

42 
Table 3.5 

1981 & 1982 Rejected State of Alabama Bids Compared to 1984 Bids 

State 

Block No . Acreage Bidder __ 

1981-1982 

Total Bonus 

Bonus 

per Acre 

Royalty 

% Result Acreage Bidder 

1984 

Total Bonus 

Bonus 

r Acre 

Royalty 

% Result 

Gain 

to State 

114 4,782 Exxon 8,608,000 1,800 25 R 4,807 Exxon and Louisiana Hunt 52,984,000 11,022 16 .67 A 44,376,000 

92 5,164 Naromas 3,000,000 581 25 R 5,164 Exxon 39,672,000 7,680 16 .67 A 36,672,000 

93 4,823 Conoco,etal. 3,713,000 770 28 .7 R 4,831 Exxon 39,364,000 8,148 20 A 35,651,000 

64 5,164 SunIitelnternational,lnc . 581,040 113 26.1 R 5,165 Exxon 32,828,000 6,356 20 A 32,246,960 

91 5,010 Pennzoil and Naromas 5,105,000 1,019 30 R 5,012 Exxon 16,540,000 3,300 20 A 11,435,000 

97 3,217 Hunt and SOH10 2,100,701 653 34 R 3,395 Exxon 14,634,000 4,310 16.67 A 12,533,299 

117 3,479 Hunt and SOH10 1,612,518 464 34 R 3,541 Exxon 14,428,000 4,075 16.67 A 12,815,482 

73 3,690 Shell 5,674,000 1,538 25 R 4,795 Exxon 12,624,000 2,633 20 A 6,950,000 

118 3,429 Exxon 1,102,000 321 25 R 3,669 Union and Pogo 9,310,000 2,537 16 .67 A 8,208,000 

88 5,112 Getty, Conoco,etal. 7,427,736 1,453 26 .7 R 5,131 SOH10 7,610,000 1,483 16 .67 A 182,264 

98 3,697 Hunt and SOH10 2,101,745 569 34 R 3,652 Exxon 6,664,000 1,825 16 .67 A 4,562,255 

59 4,720 Getty, Conoco,etal. 722,160 153 25 R 4,665 Exxon 4,244,000 910 20 A 3,521,840 

110 1,295 Getty, Conoco,etal. 2,878,000 2,222 25 R 1,295 MOEPSI, Getty & Conoco' 3,117,000 2,407 25 A 239,000 

109 2,329 Sohio 852,577 366 25 R 2,511 Sohio 1,100,000 438 16 .67 A 247,423 

96 4,093 First Energy Corp . 5,751,000 1,500 25 R 4,093 Exxon 43,738,000 10,606 20 A 37,987,000 

Exxon Subtotal 277, 720, 00'0 238, 750, 836 

- 

Total 

- 

51,229,477 

- 

298,857,000 249,627,523 

Source: Alabama Dept . o[ Conservation and Natural Resources, 1997; 

Alabama Oil and Gas Board, 1986 

W 
Exxon Exploration VP W. J. Wood was quoted in OGJ, "[Exxon] bid aggressively . . . because 

of its belief that the gas market will improve ."" Seemingly, Mobil and Exxon had different 

views of the gas market, if not the geology. Tract 78 became part of Bon Secour Bay Field. 

The 1986 re-ordering of world energy prices cancelled any beliefs about improved market 

conditions . 

Table 3.6 

Comparison of 1984 Bids in State Sale #3 

($ Million) 

Tract Exxon Mobil 

78 46 .0 1 .0 

91 16 .5 2 .1 

92 39 .7 5 .2 

93 39 .4 2 .0 

96 43 .7 1 .5 

Total 185 .3 11 .8 

Mobil % of Exxon 6 .4% 

Source : Table 3 .4 

3.5 OCS Lease Sale 98 - 1985 

Disappointing March and April 1985 exploration results in federal tracts 826, 909, and 864 did 

not dampen enthusiasm for MMS Lease Sale 98, May 22, 1985 . Table 3 .2 shows that 20 tracts 

were acquired for $191 .7 million in the Mobile OCS during this area wide sale in the Central 

Planning Region of the Gulf. The winning bids totalled nearly 90 percent more than the industry 

paid for 20 Mobile OCS tracts in the 1984 federal sale. The Conoco group acquired the highest 

bid tract of the entire sale, 991, which is in the Norphlet play, south of Mississippi . The highest 

bid three tracts of the entire sale, 991, 999, and 992 were Norphlet tracts . OG7 reported that 

Shell was the top bidder in the area wide sale, but Shell positioned itself in the deep water tracts 

of the Gulf and the Main Pass at the mouth of the Mississippi. Shell bid low on nine Mobile 

tracts and acquired none . Shell's only holdings in the Mobile area remained tracts 113 and 132. 

From an early position in Mobile Bay gas exploration, Shell shifted its focus to the deep water 

Gulf.sl 

soOGJ, "Exxon leads spending in Mobile Bay lease sale," August 27, 1984, p. 30. 

"Shell's deepwater discoveries to-date-Auger, Brutus, Bullwinkle, Cognac, Mars, Mensa, Popeye, 

Ram-Powell, Rocky, Tahoe, Tahoe II, and Ursa-confirm that Shell shifted its attention from the 

Norphlet to another frontier play that required exploitation of specialized, but different, technology from 

44 
Table 3 .2 shows that Conoco, Amoco, and Sohio were the largest players in Norphlet tracts of 

Sale 98 . Although Exxon only acquired three tracts, Exxon remained the largest lessee in 

Coastal Alabama. MOEPSI did not bid for new acreage in the sale . Chevron and Unocal added 

to their holdings on the eastern and western edges of the Alabama OCS Norphlet play . 

3.6 State and Federal Coastal Alabama Sales: After 1985 

Several small to moderate Coastal Alabama state and federal sales have occurred since 1985 . 

Results are shown on Tables 3 .7A and 3 .7B. The state captured $61 .0 million more, mostly 

from MOEPSI for the lease of tract 75, which was subsequently drilled and unitized as the Aloe 

Bay Field. This brought the state's bonuses for lease sales to $861 million. 

A substantial amount of federal real estate in the Mobile Bay OCS changed hands after 1985 for 

only $13 .3 million, with Chevron and Union acquiring the bulk of it . This brought federal 

bonus collections to $576 million from Coastal Alabama tracts . 

Chevron leased federal tracts 819 and 820 for very low bids in 1988 when the "gas bubble" and 

low prices plagued the gas industry . Norphlet gas has been discovered under both 819 and 820 ; 

production ramped up in 1997 . Conoco's $51 million tract 991 from Lease Sale 98 was 

explored by Conoco, as will be discussed in the next section, and turned back to MMS. 

Chevron acquired it in Lease Sale 152 for $2 .6 million. 

3 .7 Industry Leases: 1997 

By the end of 1997, industry had invested a total of $1 .4 billion in Coastal Alabama as shown 

on Table 3.8 by company. Exxon led the industry with $573 million for 147,616 acres, 

including the highest price tract of all sales, tract 112 at $137 .3 million. Union and Chevron 

were the next largest individual lessees, holding between them more acreage than Exxon. 

Conoco and Sohio appear on the table as the fourth and fifth largest lessees, but their leases have 

mostly expired or otherwise changed hands. 

Union and Chevron lead the Norphlet players in the lowest average price per acre under 

lease-$757 and $774 . Getting a later start, they began leasing Norphlet tracts after gas prices 

had declined, spending at most $23.6 million for tract 861, which proved to be a large Norphlet 

discovery . Union and Chevron spent twenty cents per acre for each dollar Exxon spent. 

Figure 3 .3 shows the leased positions as of 1995 . 

3.8 Alabama's Stake in the Bonus and Royalty Payments 

The bonus payments collected in conjunction with offshore lease sales are a significant source 

of revenue to the State of Alabama. Bonus payments from the mid-1950s to 1979 came to just 

the Norphlet. See USDOI, MMS (1997), "Deepwater in the Gulf of Mexico : America's New Frontier," 

OCS Report MMS 97-0004, New Orleans, February 1997 . 

45 
Table 3.7A 

Leased Blocks in State of Alabama Waters, 1988 -1997 

Offshore Lease -- Bonus Rental 

Block no. Date Original Lessee Total Bonus per acre per acre Royalty 

s a 

57 02/23/88 OGII 646,000 500.29 2.50 20% 

71 02/23/88 OGII 646,000 500.29 2.50 20% 

72 02/23/88 Callon' 225,000 174.25 2.50 20% 

73 02/23/88 Callon' 1,536,000 1,251 .20 2.50 20% 

73 02/23/88 Callon' 265,000 205.23 2.50 20% 

73 02/23/88 Callon' 988,000 1,003.22 2.50 20% 

90 02/23/88 OEDCJ 134,000 127.74 2.50 20% 

90 02/23/88 Northern Michigan Ezpl . Co . 134,290 104.00 2.50 20% 

91 02/23/88 ARCO 356,000 312.42 2.50 20% 

91 02/23/88 OEDCI 165,000 127.91 2.50 20% 

73 07/19/88 Shell/Amoco 3,873,000 807.72 5.00 16.67 

74 07/19/88 Shell/Amoco 4,373,000 1,138.21 5.00 20% 

75 07/19/88 MOEPSI 25,178,000 10,189.40 5.00 25 

91 07/19/88 Shell/Amoco 843,000 168.20 5.00 16.67% 

92 07/19/88 Shell/Amoco 8,377,000 1,621.88 5.00 16.67% 

93 07/19/88 Shell/Amoco 10,388,000 2,150.28 5.00 16.6786 

Subtotal 1988 58,127,290 

60 12/29/93 MOEPSI 1,322,208 535.09 

61 12/29/93 MOEPSI 1,564,086 632.98 

110 12/29/93 BSFI Western E&P Inc. 12,950 5.24 

Subtotal 1993 2,900,417 

71 12/10/97 MOEPSI 1,317,075 255.00 

88 12/10/97 MOEPSI 1,949,780 380.00 

89 12/10/97 MOEPSI 1,902,285 405.00 

90 12/10/97 MOEPSI 1,512,875 325.00 

Subtotal 199 6,682,015 

Total of State Leases 67,709,722 

I Formerly Arco 

Source : Alabama Dept. of Conservation and Natural Resources, 1988 ; 1997 . 

46 
Table 3.7B 

Leased Blocks in the Alabama OCS, 1988-1997 

I Offshore OCS Lease Bonus 

Block no . Original Lessee Sale no. Total Bonus per acre 

- s a 

MO 819 Chevron 118 65,000 27 .90 

MO 820 Chevron 118 1,207,000 359.22 

MO 910 Union 118 288,600 50 .10 

MO 954 Union 118 151,300 26 .26 

MO 859 Chevron/Union 123 146,000 2534 

MO 873 Miuphy/ODECO 123 622,222 108.02 

MO 909 Murphy/ODECO 123 994,444 172.65 

MO 911 Union 123 73,440 25 .50 

~M0912 Murphy/ODECO 123 338,888 58 .83 

Z 

MO 913 Murphy/ODECO 123 458,888 79 .67 

918 Chevron/Offshore Bech[el 123 175,800 30 .52 

MO 962 Union/Chevron/Offshore Bechtel 123 149,000 25 .86 

'MO 826 Unocal/Offshore Bechcel 131 27,786 26 .25 

MO 871 Unocal/Chevron/Offshore Bechtel 131 201,600 35 .00 

MO 957 Unocal/Chevron/Offshore Bechtel 131 155,520 27 .00 

M0866 OEDC 142 152,640 26.50 

~ MO 874 Murphy 142 589,900 102.41 

MO 956 Chevron/Offshore Bechtel 142 236,909 41 .13 

MO 902 MOEPSI 147 276,800 48.06 

MO 944 Chevron 152 181,843 31 .57 

MO 987 Chevron 152 114,302 27 .57 

IMO 988 Chevron 152 187,603 32 .64 

1MO 991 Chevron 152 2,598,854 451.19 

I,MO 992 Chevron 152 418,579 72 .67 

HMO 993 Chevron 152 187,603 32 .57 

MO 1004 UnionlChevron/Offshore Bechtel 152 161,914 28 .11 

MO 1005 Union/Chevron/Offshore Bechtel 152 194,169 33 .71 

MO 1006 Union/Chevron/Offshore Bechtei 152 198,144 34 .40 

MO 873 Huntington Beach 157 329,875 57 .27 

MO 913 Chiefron 157 612,864 106.40 

IM01002 Vastar/E1fBechtel 157 227,900 39 .57 

IM01003 Vastar/EIfBechtel 157 227,800 39 .55 

IMO 946 Chevron 166 208,851 36 .26 

'M0951 Shell 166 178,000 30 .90 

MO 989 Zilkha 166 191,520 33 .25 

MO 997 Callon/Murphy/Santos 166 565,500 98 .18 

MO 998 Callon/Murphy/Santos 166 209,900 36 .44 

Total of Federal Leases 1988 -1997 13,306,958 

i 

Source: U.S . Dept. of the Interior, Minerals Management Service, 1998. 

47 
Table 3 .8 

Coastal Alabama Leases : 1997 

Exxon 

Lease 

Sale no. 

Total Bonus 

Payments Bonus 

1 

1 

3 

3 

3 

3 

81 

3 

3 

1 

3 

3 

3 

3 

1 

1 

81 

1 

81 

67 

3 

3 

3 

81 

98 

3 

98 

98 

3 

67 

67 

81 

67 

112 4,932 137,254 27,829 

111 1,687 53,168 31,516 

114 4,807 52,984 11,022 

78 4,980 45,972 9,231 I 

93 4,831 39,364 8,148 

64 5,165 32,828 6,356 

M 913 5,760 18,887 3,279 

116 3,254 18,323 5,603 

91 5,012 16,540 3,300 

63 5,164 15,226 2,948 

97 3,395 14,634 4,310 I 

117 3,541 14,428 4,075 

117 3,541 14,428 4,075 

73 4,795 12,624 2,633 

115 3,416 12,308 3,603 

62 5,164 10,522 2,038 

M 828 3,090 10,302 3,334 

52 5,164 9,112 1,765 

M 912 5,760 9,090 1,578 

M 867 5,760 6,747 1,171 

98 3,652 6,664 1,825 

59 4,665 4,244 910 

14 5,165 2,723 527 

M 829 2,775 2,424 873 

M 910 5,760 2,220 385 

119 2,945 1,820 618 

M 997 5,760 1,614 280 

M 957 5,760 1,510 262 

131/133 1,535 1,228 800 

M 866 5,760 1,211 210 

M 868 5,687 1,014 178 

M 911 5,760 909 158 

M 827 3,174 718 226 

Union, et al 

Subtotal 147,616 573,040 3,882 

1 90 4,612 21,879 4,744 ', 

98 M 950 5,760 11,260 1,955 I, 

98 M 874 5,760 9,750 1,693 

3 118 3,669 9,310 2,537 

98 M 948 5,760 5,137 892 

98 M 951 5,760 3,660 635 

98 M 949 5,760 2,875 499 I 

81 M 865 5,760 1,567 272 

81 M 860 5,760 1,351 235 

81 M 1003 5,760 989 172 

81 M 1002 5,760 989 172 

48 
Table 3.8 (continued) 

Coastal Alabama Leases: 1997 

Lease 

Bidder Sale no. Block No. Acreage 

Total Bonus 

Payments 

($1000) 

Bonus 

per Acre ' 

IUnion, Cont'd 72 M 904 5,760 900 156 

69 M 905 5,760 882 153 

94 P 837G 2,828 454 161 

118 M 910 5,760 289 50 

118 M 954 5,762 151 26 

123 M 962 5,762 149 26 

', 123 M 911 2,880 73 26 

152 M 1004 5,760 162 28 

152 M 1005 5,760 194 34 

I 152 M 1006 5,760 198 34 

Subtotal 111,913 72,219 645 

Chevron, Union and Pennzoil I 

67 M 861 5,198 23,616 4,543 j 

67 M 862 5,618 17,616 3,135 

72 M 961 5,760 2,572 447 

67 M 906 5,760 2,110 366 

72 M 916 5,760 1,300 226 

72 M 958 5,760 1,300 226 

72 M 915 5,760 1,300 226 

72 M 917 5,760 1,227 213 

118 M 820 3,360 1,207 359 

142 M 956 5,760 237 41 

123 M 918 5,760 176 31 

123 M 859 5,762 146 25 

118 M 819 2,330 65 28 

152 M 944 5,760 182 32 

152 M 987 4,146 114 28 II 

I 152 M 988 5,748 188 33 

152 M 991 5,760 2,599 451 i 

152 M 992 5,760 419 73 I 

152 M 993 5,760 188 33 

j 166 M 946 5,760 209 36 

Subtotal 107,041 56,769 530 I 

Conoco, Amoco, Getty & Pennzoil 

98 M 991 5,740 51,096 8,902 

98 M 992 5,760 20,325 3,529 

98 M 956 5,760 11,768 2043 , 

98 M 871 5, 760 7 ,657 1,329 

79 P 969 5,760 1,515 263 

79 P 970 5,760 1,214 211 

81 M 996 5,760 1,108 192 

I 79 P 881 5,760 957 166 I 

81 M 995 5,760 918 159 

Subtotal 51,820 96,558 1,863 

49 
Table 3 .8 (continued) 

Coastal Alabama Leases : 1997 

Total Bonus 

Lease Payments Bonus 

~iBidder Sale no. Block No. Acreage ($1000) per Acre 

SOHIO, et al j 

3 89 4,811 42,712 8,878 I~ 

98 M 999 5,760 27,137 4,711 

98 M 1000 5,760 12,625 2,192 

3 88 5,131 7,610 1,483 I 

98 M 1001 5,760 5,127 890, 

98 M 994 5,760 4,256 739 

', 98 M 998 5,760 3,712 644 

98 M 993 5,760 3,471 603 

67 M 821 4,028 3,000 745 

3 109 2,511 1,100 438 

Subtotal 51,041 110,750 2,170 

MOEPSI, et al 

67 M 779, 823, 824 5,585 55,119 9,856 

67 M 778, 822 5,324 45,117 8,471 

1 71 4,196 40,425 9,634 !, 

1 72 5,164 31,535 6,107 

4 75 2,471 25,178 10,189 

2 110 1,295 3,117 2,407 

1993 61 2,471 1,564 633 

1993 60 2,471 1,322 535 

1969 77 5,165 26 5 

1969 76 5,053 21 4 I 

1969 95 4,322 20 5 

', 1969 94 5,155 12 2 

I 1997 71 5,165 1,317 255 

1997 88 5,131 1,950 380 

1997 89 4,697 1,902 405 

1997 90 4,655 1,513 325 

147 M 902 5,759 277 48 

Subtotal 74,079 210,415 2,840 I 

Texaco (Getty), et al 

81 M 869 4,503 32,078 7,123 

81 M 962 5,760 6,818 1,184 

', 81 M 1005 5,760 3,518 611 I 

81 M 872 5,760 3,518 611 

81 M 1006 5,760 3,037 527 

81 M 873 5,760 2,518 437 I 

81 M 918 5,760 1,617 281 'i 

81 M 830 2,909 1,518 522 

Subtotal 41,973 54,622 1,301 

Shell 

1 113 5.123 34,370 6,709 

50 
Table 3.8 (continued) 

Coastal Alabama Leases: 1997 

Bidder 

Lease 

Sale no. Block No. Acreage 

Total Bonus 

Payments 

$1000 

Bonus 

r Acre 

Shell, Cont'd 67 M 909 5,760 28,277 4,909 

1 132 2,367 22,435 9,478 

4 93 4,831 10,388 2,150 

4 92 5,165 8,377 1,622 ' 

4 74 3,842 4,373 1,138 

4 73 4,795 3,873 808 I 

', 4 91 5,012 843 168 

166 M 951 5,761 178 31 

Subtotal 42,656 113,114 2,652 

ODECO, et al I 

72 M 952 5,760 5,667 984 

72 M 955 5,760 4,778 830 

72 M 953 5,760 3,642 632 

94 P 971 5,760 1,020 177 

94 P 925 5,760 1,020 177 

I Subtotal 28,800 16,127 560 

I Murphy/ODECO 

123 M 909 5,760 994 173 

123 M 873 5,760 622 108 

142 M 874 5,760 590 102 

123 M 913 5,760 459 80 

123 M 912 5,760 339 59 

Subtotal 28,801 3,004 104 I 

ARCO, et al 

67 M 908 5,760 24,198 4,201 

72 M 959 5,760 5,553 964 'I 

72 M 960 5,760 1,053 183 I 

81 M 1004 5,760 920 160 

4 91 1,139 356 312 

Subtotal 24,179 32,080 1,327 

UnocaUOffshore Bechtel 

131 M 826 1,059 28 26 I 

142 M 866 5,760 153 27 

131 M 957 5,760 156 27 'I 

131 M 871 5,760 202 35 

Subtotal 18,339 538 29 

Tenneco, et al 

72 M 863 5,760 7,930 1,377 ; 

67 M 864 5,760 4,880 847 

98 M 907 5,760 1,459 253 I 

Subtotal 17,280 14,269 826 ~I 

51 
Table 3.8 (continued) 

Coastal Alabama Leases : 1997 

Placid 

Lease 

Sale ni 

67 

72 

Santa Fe and HNG 

98 

jCallon 

I 4 

4 

4 

4 

166 

166 

I OGI 

OEDC 

4 

4 

Block No. 

M 870 

M 826 

Subtotal 

M 914 

73 

73 

73 

72 

M 997 

M 998 

Subtotal 

57 

71 

Subtotal 

4 90 

4 91 

142 M866 

Subtotal 

Northern Michigan Exp. Company 

4 90 

IBSFI Western E&P Inc. 

1993 61 

Miscellaneous Operators 

157 M 873 

157 M 913 

157 M 1002 

157 M 1003 

166 M 989 

Subtotal 

Total Bonus 

Payments Bonus 

5,618 5,085 905 

1,430 3,564 2,492 

7,048 8,648 1,227 I 

5,760 5,076 881 'I 

1,228 1,536 1,251 

985 988 1,003 

1,291 265 205 

1,291 225 174 

5,760 566 98 I 

5,760 210 36 

16,315 3,789 232 

1,291 646 500 

1,291 646 500 

2,583 1,292 500 

1,049 134 

1,290 165 

5,760 153 

8,099 452 

1,291 134 

2,471 13 

5,760 330 

5,760 613 

5,759 228 

5,760 228 

5,760 192 

28.799 1 .590 

Source : Foster Associates, Inc . 1997; Alabama Dept. of Conservation and Natural Resources, 1997; 

Alabama Oil and Gas Board, 1986 

128 

128 

27 

56 

104 

5 

57 

106 

40 

40 

33 

55 

1,681 

52 
0 MILES 8 

MOBILE BAY AREA 

LEASE ACTIVITY MAP 

m I 

0 KILOMETERS iZ~ 

BELLIN(SRATN 

GARDENS 

_` 

Exxon Plant 

BAYOU Shell Plant 

L 

A 

BATR 

6 Mobll Plant MOBILE BAY 

. . . .11SSi .r 

r 

1 

NORTHWEST GULF FIELD 

I '- ICI (BP) 821 FIELD 

MO 823 FIELD 

MO 908 FIELD 

I 

INT CLEAR =MOBIL 

EXXON 

CHEVRON 

=UNOCAL 

=SHELL 

=MURPHY 

=CONOCO 

MII SANTA FE 

MBP 

OEDC 

=PENNZOIL 

80N SECOUR BAY FIELD 

ANN FIELD 

FAIRWAY FIELD 

X10 827 

NORTH CENTRAL GULF FIELD 

State __,_ . 

--------- "~Federol 

MO 872 FIELD 

an e 

M0 916 FIELD 

ALOE BAY FIELD 

M0 869 FIELD 

w 

Figure 3 .3 . Mobile Bay Area Lease Activity Map, January 1995 . 

Source: MOEPSI, 1997 . 
over $500,000 ; bonus payments since 1979 total $868 million from four lease sales since gas 

was discovered in Mobile Bay in 1979 : 1981, 1982, 1984, and 1988 . By far the largest bonus 

collections, almost $450 million, occurred in 1981 . Only one bid was accepted in the 1982 lease 

sale, garnering almost $3 .2 million. The 1984 sale collected bonus payments of almost $350 

million. In 1988, Alabama received about $58 million; three tracts were leased in 1993 for $3 .0 

million; four tracts were leased in 1997 for $6.7 million. 

After the 1981 lease sale, Alabama politicians were bedazzled by the bonus bonanza, which they 

viewed as a "one-time thing. . . . a once in a lifetime opportunity to solve the majority of 

problems facing the State of Alabama, Governor [Fob James] said" in April 1981 . Governor 

James articulated a list of capital projects from prisons to bridges and a controversy emerged as 

to how to spend the money .12 The Senate approved a resolution by Senator H. L. "Sonny" 

Callahan of Mobile "to set the money aside in an invested trust fund and spend only the . . 

interest . . . . [leaving] a legacy for the future . . . . Governor James expressed `serious 

reservations' about the Callahan proposal at a later press conference."" Governor James 

subsequently proposed to the state legislature that a perpetual trust fund be established to ensure 

that the State of Alabama would continue to benefit from the bonus proceeds. 

3.8.1 Trust Funds Preserve Money for the Future 

The Heritage Trust Fund was established after the 1981 lease sale (March 17, 1982). Provisions 

of the trust fund require that only the interest be distributed for statewide use . A second fund, 

the Alabama Trust Fund, was ratified December 10, 1984 following the 1984 lease sale . At that 

time all future royalty payments were directed to the Alabama Trust Fund, with provisions 

similar to the earlier fund-that only the annual interest accrued could be spent. In 2001 the 

Heritage Trust Fund will be rolled into the Alabama Trust Fund so that only one fund is 

maintained. 

In FY 1996, the corpus balance of the Heritage Trust Fund was almost $467 million. Table 3 .9 

shows that the Alabama Trust Fund capital balance stood at about $874 million, having grown 

with the receipt of state royalty payments and the state's 27 percent share of 8(g) federal royalty 

payments from producing federal leases within 8 miles of Alabama land. Since 1986, the annual 

interest from both funds averaged near $100 million." The majority of annual interest earned 

is transferred into the state's General Fund, where it has amounted to between 11 - 12 percent 

of the state's General Fund budget in recent years. 

Beginning with fiscal year 1992-1993, a percentage of interest earned from the Alabama Trust 

Fund is transferred to the Forever Wild Trust Fund, a fund established as part of the Forever 

Wild Program for the acquisition of lands for public use . In FY 1993 payments to the fund 

52 "Storm brewing over fate of lease funds," Birmingham Post Herald, April 3, 1981 . 

13 "Storm brewing over fate of lease funds," Birmingham Post Herald, April 3, 1981 . 

54 Alabama Dept. of Conservation and Natural Resources, 1997. 

54 
Table 3.9 

State of Alabama Oil and Gas Trust Fund Balances and Interest Earned 

(Millons $) 

Fiscal Year 

Alabama 

Trust Fund 

Corpus Balance 

Heritage 

Trust Fund 

Corpus Balance 

Total 

Corpus Balance 

of Trust Funds 

Alabama 

Trust Fund 

Interest to GF 

Heritage 

Trust Fund 

Interest to GF 

Total 

Trust Fund 

Interest to GF 

Forever Wild 

Trust Fund 

Pa menu 

1984-1985 $334.0 $479.8 $813 .8 $7 .8 $66.7 $74.5 - 

1985-1986 $399.9 $479.8 $879.7 $39.8 $61 .0 $100.8 -- 

1986-1987 $400.6 $479.8 $880.4 $39.2 $59.9 $99.1 -- 

1987-1988 $455.2 $479.8 $935 .0 $39.0 $58 .8 $97.8 -- 

1988-1989 $460.2 $467.3 $927 .5 $45 .3 $60.8 $106 .1 -- 

1989-1990 $465.9 $466.8 $932.7 $44.9 $54.4 $99.3 -- 

1990-1991 $472.1 $466.8 $938.9 $44.7 $60.8 $105 .5 -- 

1991-1992 $501 .2 $466.8 $968.0 $42 .7 $50.9 $93.6 -- 

1992-1993 $571 .5 $466.8 $1,038 .3 $41.8 $55.7 $97.6 $1 .8 

1993-1994 $677.7 $466 .8 $1,144 .5 $40.6 $51 .8 $92.4 $2.1 

1994-1995 $757.4 $466 .8 $1,224 .2 $47.5 $51 .9 $99.4 $3.0 

1995-1996 $873 .6 $466 .8 $1,340 .4 $50.6 $51 .8 $102.4 $3.8 

Source : Alabama Dept. of Conservation and Natural Resources, 1997 . 

v~ 
totalled $1 .8 million; payments increased to $3 .8 million in FY 1996. After FY 1998, 10 

percent of the annual earnings from the Alabama Trust Fund will be directed to Forever Wild, 

not to exceed $15 million in any fiscal year. 

3 .8.2 Royalty Payments Have Added to Alabama Trust Fund 

Royalty payments to the state totalled $354 million through year end 1996 as shown on Table 

3 .10. Norphlet production accounted for $301 million, with Exxon providing the most, $147 

million, and Shell second at $113 million. Miocene royalty payments amounted to only $17 

million. Federal 8(g) payments amounted to $36 million by year end 1996. These payments 

include production from the federal share of BP's 821 Field, MOEPSI's 823 Field, and Exxon's 

827 Field. These will increase in 1997 to reflect MOEPSI's production from the 869 Field and 

Chevron's production from tracts 819, 820, 863 and 864. 

56 
Table 3.10 

Annual Royalty Payments to Alabama 

($1000) 

Calender 

Year 

Exxon/Hunt MOEPSI BP Shell/ 

Shell Amoco 

Norphlet 

Subtotal 

Fiscal 

Year 

Miocene 

Subtotal 

8g Federal 

Waters 

Total 

1988 1,540 1,540 87-88 250 1,790 

1989 3,350 3,350 88-89 710 4,060 

1990 1,020 1,020 89-90 n/a 1,020 

1991 4,193 487 4,680 90-91 300 4,980 

1992 2,741 62 2,070 4,874 91-92 1 .35 1,560 6,435 

1993 469 8,010 288 36,789 45,555 92-93 31 6,560 52,146 

1994 53,119 6,160 318 31,741 91,337 93-94 5,268 8,330 104,936 

1995 40,504 5,355 135 20,948 66,942 94-95 7,700 7,370 82,012 

1996 53,081 7,462 198 21,391 82,132 95-96 4,072 10,945 97,150 

Total 147,173 39,831 1,000 113,426 301,430 17,074 36,025 354,529 

Source: Alabama Dept . of Conservation and Natural Resources, 1997 . 

~1 
4.0 Exploration Expands Beyond Mary Ann Field 

Following the 1979 Mary Ann discovery well, 76-1, MOEPSI and Eon drilled 11 more 

successful gas wells in a row. By year end 1984, MOEPSI and Exxon, having discovered five 

Norphlet reservoirs plus Lower Mobile Bay, had proved that Mobile Bay would become one of 

the most significant gas producing provinces in the U.S . Exxon and Chevron added two other 

discoveries in 1985 . Table 4.1 catalogs wells as exploration or delineation and shows the fields 

discovered through 1985 . Seventeen Norphlet wells were spudded and tested by year end 1985 

taking between six and twelve months each to drill 21,000+ feet wells . 

Table 4.1 

Norphlet Exploration and Delineation Wells: 1979 - 1985 

Operator Delineation Exploration Discovered 

Fields 

Discovery Date 

MOEPSI 94-2, 95-1, 76-1 Mary Ann 

77-1, 76-2, 77-2 823-1 Field 11/28/79 

72-1 823 Field 9/4/83 

West Dauphin 

Island Field 2/24/84 

Exxon 63-1 62-1 Bon Secour 

913-1 Bay Field 9/23/83' 

867-1 867 Field 7/26/84 

112-1 Northwest 

Gulf Field 12/25/84 

115-1 North Central 

Gulf Field 4/12/85 

Chevron 861-1 861 Field 8/12/85 

Placid 826-1 

Shell 909-1 

Officially discovered with 63-1 8%29/84. 

Source: Table 4.2 

Rick Hagar, Gulf Coast Editor of OGJ, who covered the news about Mobile Bay in the 1980s, 

wrote a long status report in the January 14, 1985 issue. Hagar speculated that reserves 

discovered to date amounted to about 2 .5 TCF, with the federal 823 Field being the largest-at 

least 1 TCF recoverable . Hagar described the 823 structure as possibly reaching from tract 867 

to tract 112 . Exxon Exploration V. P. Stephen M. Cassiani, called their success "phenomenal," 

having hit three gas wells on four plays. He described Exxon's development plans in the "infant 

58 
stages" and Cassiani speculated that "the offshore Norphlet trend may someday surpass Prudhoe 

Bay's 26 TCF. 

"ss 

4.1 MOEPSI Mary Ann Delineation: 1981 & 1982 

MOEPSI, having initiated its lower Mobile Bay appraisal program in January 1981, jointly 

applied to the Corps of Engineers in August with four other winners in Alabama's March lease 

sale for permission to drill up to 28 deep wells to explore their leased acreage .56 The program 

was described as a five year effort in documents submitted to the Corps in August 1981 . State 

officials-other than Mr. Bailey, who ran for governor in 1978 with environmental backing and 

lost-happy with the $449 million in the bank earning nearly $160,000 a day in interest, strongly 

endorsed the proposed drilling plan. 

MOEPSI's four appraisal wells, 94-2, 95-1, 77-1 and 76-2 were the only wells spudded in 1981 

and 1982 as the regulatory agencies reviewed the submitted program. Mrs. Myrt Jones resumed 

her public stance against drilling in Mobile Bay, keying her remarks at a public hearing in July 

1981 against Eon. She sought evidence that the industry had prepared "a `fast response' plan 

to handle oil spills and hydrogen sulfide leaks, using equipment locally available."" Both of 

these are part of the standard response measures . 

4.2 Exploration and Delineation Drilling : 1983 - 1985 

Exxon was the first of the new group to initiate drilling-but not until January 1983 . Four 

Norphlet wells were spudded in 1983 and seven were spudded in 1984 . Six of these 11 were 

drilled by Exxon. Wells spudded before year end 1984 are shown on Table 4.2 . 

ssOGJ, "Mobile Bay shaping up as major gas producing area," January 14, 1985, p . 25 . 

s60GJ, "Mobile Bay wildcat drilling programs outlined," August 17, 1981, p . 80-81 . 

""Coastal drilling plans shape up," Mobile Press, June 23, 1981 . 

59 
Table 4.2 

Mobile Bay Norphlet Wells Drilled 1979 - 1985 

Tract Operator Well Permit 

Date 

Test 

Date 

Status 

1/SS 

Status 

12/97 

76 MOEPSI 76-1 6/21/78 11/28/79 gas well Producing 

94 MOEPSI 94-2 2/2/81 5/22/82 gas well Producing 

95 MOEPSI 95-1 1/28/81 8/22/82 gas well P&A 

77 MOEPSI 77-1 7/6/82 3/27/83 gas well Producing 

823 MOEPSI 823-A1 4/14/83 9/4/83 gas well Producing 

62 Exxon 62-1 11/30/82 9/23/83 TA gas well Producing 

not tested 

until 6/2/85 

72 MOEPSI 72-1 7/13/83 2/24/84 gas well P&A 

867 Exxon 867-1 3/14/84 7/26/84 gas well TA; complete 

in 98 

76 MOEPSI 76-2 10/22/82 not tested gas well P&A 

I 

until 6/29/88 

77 MOEPSI 77-2 8/26/83 not tested gas well Producing 

until 6/13/87 

', 63 Exxon 63-1 3/14/84 8/29/84 gas well Producing 

112 Exxon 112-1 5/30/84 12/25/84 gas well Producing 

', 826 Placid 826- 12/16/83 3/5/85 drilling P&A (water) 

1/826- 

I 2ST 

909 Shell 909-1 11/3/84 3/12/85 drilling P&A 

115 Exxon 115-1 9/11/84 4/12/85 drilling Producing 

913 Exxon 913-1 11/13/84 7/13/85 drilling P&A 

861 Chevron 861-1 11/4/84 capped 7/85 drilling Gas well ; 

blew out, 4/85 

-P&A 

Source: Alabama Oil and Gas Board, 1997; U .S . Dept. of the Interior, MMS, 1998 . 

60 
4.2.1 Exxon Steps Out in State Water: 1983 and 1984 

Exxon was permitted to drill its first well seeking Norphlet gas on November 30, 1982 and 

spudded a well on state tract 62 in January 1983 in 14 feet of water targeted to 21,000 feet . The 

well was three miles north-northeast of Mobil's discovery well. Well 62-1 was drilled to target 

depth on September 6, 1983, but not tested until June 1985 . The well tested 20.5 MMCFD at 

20,822 feet as the confirmation of the Bon Secour Bay field. Eon well 63-1, spudded March 

14, 1984 and tested 28 .1 MMCFD at 20,792 feet on August 29, 1984 is the official discovery 

well . 

Tract 112, for which Eon paid $137 million, was not permitted until May 30, 1984 . The well 

tested 21 .1 MMCFD on December 25, 1984 . Well 112-1 discovered the Northwest Gulf Field 

at a depth of 21,500 feet . Exxon's aggressive bids in the August 1984 state Lease Sale reflected 

the information they acquired from their drilling program. 

Exxon hit another winner-115-1-in April 1985 giving Exxon four successful state gas wells . 

Well 115-1 discovered the North Central Gulf Field at a depth of nearly 21,400 feet . The well 

tested 9.0 MMCFD. 

4.2.2 MOEPSI Finds the First Federal Field 

MOEPSI's drilling during 1983 and 1984 included two exploration wells (823-A1 and 72-1) and 

two more delineation wells in the Mary Ann field (76-2 & 77-2) . MOEPSI completed its 77-1 

well in April 1983 and moved the drilling rig, a Global Marine jack up, to federal tract 823-the 

first federal acreage to be probed and the first discovery in federal water. The well tested 26 

MMCFD April 14, 1983, encountering gross sand thickness of 300 to 700 feet at a depth of up 

to 1,100 feet deeper than Mary Ann. Federal tract 823 adjoins Exxon's tract 111 . 

Exxon followed this with a discovery March 14, 1984 in tract 867, adjoining the southern edge 

of Mobil's tract 823 . The well, drilled to 22,422 feet, tested 33 MMCFD, the highest flow rate 

recorded to date in the Norphlet. Exxon described the discovery as a possible extension of the 

reservoir underlaying 823 . Exxon subsequently drilled a well in adjoining tract 868 that was 

tested on February 21, 1986, then plugged and abandoned (P&A'd). No development has 

occurred on 867 although the lease is still active . Exxon maintains that they will produce the 

867 gas in 1998.58 

MOEPSI's third discovery was on state tract 72, north of Dauphin Island and 10 miles west of 

their first discovery well on tract 76. This well tested 21 .2 MMCFD from 21,102 feet on 

February 24-25, 1984 from the uppermost perforation, having tested water at lower depths . The 

West Dauphin Island Field was established in September 1985 consisting of tracts 71, 72, 89 and 

90. The south half of 89 and 90 subsequently were deleted from the field because Union's well 

SgTelcon with Exxon executive, May 5, 1997. 

61 
90-1 was P&A'd as non-productive in July 1986. Union "twisted off leaving 50 feet of bottom 

hole assembly fish in the hole . 

"s9 

MOEPSI appeared before the AOGB in December 1987 seeking another reduction of field limits 

to match extensive new 3D seismic evidence that showed that the West Dauphin Island Field was 

smaller than originally believed. Ultimately, MOEPSI turned the leases back to the state in 

1994. The tight zone found in all Norphlet producing reservoirs varies greatly in thickness but 

is perhaps the thickest in the Alabama Well 72-1 where it reaches a thickness of 141 feet. 

Average pay thickness is 67 feet . MOEPSI found that the Well 72-1 tight zone is too thick, the 

structure is too small, and the net pay is too thin to sustain development. 

4.2.3 Chevron Pioneers the Western Norphlet Trend 

Chevron's first Norphlet well was drilled in tract 861 and tested 11 .2 MMCFD at 21,645 feet . 

The well was 18 miles west of Exxon's discovery in tract 867, and 14 miles south of 

Pascagoula. The well encountered bottomhole pressure greater than 18,000 psi, well above 

previous Norphlet discoveries in the 10 - 13,000 psi range . The well blew out underground in 

April 1985 and was subsequently capped in July, plugged and abandoned. Chevron subsequently 

drilled a number of Miocene wells and one well to 11,500 feet in tract 861 . They finally drilled 

a second Norphlet well in tract 861 to 22,103 feet seven years later, testing 52 MMCFD on 

April 9, 1991 . 

4.2.4 First Disappointments : 1984 & 1985 

After hitting 12 gas wells in row, Placid's 826-1 well was the first Norphlet disappointment . 

The well was P&A'd March 5, 1985 after two sidetracks . This proved that Exxon's tract 115 

discovery was sealed on the south by a fault between the state and federal tracts . Placid drilled 

a well and two sidetracks into this small tract beginning in December 1983 before finally giving 

up in April 1985 . Exxon, a partner in the well, subsequently testified to the AOGB that the well 

encountered 100 percent water from an interval in the Norphlet that was hoped to contain gas .6° 

Four of the five wells drilling January 1, 1985 were disappointments . These included Shell's 

first Norphlet well, drilled in tract 909, tested March 12, 1985 and Exxon's well 913-1, tested 

July 13, 1985. Shell drilled its tract for which it paid $28 .2 million in Sale 67 before it drilled 

its state tracts 113 and 132, which it acquired in 1981 . Shell's and Exxon's wells were below 

22,000 feet, following the downward dip of the sands. Shell's and Exxon's leases were 

subsequently terminated, the wells plugged and abandoned. These well results suggest that the 

productive Norphlet does not extend very far directly south of the entrance to Mobile Bay. 

S9AOGB Docket 12-17-879A, p . 74 . 

'AOGB Docket 9-6-86, p. 79. 

62 
4.2.5 Summary: Exploration Successes: 1983 - 1985 

Through 1985, Mobile Bay operators had discovered eight Norphlet fields . Exxon's four 

discoveries led to the establishment of three producing state fields and one federal field-Bon 

Secour Bay, North Central Gulf, 827 Field, and Northwest Gulf-which produced between about 

320-408 MMCFD in 1997 . So far, Exxon has produced no gas from tract 867. MOEPSI's 

exploration found the 823 Field, which produced as much as 200 MMCFD in 1996, and the 

West Dauphin Island Field, which was abandoned in 1994 . Chevron's discovery led to 

substantial exploration by Chevron and Union in the vicinity of the 861 discovery, after technical 

problems were solved to deal with the extremely high reservoir pressures . Production is 

building up in 1998 from Chevron's 861 tract and wells in adjoining tracts . 

4.3 Exploration and Delineation Wells: 1985 - 1989 

Twenty-two Norphlet wells were spudded and tested between 1985 - 1989 . Most were spudded 

before gas prices skidded below $2 .00 in 1986 . Oil prices collapsed at that time, bringing the 

value of liquid btus in line with natural gas btus, and confirming that the incentives for spudding 

$20 million exploration wells needed to be reconsidered . The activity in 1985 and 1986 was 

both planned earlier and needed to be undertaken to comply with five year lease terms from the 

first state and federal lease sales . Nine wells were spudded after the oil price drop . Exploration 

slowed considerably during 1988 and 1989. 

Twelve of the 22 wells were delineation wells, seven of which drilled by Exxon; ten were 

exploration wildcats drilled by MOEPSI and the new participants . Table 4.3 shows the wells 

characterized as delineation or exploration and fields discovered . Seven new fields were 

discovered bringing the total number of discovered Norphlet fields to 15 by the end of 1989. 

Table 4 .4 shows the wells in date order of their testing . 

63 
Table 4.3 

Norphlet Exploration and Delineation Wells Drilled: 1985 - 1989 

Operator 

Exxon 

MOEPSI 

BP 

Shell 

Chevron 

Texaco 

Delineation Wells 

64-1, 78-1, 114-1, 868-

1, 827-1, 97-1, 91-1 

823-A2, 822-1, 822-2 

Exploration Wells Discovered Discovery 

Fields Date 

827 Field 4/21/86 

821-1, 999-1 

113-1 

DD56-1 

1006-1, 872-1, 

869-1 

90-1, 904-1 

991-1 

Union 

Conoco 

132-1 

862-1 

821 Field 

Fairway Field 

Destin Dome 

872 Field 

869 Field 

904 Field 

4/10/86 

5/2/86 

1/7/88 

7/24/88 

8/22/89 

5/18/88 

Source : Table 4 .4 . 

64 
Table 4.4 

Mobile Bay Norphlet Wells Spudded and Tested: 1985 - 1989 

Tract Operator Well Permit Date Test Date Status 1/89 Status 12/97 

822 MOEPSI 822-1 1/10/85 9/24/85 P&A P&A 

64 Exxon 64-1 5/24/85 11/8/85 gas/TA P&A March, 

1997 

114 Exxon 114-1 1/14/85 12/14/85 gas/TA P&A 

1006 Texaco 1006-1 2/27/85 1/8/86 P&A P&A 

868 Exxon 868-1 8/1/85 2/21/86 P&A P&A 

821 BP 821-1 9/25/85 4/10/86 gas/TA Producing 

113 Shell 113-1 2/15/85 5/2/86 gas/TA Producing 

97 Exxon 97-1 6/13/85 7/16/86 P&A P&A 

(water) 

90 Union 90-1 12/4/85 7/21/86 P&A P&A 

(water) 

827 Exxon 827-1 4/1/86 7/29/86 gas/TA Producing 

862 Chevron 862-1 11/9/86 5/21/87 gas/TA TA;ST, 1998 

991 Conoco 991-1 10/16186 10/28/87 P&A P&A 

91 Eon 91-1 4/30/85 12/27/87 P&A P&A 

(water) 

DD56 Chevron DD56-1 6/12/87 1/7/88 gas/TA P&A 

999 BP 999-1 4/22/87 2/17/88 P&A P&A 

822/ MOEPSI 822-2/ 8/7187 5/10/88 P&A P&A 

110 110-1 

904 Union 904-1 9/21/87 5/18/88 gas/TA; start up 12/93 ; 

(bottomhole) Test 97.6 lost the well 

MMCFD 8/94 

2/92 

872 Texaco 872-1 11/16/87 7/24/88 gas/test at Producing 

25 

MMCFD 

132 Shell 132-1 9/17/87 11/27/88 gas Producing 

823 MOEPSI 823-A2 7/23/88 4/7/89 gas/TA Producing 

869 Texaco 869-1 10/7/88 8/22/89 drilling Gas;P&A 

78 Exxon 78-1 12/1/88 12/13/89 drilling Producing 

(bottomhole) 

Source : Alabama Oil and Gas Board, 1997; U.S . Dept. of the Interior, MMS, 1998 . 

65 
4.3 .1 Exxon Delineates Discoveries 

Four of Exxon's wells extended their discoveries-64-1 and 78-1 extended the Bon Secour Bay 

Field; 114-1 and 827-1 extended the North Central Gulf reservoir limits . The 827 gas well 

resulted in the formation of federal 827 Field . The wells in state tracts 91 and 97 hit water to 

the north of their 111 and 115 discoveries, and the well in 868 must have confirmed that the 823 

reservoir did not trend southeast quite as far as originally anticipated. Unlike the 867 discovery, 

868-1 was P&A'd. Well 114-1 found gas, but tested only 1 .2 MMCFD due to poor quality (low 

permeability) reservoir rock. Exxon later decided with 3D seismic that 114-1 penetrated a thin 

section of interdune reservoir. Well 114-2 subsequently penetrated the thick center of the dune 

containing good quality reservoir rock in 1991, after which 114-1 was P&A'd in 1992 .61 Well 

114-2 typically produces about 35 MMCFD. 

4 .3 .2 Texaco Finds Federal 869 and 872 Reservoirs 

Texaco's well 872-1 tested 25 MMCFD gas at 22,803 feet in July 1988 . Confirming the typical 

northwest-southeast orientation of Norphlet sands, the well is southeast of the Exxon discovery 

wells on tracts 115 and 827. Chevron subsequently purchased the 872 discovery from Texaco. 

Chevron's infrastructure plans for the eastern area of the Mobile OCS supported the purchase. 

Well 872-1 initiated production March 1996, producing to Union's 916 platform . 

Texaco drilled well 869-1 and discovered reserves south of Shell's Fairway Field in August 1989 

at 22,635 feet . The well tested only 5 .1 MMCFD, suggesting that it wasn't in a very good 

location in the reservoir. Texaco, which acquired the lease when it merged Getry, subsequently 

sold the discovery to Mobil because Texaco had no infrastructure and insufficient discoveries 

to justify development pipelines and processing . Mobil's well later hit a more productive part 

of the reservoir and the field started production February 1997 from well 869-3 at 80 MMCFD 

transported to the 823 plant. 

Texaco's two discoveries are producing nearly 75 MMCFD in 1997 . 

4.3.3 MOEPSI's 823 Delineation Efforts 

MOEPSI drilled a confirming gas well on its 823 discovery and two wells-822-1, 822-

2-looking for the western extension of the 823 reservoir. Well 822-1 was a straight hole, but 

822-2 reached a bottom hole in tract 110. Neither of the two found commercially productive 

Norphlet gas . 

4.3 .4 BP Finds Federal Field 821 

BP's successful well in 821 discovered a new reservoir, rather than a westward trend of the 823 

6'AOGB Docket 11-9-937, p . 287. 

66 
reservoir. BP's well subsequently began production in January 1992, producing over 20 

MMCFD, processed on the platform. BP had only the single discovery and sold the producing 

property to Shell August 1, 1996 . Shell may drill another well on the tract sometime in 1998 . 

4.3 .5 Shell Finds Fairway Field 

Shell's well 113-1 discovered the Fairway Field May 2, 1986 at 21,200 feet . The well tested 

13 .7 MMCFD. Well 132-1 confirmed the extent of the reservoir November 27, 1988. The 

Fairway Field was subsequently developed with four wells producing in 113 and one in 132 . 

The 113-1 well was reported by Shell Offshore General Manager of Production, W. W. Dover, 

as penetrating 500 feet of net pay gas .62 Porosity averages 13 percent in the reservoir and 

average pay thickness is 199 feet . Like other Norphlet fields, the Fairway Field has variable 

HZS, close to 100 ppm for some of the wells and up to 1 .5 percent for others . 

4.3.6 Chevron/Union Confirm Western Edge Norphlet Trend 

Chevron's well 862-1 found gas, delineating their adjoining 861 discovery, and confirming that 

the Norphlet trends east-west between the Alabama and the Mississippi OCS. The well remains 

TA, tentatively scheduled for a sidetrack in 1998 . Union's 904-1 discovery southwest of 861 

provides evidence of the extent of the productive Norphlet on the western trend of the Norphlet. 

Union's 904-1 well reached total depth in 1988 but was not tested until February 1992 due to 

technology limitations on the extremely high pressure gas . The well tested 97 .6 MMCFD, the 

highest rate to date, from 22,290 feet in February 1992. Union's well encountered as much as 

20,000 psi-the same problem Chevron encounter with its 861-1 . Chevron and Union sought 

delays from MMS while they developed metallurgy technology to deal with the extremely high 

pressures .61 The well was finally brought into production December 1993; but the well was 

lost in August 1994 . 

Union's state well 90-1 was water bearing, proving that a fault separated the tract from 

MOEPSI's discovery on tract 72 . This was a major disappointment . 

4.3.7 Chevron Hits Destin Dome 

The major discovery of the five year period was Chevron's discovery of the Norphlet 22 miles 

south of Pensacola Beach in the Destin Dome OCS. Well DD56-1 was not tested but "analysis 

of cores and . . . logs indicated the presence of gas in the Norphlet sandstone"' January 7, 

1988 at 22,572 feet. After years of unsuccessful exploration of the Eastern Gulf by the industry, 

Chevron is fulfilling the geologic potential subsequently described by Mink, Tew, et albs The 

620GJ, "Development activity dots Mobile Bay trend," April 6, 1987, p. 27 . 

630GJ, "Industry slates more exploration, development in the Gulf Norphlet," March 6, 1989, p . 16 

'OGJ, "Norphlet gas find indicated off Pensacola," February 21, 1989, p. 18. 

6sMink, Tew, et al, Bulletin 140, 1990, p . 23 - 26. 

67 
Norphlet extends east from Mobile Bay. After two subsequent delineation wells, Chevron filed 

a Development and Production Plan with MMS in December 1996, calling for an expected 

production of 300 MMCFD on peak, not long after the turn of the century . This discovery put 

Murphy and Conoco into the game as Chevron's equal partners . 

4.3.8 Conoco/BP/Texaco Disappointments 

Conoco's and BP's two wells in their expensive federal Sale 98 tracts-991 and 999-provide 

evidence of their efficiency in planning, permitting and initiating exploration programs; but their 

disappointments provide further evidence that the productive Norphlet does not run too far 

directly south of Mobile Bay, even dipped to the greater depths where these wells bottomed : 

23,195 and 24,274 feet . Well logs show that Conoco's 991-1 well actually hit extremely good 

quality gas bearing sand; but the well was in a thin location, penetrating a 30 foot pay zone, 

possibly interdune . Conoco P&A'd and let the lease expire . Chevron re-acquired tracts 991, 

992 and 993 in the 1995 lease sale and made a discovery in 1996 in the Cretaceous, at 15,400 

feet. Chevron's plans are not yet announced . 

Texaco's January 1986 disappointment in tract 1006 provides further evidence that productive 

Norphlet with sufficient gas to warrant development is missing in the southern part of the Mobile 

area OCS, where the Norphlet approaches the shelf edge . The well reached total depth of 

23,153 . 

4.3.9 Major Exploration Achievements/Disappointment: 1985 - 1989 

By early 1988, MMS reported discovered reserves at 4 TCF. Operators speculated that 

discovered reserves at current prices could reach 10 TCF. During 1988 and 1989 four more 

federal fields were discovered-DD56, 904, 872 and 869-bringing the discovered reserves 

closer to the 10 TCF estimate . Chevron's Destin Dome discovery and the emerging play on 

the western trend of the Norphlet stand out as the major exploration achievements of this period. 

Failure by Conoco, BP, and Texaco to find commercial gas on the southern edge of the Mobile 

OCS area where Conoco and BP spent over $100 million in Lease Sale 98 stands out as the 

major disappointment of the five year period . The leases along the southern border of the Mobile 

OCS have been terminated or allowed to expire . 

The March 6, 1989 OGJ contained a graphic of discovered and postulated Norphlet gas 

structures in the area, which is reproduced as Figure 4.1 . While not all of the postulated fields 

turned out to be commercially productive (e.g ., tracts 990/991/999) and not all of the 

subsequently discovered reservoirs were postulated on the figure (e .g. tracts 904 and 872), 

Figure 4.1 shows a remarkable number of Norphlet structures with extensive areal coverage . 

'OGJ, "Industry slates more exploration development in gulf Norphlet trend," March 6, 1989, p. 

15- 18. 

68 
Figure 4.1 . Norphlet Structures Off Coastal Alabama . 

Source: Oil and Gas Journal, March 6, 1989a, p . 15 . 110 1 
Rick Hagar wrote in his summary article that confirmed Norphlet discoveries represented the 

largest accumulation of U.S. gas found since discovery of Prudhoe Bay.6' 

4.4 Exploration and Development: 1990 to 1993 

Eighteen wells were tested between 1990 and June 1993 ; all but three were development wells. 

Sixteen of the 18 wells are gas wells, 13 of which are producing in 1997, or are shut-in for 

workovers . Table 4 .5 characterizes the wells as exploration or delineation and shows new field 

discoveries . Two new fields were discovered during this three and one-half year period : 

MOEPSI's Aloe Bay Field, north of Dauphin Island, and Union's 916 Field on the eastern edge 

of the Mobile OCS at the Florida-Alabama line . This brought the total of discovered Norphlet 

fields to 17 . Wells tested in date order are shown on Table 4.6. 

Table 4.5 

Norphlet Exploration and Delineation Wells Drilled: 1990 - 1993 

Operator Delineation Wells Exploration Wells Discovered 

Fields 

Discovery 

Date 

Eon 114-2, 116-1, 111-1, 

112-2, 111-2 

MOEPSI 95-3, 95-4, 75-1 Aloe Bay 1/7/92 

823-A3, 823-A4 

Shell 113-2,113-3, 113-4 

Chevron DD56-2, 861-8, 906-2 

Union 950-1, 916-A2 916 12/7/91 

Source : Table 4.6 . 

6'OGJ, "Industry slates more exploration, development in gulf Norphlet trend," March 6, 1989, p . 

15 . 

70 
Table 4.6 

Mobile Bay Norphlet Wells Tested: 1990 - 1993 

Tract Operator Well Permit 

Date 

Test Date Status 

12/93 

Status 12/97 

DD 56 Chevron DD56-2 10/18/89 11/22/90 Test 22 TA 

MMCFD 

823 MOEPSI 823-A3 7/7/89 4/25/90 Test 62 .3 Producing 

MMCFD 

823 MOEPSI 823-A4 6/11/90 12/11/90 gas Producing 

95 MOEPSI 95-3 10/16/89 11/15/90 gas Producing 

95 MOEPSI 95-4 11/2/90 5/19/91 gas TA 

950 Union 950-1 2/26/91 8/24/91 P&A P&A 

916 Union 916-A2 3/15/91 12/7/91 Test 42 Producing 

MMCFD 

861 Chevron 861-8 4/4/91 11/18/91 Test 57 Producing 

(TD) MMCFD 

113 Shell 113-2 2/26/90 12/24/91 gas Producing 

113 Shell 113-3 10/19/91 12/25191 gas Down for 

Workover 

113 Shell 113-4 10/29/90 1/4/92 gas Producing 

75 MOEPSI 75-1 5/9/91 1/7/92 gas Producing, 

Start-up 7/97 

at 22 

MMCFD 

114 Exxon 114-2 1/25/91 2/7/92 gas Producing 

906 Chevron 906-2 11/12/91 5/2/92 P&A P&A 

111 Exxon 111-2 4/4/91 11/24/92 gas Producing 

111 Exxon 111-1 7/6/92 10/29/93 gas Producing 

112 Exxon 112-2 12/13/91 11/4/93 gas Producing 

116 Exxon 116-1 6/26/91 12/1/93 gas Producing 

Source : Alabama Oil and Gas Board, 1997 ; U.S . Dept. of the Interior, MMS, 1998 . 

71 
4.4.1 Exxon & Shell Complete Projects and Initiate Production 

Exxon and Shell's delineation wells accomplished the following : 

" Shell drilled out its Fairway field and started production in December 1991 ; 

" Exxon drilled out its three state fields and started production in October 1993 . 

The development of these fields is discussed in Section 6 .0 . 

4.4.2 MOEPSI's Development Drilling : Mary Ann and 823 

Mobil added two wells to its Mary Ann Field and developed its 823 Field, which started 

production in November 1991 . The development of these fields is discussed in Section 6 .0. 

MOEPSI wells 95-3 and 95-4 completed the drilling program for the original reservoir 

discovered within its Mary Ann Field. Well 95-3 was tested and brought on production in 

November 1990. Well 95-3 is the Mary Ann Field's best well, producing an average of 25 

MMCFD through September 1996, with lower than field average H2S, 3 .5 percent. Well 95-4 

was tested in May 1991, but never produced . After they drilled it, MOEPSI TA'd the well for 

further evaluation in July 1991 . They considered a sidetrack to a better location in 1992. 

AOGB testimony shows that the well hit "an unusually thick section of tight zone, 163 feet, 

before penetrating 84 feet of gas . "6$ The records show it temporally abandoned . 

MOEPSI initiated a program to develop the 823 Field and slated the field for a 1991 start-up. 

Gas started flowing at 40 MMCFD from a single well in November 1991 . Two more wells 

brought production to 170 MMCFD in March 1992 with less than 200 ppm HZS.69 At year end 

1993, MOEPSI was producing 140 MMCFD from three wells in 823 to its 250 MMCFD 

capacity 823 plant. MOEPSI increased its capacity of the Mary Ann Plant to 160 MMCFD to 

take in the unexpectedly sour gas from 823-A4 well. That well tested 68 MMCFD with 2.8 

percent H2S from 22,570 feet . Production started March 1994. 

4.4.3 MOEPSI's Aloe Bay Discovery 

Mobil's single exploration well 75-1 discovered its Aloe Bay Field, which covers parts of tracts 

74, 75, 92 and 93 on January 7, 1992-underlaying Dauphin Island . Tract 75 was leased from 

the state in 1988 . Gas began flowing to the Mary Ann Plant in July 1997 . The plant, which 

received an average of 144 MMCFD during the first quarter 1997, was debottlenecked to 

increase capacity to take in the Aloe Bay 8 percent HZS gas, anticipated to produce between 30 -

50 MMCFD. 

6gAOGB Docket 7-17-964, p . 130. 

690GJ, "Gas flowing from field off Alabama," November 11, 1991, p . 27 . 

72 
4.4.4 Chevron and Union: Eastern and Western Mobile OCS Successes 

Chevron, working with Union, continued to drill to delineate their high pressure reservoir[s] 

underlaying tracts 860, 861, 862, 904, 905, 906, 948, 949, and 950. Chevron's 861-8 reentered 

the Norphlet at a better location than the 1985 861-1 well, testing 57 MMCFD from 22,103 feet . 

The well encountered "more than 360 feet of potential pay, suggesting a large gas reservoir. " 

Union's 950-1 and Chevron's 906-2 were unsuccessful, apparently confirming that the Norphlet 

structures under 861, 862 and 904 do not trend southeast in sufficient thickness. Well logs show 

that the wells encountered gas but not in sufficient volume to be economic. They were P&A'd. 

(See box.) 

Norphlet Drilling Challenges 

Chevron reported Well 9Q6-2 to have the "best drilling performance yet experienced 

in the high pressured Norphlet. " Central to the completion of the well 32 days 

ahead of schedule was the selection of drilling bits. "With well depths in Mobile 

federal waters averaging [over] 22,000 feet, the key criteria for bit selection is to 

remain on bottom as long as possible in order to avoid costly trips at those depths . 

. . . Furthermore, the formations encountered in federal Mobile waters are extremely 

hard and abrasive, particularly the lower Cotton Valley formation between 18 ;000 -

21,400 feet . . . . High pressure and hard rock, coupled with bottomhole static 

temperatures exceeding 425°F, will decimate an improperly selected drill bit ." In 

comparison to Chevron's first Norphlet well, 861-1, which used 19 drill bits', 906-2 

used only 9, reducing the round trip costs at $2,000 an hour from $483,567 to 

$291,098 . Eight 'of the nine bits employed on the 906-2 well were metal sealed 

roller coned fits in contrast to elastomer 0-ring seals used in Chevron's 861 and 862, 

wells . These proved to be inadequate to contend with the aggressive Norphlet 

drilling environment . The reliability of the metal seals is as critical to successful 

Norphlet wells as matching the bit choice and operating rate to the formation rock. 

Bomar, B., and J . Canals, Offshorel4ilman, January 1993', p. 31 - 33 . 

"Natural Gas Intelligence, "Chevron, Mobil, Phillips, Apache Announce Large Finds," February 10, 

1992, p . 5 - 6 . 

73 
Chevron achieved confirmation of its discovery on Destin Dome with its DD56-2 well, which 

tested 22 MMCFD from 22,864 feet November 22, 1990 ." 

Union's 916-A2 well, the first Norphlet discovery in the tract, tested 42 MMCFD December 

1991 . This was a significant discovery, extending the productive Norphlet trend Chevron 

discovered with its 872-1 well southeast from Mobile Bay. Union, Chevron and Bechtel's 

Fremont Energy Corp hold the leases for the tracts that are believed to overlay the discovered 

reservoir and other productive Norphlet sands-871, 872, 915, 916, 917, 918, 961, and 962. 

4.5 Exploration and Development: 1993 - 1997 

Drilling in the last five years has been dominated by Chevron and Union developing their eastern 

and western Mobile Bay Norphlet fields as shown on Table 4.7 . Four wells are classified as 

exploration wells . Murphy's 908-3 well and Chevron's 864-3 well spudded within two months 

of each other to probe nearby Norphlet targets below 22,000 feet . Well 908-3 was Murphy's 

first as operator . Chevron hit; Murphy did not. Chevron also drilled a wildcat well in tract 958 

that had the same problem found in the 950 and 906 wells : insufficient gas to be economic . 

Two new fields were discovered in the last four years : Chevron's 864 and 820 fields, bringing 

the total to 19 Norphlet fields . Eighteen wells tested in date order are shown on Table 4.8, 

including Exxon's and Chevron's most recent wells spudded, 114-3 and 864-4. 

Table 4 .7 

Norphlet Exploration and Delineation Wells Drilled: 1993 - 1997 

Operator Delineation Wells Exploration Wells Discovered 

Fields 

Discovery 

Date 

Chevron 917-2ST, 958-2 820 12/14/94 

863-3, 819-1, 820-1, 864-3 864 6/29/94 

DD57-1, 864-4 DD97-1 

Union 904-2, 

916-B3, 961-2 

MOEPSI 869-2, 869-3, 95-SST 

Murphy 908-3,3ST 

Exxon 111-3, 114-3 

Source: Table 4.8 . 

"OGJ, "U.S . Gulf," April 25, 1994, p . 74. 

74 
Table 4.8 

Mobile Bay Norphlet Wells Spudded and Tested: 1993 - 1997 

Tract Operator Well Spud Date Test Date Status 

12/97 

917 Chevron 917-2/A2ST 6/23/93 12/2/93 Producing 

916 Union 916-B3 9/24/93 3/15/94 P&A 

869 Mobil 868-2 12/18/93 5/18/94 P&A 

864 Chevron 864-3 1/28/94 6/29/94 Start up 10/21/96; 

P&A water 

problem 

I DD97 Chevron DD97-1 3/11/94 7/9/94 P&A 

I' 863 Chevron 863-3 12/8/93 9/21/94 Producing; 

start up 2/19/97 at 

18 MMCFD 

961 Union 961-2 9/22/94 4/8/95 Producing 

908 Murphy 908-3/908- 11/23/93 8/27/95 P&A 

3ST-2 

95 MOEPSI 95-5/95-SST 4/15/94 10/22/95 Producing; start up 

11/96 at 73 

MMCFD. 

958 Chevron 958-2 11/25/95 2/26/96 P&A 

DD57 Chevron DD57-1 11/7/95 2/7/96 Tested 41 

MMCFD; TA 

820 Chevron 820-1 9/26/94 12/14/94 Producing; 

(TD); 10/31/96 startup at 

29 MMCFD 

904 Union 904-2 3/15/96 9/18/96 Start-up 12/96 at 

32 MMCFD 

819 Chevron 819-1 9/17/96 12/15/96 TD Gas; start-up 

1/1/98 at 22 

MMCFD 

869 MOEPSI 869-3 5/12/96 1/97 Startup at 78 

MMCFD 

111 Exxon 111-3 3/6/96 3/20/97 Producing; start up 

at 79 MMCFD 

114 Exxon 114-3 3/6/97 10/14/97 gas; start-up Feb, 

98 at 65 MMCFD 

864 Chevron 864-4 7/13/97 12/97 Producing; start-up 

at 16 MMCFD 

Source : Alabama Oil and Gas Board, 1997; U .S . Dept. of the Interior, MMS, 1998 . 

75 
4.5.1 Mobil and Eon Add to Existing Production 

Mobil's well, 95-5, came on line during November 1996 producing 66 MMCFD during 20 days 

of November and 72 MMCFD during December. Well 95-5 is in a reservoir that underlies 

Exxon's tract 114 tract, the southern portion of Mobil's tracts 94 and 95, and the northwest 

corner of Exxon's tract 113 . (See Box.) 

Taking over the lease from Texaco, Mobil drilled well 869-2 which was tested May 18, 1994 

at 60 MMCFD. It encountered a liner top problem during completion and was P&A'd. Mobil 

subsequently spudded 869-3 May 19, 1996, which initiated production in February 1997 at 78 

MMCFD; the well produced 85 MMCFD in March, 1997 . 

Exxon started-up the 111-3 well March 10, 1997 at 79 MMCFD-above expectations-in the 

Northwest Gulf Field. Exxon's 114-3, an offset to Mobil's 95-5, spudded March 6, 1997 and 

initiated production in February 1998 at 65 MMCFD. 

4.5.2 Murphy's First Norphlet Exploration Venture 

Murphy worked for two years trying to find a productive zone as operator of tract 908 which 

it leased with ARCO and others in 1982. Murphy discovered 400 feet of gas sands but with 

insufficient permeability, porosity and gas even after several sidetrack attempts over 1994 and 

1995 . The well was P&A'd August 27, 1995 . Murphy's position in the Norphlet remains 33 

percent owner of the Destin Dome Unit, plus several yet unexplored Norphlet targets . 

4.5.3 Union and Chevron Bring New Fields into Production 

Chevron and Union drilled their 916/917 Field with a plan to start production in the first quarter 

1995 . The 1991 discovery well, 916-A2, was followed by Union's 916-B3 which tested 32 .5 

MMCFD from 23,026 feet March 1994. The well was reported to penetrate 125 feet of net 

pay .' Chevron's well 917-2ST tested 44 MMCFD in December 1993 . Union started 

production from 916-A2 in April 1995, adding 9 MMCFD from 916-B3 in May." Well 961-

A2 initiated production July 31, 1996 at 24 MMCFD. Chevron started-up their 917-2ST well 

in April 1995 producing 40 MMCFD, 80 ppm HZS. Well 872-A1 began production February 

28, 1996 and averaged 11 MMCFD in mid-year. 

Union began production from its 904-1 well on December 22, 1993 at 20 MMCFD. The well 

reached a peak production rate of 22 .3 MMCFD-well below its record test rate-but was lost 

in August 1994. Chevron started production from 861-8 June 1993 flowing to Union's 904 

facility . The well is 120 ppm HZS. The well initiated production at 30 MMCFD, but 

developed water problems and was off production from August 1994 until January 1995 . It has 

never produced near the high rates of its initial production, currently maintaining 10 - 12 

12 Dow Jones News, November 21, 1994. 

'30GJ, "Unocal steps up gas/condensate production," May 29, 1995, p. 24. 

76 
3D and CAEX Improved Norptilet Exploration 

New exploration technology-3D seismic and computer-aided exploration workstations 

(CAEX)-has 'transformed the way companies explore for hydrocarbons 'and select 

bottomhole production locations . Although the largest NorphIet reservoirs were discovered 

before 3D was widespread, MOEPSI's 1995 well 95-5 and its foul bottomhole location 

with a sidetrack 700 feet to the east of the initial location illustrate how 3D and CAEX are 

improving Norphlet results, 

CAEX and 3D are twin technologies using workstations such as Sun or Silicon Graphics, 

running interpretation software provided by Geoquest, Landmark ' and others . The 

companies use this extremely fast computing power to integrate the 3D seismic data with 

geologic data to interpret the exploration opportunity. 3D seismic processes lines shot at 

much smaller interline separation than 2D. 2D captures a few lines per mile ; 3D processes 

lines shot at one to two hundred feet and then assembles the data to map the structure in 

three dimensions, 2D shows less than 25 percent of the subsurface information that 3D 

shows because 3D processes the closely-spaced information volumetrically . Digicon, a 

company that performs 3D seismic shoots, uses an NEC SX4 mainframe to process 

Terabytes of data (1 Terabyte = 1,000 Gigabytes = 1,000,000 Megabytes) . With these 

data intensive tools, geologic structural features appear that cannot be seen with 2D. Fault 

locations become more certain . Using contrasting color and amplitude extraction, the view 

of the target zone can be improved to delineate the pay sands . 'Reservoir areal extent and 

thickness can be mapped and well path can be designed to penetrate the target at the 

optimum point. 

MOEPSI's well 95-5 illustrates the effects of 3D seismic data on well placement. MOEPSI 

spudded the 95-5 ,well in July of 1994, deviated 7400 feet east' from a rig located' outside 

the Mobile Bay shipping fairway in tract 94 . The initial well was tested May 1995 and 

judged capable of producing 50 MMCFD. 3D seismic data were used to clarify the top 

and base of Norphlet and show the geologic depth cross section on the well 95-5 . 

Conventional 2D seismic could be relied upon only to supply information on structural 

position. The well was sidetracked (ST) to a location 8100 feet east of the rig to maximize 

both structural height and stratigraphic'thickness, reaching' total depth in October 1995 . 

(OGB Docket; 7-19-964, p . 123 .) Moving the well 7(}0 feet further east from its original 

bottomhole `location improved the porosity from 11 .7% to 12.8% and improved 

productivity of the well markedly . The ST well tested 77 .3 MMCFD on October 23 1995 . 

Production averaged 70 MMCFD during December-January, 1997 following start-up in 

November, 1996 . 

The improved productivity dramatically helps the economics. The added 20 MMCFD 

improves cash flow by $20,000 a day, if the weIlhead net back price is $1 .00 per MCF. 

An incremental six million dollars a month' will pay for a substantial amount of 3D seismic 

data and drill rig time. 

77 
MMCFD. This was the only production to the 904 facilities after 904-1 was lost until Union 

brought a new well 904-2 on line December 24, 1996 at 32 MMCFD. The well is planned to 

reach 50 MMCFD after the well has stabilized .' The ultimate production rate from the 904 

field is yet unknown. 

Chevron's well 864-3 started production at 20 MMCFD October 21, 1996, but encountered a 

water production problem and was shut in. It was P&A'd April 1997 . Well 864-4 spudded in 

July, 1997, to replace 864-3 . The well initiated production in December at 20 MMCFD, 40 ppm 

H2S; ultimately, the well is expected to produce 35 MMCFD. Chevron's 863-3 well "cut more 

than 250 feet of net pay below 21,700 feet" in September 1994.'5 Production started February 

19, 1997 at 18 MMCFD, ramping up to 47 MMCFD in April 1997 . The well tested at an 

unexpectedly high 112S content, 1 .7 percent. A pipeline was installed to the Shell Fairway Field 

and the 863-3 gas is processed in the Yellowhammer plant. The well was shut in for repairs in 

December but was producing 44 MMCFD by April 1998 . 

Chevron spudded well 819-1 September 1, 1996 which reached total depth of 22,042 December 

16, 1996. The drilling time of well 819-1 shows that Norphlet wells are achieving new levels 

of productivity . The well took 3 .5 months, compared to the previous standard of five - six 

months. Chevron attributed the drilling record to experience gained in bit selection and 

casing .71 MOEPSI's first two Norphlet wells took a year. Chevron's well 819-1 initiated 

production January 1, 1998 at 22 MMCFD. 

4.5.4 Chevron's Destin Dome 

Having probed the DD56 structure successfully with two wells, Chevron spudded an exploration 

well on tract 97 in March 1994. This well was unsuccessful . Chevron subsequently hit another 

gas well in October 1996 on tract DD57-three successes out of four wells-and filed a 

development plan in December 1996 . A May 1, 1996 press release reported a test of 41 

MMCFD with average porosity and permeability significantly exceeding the two earlier DD56 

wells . 

4.5 .5 Drilling and Planned Norphlet Wells: 1998 

Planned and likely 1998 wells are shown on Table 4.9. Mobil spudded two wells in December, 

1997 : 823-AS and 914-4. The 914 well is a partnership with Enron and Chiefton. The latter two 

companies are partners in the 913/914 leases producing Miocene gas . Nine additional wells are 

announced or under consideration for drilling in 1998 . All of these wells represent extensions 

of known geology or wells to maintain production. 

'4Union press release, January 9, 1997. 

'SOGJ, "Industry Briefs," October 10, 1994, p . 36. 

''Personal communication from Gary Jacobs, August 6, 1997 . 

78 
Table 4.9 

Mobile Bay Norphlet Wells Drilling/Planned to Spud: 1998 

Tract Operator Well Spud Date Test 

Date 

Status 

12/97 

823 Mobil 823-AS 12/97 NA Drilling 

914 Mobil 914-4 12/97 NA Drilling 

61 Mobil 61-1 1998 NA Planning 

75 Mobil 75-2 possible NA Planning 

821 Shell 821-2 possible NA Planning 

918 Spirit 918-1 April-May, NA Planning 

1998 

904 Spirit 904-3 After 918-1 NA Planning 

871 Spirit 871-1 possible NA Planning 

819 Chevron 819-2 possible NA Planning 

862 Chevron 862-1ST possible NA Planning 

863 Chevron 863-4 Sept, 1998 NA Planning 

Source: Industry POEs and telcons with industry staff, 1998. 

4.5.6 Norphlet Summary: December, 1997 

Through December, 1997, 75 Norphlet wells have been drilled in state and federal waters off 

Coastal Alabama. The operators shown on Table 4.10 discovered 20 gas fields, all but three 

of which are producing . MOEPSI abandoned the West Dauphin Island Field as uneconomic; 

Exxon maintains their 867 Field lease, and plans to produce it in 1998 . Chevron and its partners, 

Conoco and Murphy, have filed a DOCD with MMS to develop Destin Dome . Exxon has 

drilled the most wells, 20 ; MOEPSI has drilled 19 . Twenty-eight wells were exploration wells . 

Twenty Norphlet discoveries for 28 exploration wells represents a 71 percent success ratio. 

Table 4.11 summarizes production, producing wells and planned wells for the near future, 

including Destin Dome wells . The fields produced 1 .1 BCFD in February 1998 from 40 wells . 

This table includes wells TA plus the wells that are drilling and planned previously shown on 

Table 4 .9. Nineteen wells are currently TA, drilling or planned including Destin Dome's wells, 

and Shell's well 113-3 undergoing a workover. These wells will keep the local area busy for the 

next several years . Potential new production to augment and sustain existing production levels 

over the next several years will come from : 

Two wells initiated production in January and February-819-1 and 114-3 ; 

Two wells spudded in December, 1997-914-4 and 823-A5 ; 

79 
Table 4.10 

Mobile Bay State and Federal Norphlet Exploration Summary: 12/97 

Exploration 

Wells 

Delineation 

Wells 

Discovered 

Wields 

MOEPSI 4 15 Mary Ann 

823 

West Dauphin Island 

Aloe Bay 

Exxon 5 15 Bon SecourBay 

867 

Northwest Gulf 

North Central Gulf 

827 

Chevron 5 10 861 

Destin Dome 

820 

864 

872 

Union 4 3 904 

916 

Shell 2 4 Fairway 

BP 2 821 

Texaco 3 872 

869 

Conoco 1 

Placid 1 

Murphy 1 

Total 28 47 20 Discovered Wields 

Source : Tables 4.1 - 4 .9 . 

80 
Table 4.11 

Active Norphlet Fields - February, 1998 

DrIII1ngIPlannedl 4011997 Processing 

Operator Discovery Production Producting Wells - February WarkoverITA Wells Production Processing Plant Capacity 

Field Name (Partners ) T racts Announced Start up Total ID Total ID Rate - MMCFD Plant MMCFD 

State Offshore 

Mary Ann MOEPSI 76, 77, 94, 95 11/28/79 4/88 6 76-1, 94-2, 77-1, 77-21953/95-SST 1 95-4-TA 105 Mary MNYelham/823 780 j 

Bon Secour Bay Exxon 62, 63, 64 , 78 03/14/84 11/93 3 62-1, 63-1, 78-1 1 61-1-P 106 Exxon 400 

Northwest Gulf Exxon 117, 112, 131 12/25/84 10/93 5 111-1, 111-2, 111-3,112-1, 112-2 0 201 Exxon 

North Central Gulf Exxon 114, 115, 176 04/12/85 11/93 4 115-t, 114-2, 176-1, 1143 0 125 Exxon 

Fairway Shell/Amoco 113,132 05/02/86 12/91 4 113-1, 2, , 4, 132-1 1 113-3-WO 98 Yellowhammer 200 

Aloe Bay MOEPSI 74, 75, 92, 93 01/07/92 7/97 1 75-1 1 75-2-P 23 Mary Mn 

Subtotal 6 23 4 658 780 

Federal OCS 

823 Field MOEPSI 822, 823, 824 02/24/84 11/91 4 823-A1, 2, 3/A4 1 823-5-D 139 823/Mary Mn 300 

867 Field Exxon 867, 868, 911 07/28/84 1998 0 1 867-1-TA 0 Exxon 

861 Field Chevron 860, 861, 862 08/72/85 12/93 1 861-8 7 862-1S7 9 904 Platform 80 

821 Field/109 state Shell 821 04/10/88 11/92 7 827-1 1 821-2-P 15 821 Platform 60 

827 Field Exxon 827,828 04/21/86 71/93 1 827-1 0 29 Exxon 

Oestin Dome Chevron/ 01/07/88 2000 0 5 0 Destfn Dome 

Conoco/ NA 

904 Field Union 904, 905, 948, 949 05118/88 12/93 1 904 .2 1 9043-P 38 904 Platform 

872 Field Chevron 872,873 07/24/88 4/95 1 872-A1 0 12 916 Platform 150 

869 Field MOEPSI/Excon 868, 869, 914 08/22J89 1/97 1 8693 1 914-4-D 64 823 Plant 

916 Field UnioNChevron 871, 915, 916, 917, 17J07/91 4/95 3 916-A2, 961-A2, 917-A2ST 2 918-1, 871-1-P 62 916 Platform 

918,961,962 

820 Field Chevron 819,820 12116/86 10/96 2 820-1, 819-1 1 819-2-P 55 864 Platform 150 

864 Field Chevron 863.864 09/21/94 2/97 2 863-3/ 864-4 1 863-4-P 65 Yellowhammer/864 

Subtotal 13 17 15 488 740 

Total 19 40 19 1146 1520 

Source : Foster Associates, Inc. , April, 1998 . 

notes: Exxon X67-t has to be put online by 12137/98 or lose the lease. Mobil has to drill tract 67 by 12/31198 or lose the lease . 

Chevron's 8633 well was down to repair a safety value during 4Q ; production rates shown are Apri 1998 production plus new well 8644, which started in December and is producing 16 MMCFD. 

Chevron 819-1 started production January 1 at 22 MMCFD. 

Exxon 1143 started production early February al 65 MMCFD. 

00 
Three wells TA, pending further evaluations-95-4, 867-1 and 862-1, which will be 

sidetracked in 1998; 

One well down for workover-113-3 ; 

Eight wells under consideration in 1998 for drilling shown on Table 4 .9; 

Five wells planned for Destin Dome . 

Table 4.12 shows the number of Coastal Alabama and Destin Dome Norphlet wells tested by 

year. Four to six wells have been tested annually in every year of the 1990s, averaging 4.5 

wells tested per year. Drilling and planned wells will maintain that average at least until Destin 

Dome comes into production. 

Good thing MOEPSI decided to drill a mile below the Smackover to the Norphlet in their 

original exploration of Lower Mobile Bay! 

Table 4.12 

Norphlet Wells Tested by Year 

Year No. of Norphlet 

Wells 

Year No. of Norphlet 

Wells 

1979 1 1988 6 

1980 0 1989 3 

1981 0 1990 4 

1982 2 1991 6 

1983 4 1992 5 

1984 5 1993 4 

1985 8 1994 6 

1986 7 1995 3 

1987 3 1996 4 

1997 4 

4.6 Miocene Exploration, Development and Transportation in Coastal Alabama State 

and Federal Waters 

MOEPSI tested the first offshore Miocene well in 1982 as part of the Lower Mobile Bay 

development plan. Well 95-2 tested 4 MMCFD October 9, 1982; the gas was used as fuel gas 

for the project and the well is now shut-in. While majors have focused mainly on finding and 

developing Norphlet gas, several independents have pursued smaller, shallow Miocene gas 

prospects in Coastal Alabama state and federal waters . ODECO President Hugh Kelly called 

the Alabama Miocene "an independent's play," in a 1989 OGJ article. Miocene wells are drilled 

82 
in a few days to a few weeks for little more than $150,000 and discoveries average 10 - 15 

BCF" versus numbers ranging in the hundreds of BCFs for Norphlet discoveries . 

The critical achievement of the Miocene development was the Dauphin Island Gathering System 

(DIGS) pipeline, constructed to transport the gas to market. This is discussed within this 

section. 

4.6.1 Miocene Geology Overview and Drilling Summary 

The Miocene is a much younger geologic age formation found between 1,500 - 3,000 feet in the 

state offshore region dipping to 4,000 - 7,500 feet in the federal OCS.'8 Miocene gas is 

typically 99.9 percent methane, probably biogenic in origin, in comparison to Norphlet 

comprised of substantial HZS and COZ contaminants . Miocene gas is pipeline quality requiring 

none of the specialized technology processes used with Norphlet gas. Bottomhole pressures for 

Miocene discoveries range from 550 to 1,200 psi compared to > 10,000 psi for Norphlet. 

The Miocene sands are categorized as upper, middle and lower, with the strata dipping down 

to the southwest from Mobile Bay. Gas-bearing Miocene sands have been discovered throughout 

Southwest Alabama, but discoveries have been generally deeper, larger, more numerous and 

more productive offshore . Union Exploration vice-president, Graydon H. Laughbaum was 

quoted as saying "MOEPSI's discovery in the Mary Ann Field led his company to the trend . . 

. . Everyone knew the Miocene was there ; but we didn't map it in detail until we got better [3D] 

seismic and decided it was worth drilling for on its own."" 

Table 4.13 shows the Miocene wells drilled in date order in state and federal waters . Following 

MOEPSI's state Miocene well 95-2, Tenneco tested the next Miocene well on OCS block 864 

in January 1983 (now operated by Chevron). A total of 40 Miocene wells were drilled in the 

Mobile OCS between 1983 and 1989, 76 total in state and federal waters through 1996 . Besides 

the obvious objective of discovering economic gas reservoirs, the wells were drilled to achieve 

two other purposes: 

" Search for sufficient discovered reserves to justify a pipeline system; 

" Demonstrate activity on the leases sufficient to meet the five year lease requirement. 

The peak drilling years, 1985 and 1987, when 10 and 13 Miocene wells were drilled, are 

coincident with the second bullet objective. Over two-dozen of these wells tested gas for a 

success rate of 64 percent. Only two miocene wells were drilled in 1996 . Table 4.14 shows 

"OGJ, "Smaller Miocene targets draw attention in Norphlet areas," March 6 1989, p. 17 . 

''Petroleum geology draws from Mink, Robert M., Ernest A. Mancini, Bennett L . Bearden and 

Charles C. Smith, "Middle and Upper Miocene Natural Gas Sands in Onshore and Offshore Alabama," 

AOGB Reprint Series 71, 1988 . 

'90GJ, "Smaller Miocene targets draw attention in Norphlet areas," March 6 1989, p. 17 . 

83 
H H H- H [~l U H 0 

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Table 4.14 

Mobile Bay Miocene Gas Wells 

FSeld Tract 

Current 

O r 

Well 

Number De 

Date Tested, 

TA or Plugged 

Well 

Status i 

E. Miss . Sound 59 Legacy 1 5,100 02125/95 Gas 

Goose Bayou 59(SL) Legacy 1-2 5,414 04/10/95 Gas 

NE Peat Bois Pass 71 OGI 1 2,100 10/11/93 Gas 

NE Petit Bois Pass 71 OGI 1 3,204 11116/95 Gas 

NW Dauphin Is 71 OGI 3 2 ST 3,995 02113/96 Gas 

I NW Dauphin Is 71 OGI 1 2,514 07/21/90 Gas 

I NW Dauphin Is 57 OGI 1 1,938 01!16/94 Gas 

~i N. Dauphin Is 73 Callon 1 2,510 07/09/90 Gas 

N. Dauphin Is 73 Callon 3 3,978 07127/91 Gas I 

N. Dauphin [s 72 Callon 2A 2,252 07/31/90 Gas I 

I N. Dauphin Is 73 Callon I 3,977 06/09/91 Gas 

I N. Dauphin Is 73 Callon 2 3,644 07/02/91 Gas 

N. Dauphin Is 95 MOEPSI 2 3,058 10/09/82 SI 

S. Dauphin Is. 91 OEDC 1 3,464 04/09/93 Gas 

S. Dauphin Is. 90 OEDC 2 3,842 06/11/93 Gas 

S. Dauphin Is. 90 OEDC 1 2,460 06/11193 Gas 

S. Dauphin Is . 90 OEDC 1 ST 3,779 04/05194 Gas I 

823 822 M OEDC A1 2,707 05/17/93 COM 

823 822 M OEDC A2 3,085 05/24/93 COM 

830 830 M Apache Corp. 1 2,050 02/18/89 TA 

861 861 M Chevron 9 3,385 10123/96 COM 

861 861 M Chevron 3 11,352 08/06/85 Gas/DSI 

861 861 M Chevron 7 3,650 06/16/85 Gas/COM i 

861 861 M Chevron 4 3,650 05/12/85 Gas/COM 

861 861 M Chevron 5 3,650 05/15/85 Gas/COM 

861 861 M Chevron 6 12,333 08106/85 Gas i 

864 863 M Chevron 1 3,050 04/22/85 TA I 

864 907 M Chevron A1 2,800 08/07/90 

I 

COM 

864 908 M Chevron 2 4,094 08/17/85 Gas 

864 863 M Chevron 2 3,400 08/07/90 COM 

864 861 M Chevron 2 4,375 04/18/85 Gas/COM 

864 864 M Chevron A2 3,197 08/06/88 COM i 

865 865 M Scans 1 3,800 05 .19/89 TA I 

865 865 M Scans A3 2,502 01~123/95 COM 

865 865 M Scans A2 ST 1,721 04/22/94 COM I 

866 822 M OEDC BI 1,677 07119/94 COM 

870 870 M Santa Fe 2 2,292 11102/87 COM 

870 870 M Santa Fe 1 2,449 02 .125/87 COM 

870 870 M Santa Fe A1 2,449 03/09/87 COM ', 

881 881 P Apache 1 2,700 01,128/89 TA 

914 914 M Enron A2 2,456 11/15/87 COM 

914 914 M Enron A1 2,906 07/12/86 COM 

914 914 M Enron 3 2,489 11125/87 COM 

916 916 M Union 1 3,100 11/15/87 TA ~i 

945 945 M Hall-Houston 1 4,400 06/04/90 COM 

947 947 M Hall-Houston 1 3,200 05/09/90 COM 

952 952 M Murphy 1 4,270 03/04/85 COM 

952 953 M Murphy 1 3,620 03120/84 COM 

955 955 M Murphy 2 4,080 07127/87 COM 

959 915 M Union 1 2,378 01/07/88 COM 

959 959 M OEDC A3 2,567 01/19/95 ST 

959 959 M OEDC A3 2,396 03 .'25/95 COM 

959 959 M OEDC A4 2,076 0528/95 COM 

959 959 M OEDC A2 2,610 11/09/94 COM ' 

959 959 M OEDC A1 2,310 10/16/94 COM 

959 959 M VASTAR 1 3,100 10/09/87 ST 

960 960 M OEDC A2 2,313 04/17/95 COM 

960 960 M OEDC A1 2,279 11/20194 ST 

960 960 M OEDC A1 ST 2,290 11/25/95 COM 

960 960 M VASTAR 1 3,100 10/25/87 TA 

961 961 M Union 1 3,191 12,116/87 COM 

990 990 M Hall-Houston 1 4,033 05 .'26/90 COM 

Source : Alabama Oil and Gas Board, 1986 ; U.S . Dept. of the Interior, Minerals Management Service. 1998 . 

85 
the gas wells re-ordered by subsequently defined fields . A substantial number of small Miocene 

reservoirs were discovered before a pipeline was built to bring the gas to market . 

4.6.2 Dauphin Island Gathering System 

Central to Miocene development was Offshore Energy Development Corp (OEDC) development 

of the Dauphin Island Gathering System (DIGS) to move gas to shore . OEDC drilled its first 

Miocene gas discovery June 1991 on Alabama tract 90, followed by a subsequent discovery on 

tract 91 . OEDC conceived the need for a pipeline to transport its own and other's gas to shore . 

OEDC's strategy was to develop a gathering system through Coastal Alabama to pick up both 

miocene and pipeline quality Norphlet gas (e. g ., Norphlet gas from BP and Union/Chevron 

processed on the platforms) . 

Rather than skirt Dauphin Island via the ship channel at the mouth of Mobile Bay, OEDC 

decided DIGS could be routed by boring under Dauphin Island and heading straight to the 

Interstate connection. Permits and right-of-way were approved in the fall of 1991 and OEDC 

started looking for partners to pay for the project. BP was planning to start its 821-1 in January 

1992 and agreed to dedicate its Block 821 gas to DIGS . OEDC obtained commitments from 

Miocene producers south and north of Dauphin Island in addition to BP and the first stage of 

DIGS was completed before the end of 1991 ." 

DIGS begins on Block 822, where a number of gathering pipelines from nearby fields converge 

at OEDC's central gathering facility . BP's 12-inch pipeline connects to the Block 822 platform, 

which in turn connects to the DIGS just south of Dauphin Island . OEDC bored an almost milelong tunnel through Dauphin Island and ran three 12-inch pipes through the island-one for 

immediate capacity, and two for expansion. Figure 4.2 shows the location of DIGS in relation 

to other existing pipelines in Mobile Bay. 

Gas emerges from the northern shore of Dauphin Island, flowing through the 20-inch DIGP 

pipeline (a partnership between Enron and OEDC) that travels onshore to OEDC's metering 

station and the Transco and Koch Interstate pipeline systems . On its way to shore, the 20-inch 

DIGP pipeline travels through the North Dauphin Island Field, where it connects with gathering 

lines from platforms in state blocks 71, 72, and 73 . 

OEDC expanded the pipeline from its 822 platform through federal waters to the east to connect 

platforms in Mobile Blocks 870, 914, 915, and 916. In January of 1994, OEDC installed 20-

inch pipe for a 40-mile extension from BP's Mobile 821 platform south across federal waters 

to Block 954 in the southern Mobile area and still further south into the Viosca Knoll OCS area. 

This pipeline began transporting gas to market in late 1994 .81 

IOEDC Prospectus October 9, 1996, p . 40. 

g'OGJ, "Mobile Bay gas flow rising in response to E&D campaigns," January 10, 1994, p . 23 . 

86 
To shore To shore 

' ona r rw 

- - - - - i , 

J { I i I 

55 ~ a ' 56 -57 ~ " 58, Yp :59 160 ' 81 62 ' 83 ' 64 . 65 . 66 

1 . . ; . . . . . - - - - - - ~ - - - - - - - - - ~ - - .. . . ~.. ' I . . ... . ., . ~ - - - - , - - - ~ - -~ - - - - - ~ ; - - - - - -

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. . 

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, 

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75 

!79 

69 ~ ' 70 '71^w r72 , 7 X 74 76 77 178 I 80 

- - " ~ - - - - - - " - " - - " " I-- -- - 

87 ~ .88 ,89 , .90 ,91 ;92 ,93 '94 .95 96 ;97 ,98 

- -I- -- - ------r------~-----------~-

106 ~ - -,'107 _ _ - .108- _ _ - 109 """ 111 .112 1113-~ '114 ~ ;115 ,116 ,117 

1 .~ 

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I 131 1 132 (133 

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' 1 . . . .,w. ' . .,.~ ' ., . .~ ~ ., , ., . 

., ., 

906 907 1908 1909 0 '91 1 '912 '913 ' 914 ' 915 916 1917 

., 

950 1 ' 951 1952 -953 1954 - 955 958 . . - - ; 957- '.958 959 980 _ _ _ _ 961 

-~ ~ 

994 '995 ' gg6 ' gg7 '998 '9991000 .1001 10021 .1003 X1004 '1005 

Figure 4 .2 . Dauphin Island Gathering System. 

DIGS 

Source: Foster Associates, 1997 . 

00 

J 
DIGS current capacity is 400 MMCFD but construction during 1997 increased the DIGP 

connector capacity from Dauphin Island to the onshore terminus to 450-550 MMCFD, and 

extend the pipeline south to provide gathering services in Viosca Knoll and Main Pass East 

Addition areas. The DIGS extension will provide the first northern outlet for gas from the East 

Central Gulf Area to East Coast Markets. A substantial quantity of gas from the deep water 

development in the vicinity of Main Pass block 225 will move north over this pipeline by winter 

1998 . OEDC and partners will operate a NGL plant at the terminus to strip the NGLs from the 

deep water gas south of Mobile Bay. 

4.6.3 Chandeleur Connection 

The fields in the western portion of the Mobile OCS are connected to the Mobile Area Gathering 

System (MAGS), which connects to either the Chandeleur pipeline of Pascagoula, or to Canon's 

Interstate connector in Mobile County. Chandeleur is a pair of pipelines (one 16-inch and one 

12-inch) that extend from the Mississippi shore through the western edge of the Mobile OCS and 

further south into the Chandeleur OCS. ODECO owns a six-inch gathering system that connects 

Mobile 955, 954, 953, and 952 to Chevron's "A" platform in Mobile 908. Gathering lines 

connect Chevron's Mobile 908 "A" platform to wells in Mobile 863 and 908. From Chevron's 

Mobile 908 "A" platform, gas flows through a 12-inch line to Mobile 861, where it enters a 12-

inch spur owned by Chandeleur, travels through Mobile 904, and connects with the Chandeleur 

pipeline system. Chevron constructed a 12-inch pipeline to connect its Mobil 861 platform with 

the Chandeleur pipeline system in mid-1995 . 

4.6.4 Production Start-Up : Miocene 

ARCO came on-line with the first Miocene wells producing for the commercial market and 

became the second producer in Coastal Alabama, following MOEPSI . After drilling three gas 

wells in 1990 in tracts 71, 72 and 73, ARCO moved to immediately develop their discovery . 

Like the Norphlet developments, the environmental sensitivity of the Dauphin Island setting was 

a critical consideration. Ultimately, ARCO applied several innovative technologies to bring the 

North Dauphin Island and Northwest Dauphin Island Fields into production. Horizontal drilling, 

not typically used for shallow wells, was used to reduce the number of wells . Pipelines under 

shorelines were bored to reduce the impacts to wetlands and oyster beds. A special platform 

design was used to prevent rainwater from coming into contact with the main deck of the 

platform and then running-off into the Mississippi Sound. Zero discharge was expected of 

Miocene producers as well as Norphlet producers. Platforms were painted blue and gray to 

blend into the seascape and lighting was shielded to minimize the visual pollution to near-by 

onshore vacation homes ." 

ARCO initiated production in the North Dauphin Island Field (NDI) in December 1991 and in 

the Northwest Dauphin Island (NWDI) Field in March 1992. ARCO subsequently sold its leases 

and discovered reserves to Callon and Offshore Group in mid-1993 . Table 4.15 summarizes the 

BzR. P. Layfield, K. L. Elser, and R. H . Ostler, "Dauphin Island Natural Gas Project," JPT, January, 

1994, p . 63 - 66 . 

88 
Table 4.15 

Summary of Mobile Bay State and 

Federal Miocene Production 

(BCF) 

Cumulative 

Field Current Operator 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 Thru 1997 

State 

East Mississippi Sound Legacy - - - - - - - 0.1 1 .8 0 .1 2.0 

Goose Bayou Legacy - - - - - - - 0.1 1 .3 0 .1 1 .5 

North Dauphin Island Callon - - - 0.2 193 15 .9 11 .1 7.4 3 .8 2.1 59.8 

Northeast Petit Bois Pass Offshore Group - - - - - - 0.4 0.1 1 .2 0.5 2.1 

Northwest Dauphin Islam Offshore Group - - - - 0.6 0.9 2 .0 1 .2 0.9 0.6 6.2 

South Dauphin Island SCANA - - - - - 0.6 3.5 2.6 1 .5 0.7 8.9 

Southeast Mobile Bay MOEPSI 0.2 0.1 - - - - - - - - 03 

Subtotal State 0.2 0.1 - 0.2 19 .9 17 .4 17 .0 11 .5 10 .5 4.1 80.9 

Federal 

Mobile 823 Scana - - - - - 2.3 6.8 5.2 3.2 2.1 19 .5 

Mobile 861 Chevron USA - - - - - - - - 0.0 2.0 2.0 

Mobile 864 Chevron USA - - - - 18 .8 20 .5 18 .2 13 .8 11 .5 8 .7 91 .5 

Mobile 865 Scana - - - - - - 2.9 3.4 2.8 1 .5 10 .6 

Mobile 866 Scana - - - - - - 0.9 0.9 1 .0 0.6 3.4 

Mobile 870 Enron - - - - - - 1 .1 4.7 53 5.6 16 .7 

Mobile 914 Enron - - - - - - 1 .0 2.5 1 .5 0.7 5.6 

Mobile 945 Apache - - - 0.1 1 .1 0.8 0.6 0.5 0.2 0.1 3 .5 

Mobile 947 Apache - - - 0.1 1 .9 1 .6 1.0 1 .1 0.9 0.6 7.3 

Mobile 952 Murphy - - - - 0.8 1 .1 1 .0 1 .0 1 .3 3 .4 8.6 

Mobile 955 Murphy - - - - 1 .0 1 .4 1 .2 1 .1 1 .0 0.9 6.7 

Mobile 959 OEDC/LJnocal - - - - - - - 4.9 3.1 1 .4 9.5 

Mobile 959 OEDC - - - - - - - 0.9 0.6 0.4 1 .9 

Mobile 961 Unocal - - - - - - - 1 .4 13 0 .8 3 .5 

Mobile 990 A ache/Enron - - - 0.4 4.3 3.9 2.9 2.5 1 .8 1 .2 16 .9 

Subtotal Federal - - - 0.6 27.9 31 .7 37.5 44.0 35 .4 30 .0 207.1 

Total Miocene Production 0.2 0.1 - 0.8 47.8 49.0 54.5 55.5 45.9 34.1 288.0 

00 I Source : AL Oil and Gas Board, 1997 ; Dwights/PI, 1997 ; US DOI MMS, 1998 . 
production from fields by current operators. ARCO's production from the North Dauphin Island 

Field averaged 53 MMCFD in 1992 while the Northwest Dauphin Island Field produced less 

than 2 MMCFD. The NDI production rate and the amount of gas produced through year end 

1996 is uncharacteristically high for a Miocene structure. No other State of Alabama Miocene 

field has produced such a quantity of gas, or produced at such a high rate. 

Inspection of Table 4.15 shows another Miocene field in the OCS with comparably high and 

sustained production. Miocene 864 Field hit 56 MMCFD in 1993 and has produced 83 BCF 

at year end 1996. Chevron's tract 864 is immediately contiguous to Murphy's tract 908 which 

was an unsuccessful Norphlet play . The unusually high and sustained Miocene production rate 

from tract 864 may be the gas missing from the "very good" Norphlet sands Murphy probed 

with 908-2 and two sidetracks .83 If so, not all Coastal Alabama Miocene gas is necessarily 

biogenic in origin . If the high production from 864 and NDI may be Norphlet in origin, the 

distinctive HZS signature present in all other Norphlet gas is missing . Wellstream analysis of 

the state NDI wells shows that they are 98 - 99 percent methane, with Nitrogen being the second 

largest component. 

Production stepped-up annually through 1995 from Coastal Alabama Miocene fields after DIGS 

was in place . Figure 4.3 shows the production through 1997 from the state and federal Miocene 

fields . Production from the producing Miocene reservoirs appears to be in decline . Table 4.15 

shows that through year end 1997 Miocene production totalled 288 BCF. 

83Telcon with Murphy exploration manager, May 16, 1997 . 

90 
160 

140 

120 

100 

A 

w 

V 80 

60 

40 

20 

0 

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 

[

" AL State D Mobile OCS 

Figure 4.3 . Summary of Mobile Bay State and Federal Miocene Production. 

Source: AL Oil & Gas Board ; Dwights/PI; MMS, 1998 
5.0 State Field Definitions from AOGB Dockets8l 

Companies file substantial information with the AOGB as required by State of Alabama 

regulations . The following subsections report selected information about their reservoirs 

submitted by Exxon, MOEPSI and Shell . The purpose of the section is to show how the 

predominantly northwest-southeast trending eolian sandstone Norphlet reservoirs appear and how 

faults dune the areal extent of the reservoirs . Similar information for federal fields is not 

available. 

5.1 Exxon Bon Secour Bay Field 

Exxon's Bon Secour Bay was named and defined by AOGB Order 85-345 in Docket 12-19-85 . 

Tracts 62, 63 and 64 were originally included in the field. This was amended to include tract 

78 and the northeast corner of tract 77 on April 15, 1992. Mr. Jeff Durrant appeared for Exxon 

with attorney Tom Watson to revise the field limit as shown on Figure 5 .1 ; i.e ., to incorporate 

the segment of tract 77 northeast of the fault shown on Figure 5 .2, 1306 acres in total that do 

not contain Mobil's Mary Ann reservoir, and do contain the Bon Secour Bay reservoir. Mr. 

Durrant testified that four wells had been drilled into the reservoir from each of Exxon's tracts . 

Exxon's well locations can be seen on Figure 5 .1 . Mobil's eight existing 1992 Mary Ann Field 

wells are also shown. Figure 5 .2 shows that the wells in tracts 63 and 78 are on either side of 

the top of the reservoir structure, which follows the fault that runs northwest to southeast from 

tract 63 to 78. The fault, which is also visible on MOEPSI's exhibits, seals the Mary Ann Field 

and separates it from the Bon Secour Bay Field. Exxon testified that "the most orderly and 

efficient development of the . . . revised formation will avoid the drilling of unnecessary wells, 

. . . prevent waste, and . . . protect the coequal and correlative rights of all unit owners ."" 

Two east-west trending faulted salt anticlines, which are the traps for natural gas in the field, 

can be seen on Figure 5 .2 . Average net pay in the field is 136 feet . Reservoir sandstones are 

interpreted as eolian . Porosity averages 12 percent and permeability varies from < 0.01 to up 

to 44.6 md. While truncated on the west border of Exxon's tract, the reservoir can be inferred 

to extend west to tract 61, which Mobil leased in 1993 for $1 .5 million in bonus payment. 

5.2 Exxon North Central Gulf Field 

Exxon's North Central Gulf Field was named and defined by AOGB Order 86-239 in Docket 

9-5-86 . Tracts 114, 115, 116, and 117 were included in the field. Witnesses appearing for 

Eon with attorney Tom Watson testified that the four tracts are underlain by a continuous 

geologic structure on the Norphlet Formation with a common gas pool . This is shown on Figure 

5 .3 . Well 115-1 was the discovery well for this reservoir at a measured depth of 21,456 feet . 

"These descriptions draw from company sponsored testimony at the AOGB and from Bulletin 140 of the AOGB. 

Mink, Robert M., Berry Tew, Steven Mann, Bennett Bearder, and Ernest Mancini, "Norphlet and PreNorphlet Geologic Framework of Alabama and Panhandle Florida Coastal Waters Area and Adjacent 

Federal Waters Area," AOGB Bulletin 140, 1990 . 

BZAOGB Docket 4-14-929 . 

92 
Figure 5 .1 . Bon Secour Bay Field Limits . 

W 
\zO O 

.2 

\1500 

k 64 

A'.~1° F a o 

0o \ 

,i\ Q) 

A 

EXXON COMPANY USA 

DOCKET 4-14-929, 9210 

EXHIBIT 3 

HON SECOUR B 4Y UNIT EXPANSION 

TOP OF NORPHLET STRUCTURE 

PREPARED Br J.M .DURRANT MARCH 24 . 1992 

M1 

Qg00 

77 

F U1'. . AND f.F1S BOARD ' 

C~xo~Y.------ 

._, 

Item 

leslimoriv 

Received 

Figure 5 .2 . Bon Secour Bay: Top of Structure . 
J, 40BIL I 

'N'2 5/L 348 

n ~ :1 o 

' ;'8 .' 

97 

93f 

MOBIL 

I I 5/1 350 

:Y 20 .99 9iE2 

O ~ FORTIAORGAN PENINSULA 

0 _j 

o° 

S,L 62 . 

_ x1 ,ass pies 

~ 133 

iso° 

W

s

__1421600 

MARY ANN FIELD 

UNIT BOUNDARY 

96 

S~J=. 

827 

ezs 

STS 

PLACID 

." 1 OCS-0 3707"N 

21,728 3/BS 

21,717 B/BS 

si p 

I [xxorr 

e"~ r ~ sn szo W 

21 .750 :yes 

. t. .. 

y $l 

Y1 I71p ~1~G ~, 

B 

_75/L 53 

0C if820 

t98 99 

N 

w ? 

C"' '.. 

j 

?~'{oo : STATE OIL AND a Exhibit No. 

600 FAULT Y Petition 8y EKXE 

item No. 

o Testimony Of - r- . . 

\-2160o Received By 

C" 929 

e. Figure 5 .3 . North Central Gulf Field Structure . 110 L-11 I 
The Exxon witness testified that the gas reservoir on OCS tract 827 is a part of the same 

reservoir underlaying tracts 114 and 115 . The reservoir is defined on the southwest of tract 114 

by the fault labelled Fault Z. The fault can be seen running into tract 113, Shell's lease . 

Placid's well in OCS tract 826 was water bearing proving that Fault Z seals the reservoir on the 

south. The northern edge of the reservoir is defined by Fault Y on Figure 5 .3 . Well 97-1 north 

of the fault was water bearing, proving that the reservoir is sealed by Fault Y, which also seals 

the eastern edge of the reservoir. 

The hydrocarbon trap in the field is the elongated east-west trending salt anticline, truncated on 

the north and east by Fault Y, which extends northwesterly into Mobil's tract 95 . The Norphlet 

formation is thinner in the North Central Gulf than in the other offshore Norphlet fields, ranging 

from 120 to 160 feet. Eolian dune sandstone comprises the depositional environment. 

The wellstream analysis shows that Exxon's North Central Gulf Field produces gas with carbon 

dioxide concentrations typical to other local Norphlet fields, but with much lower in HZS 

concentration than the Bon Secour Bay and Lower Mobile Bay Fields-between 300 and 650 

ppm as shown on Table 5 .1 . This proves that the field is not in contact with the reservoir in 

the contiguous Mary Ann Field. Exxon testified that the gas in tract 112 contained 40 times 

higher concentration of H2S than measured in tracts 114 and 115 . 

Table 5.1 

Eon Wells 115-1 & 114-1 Full Wellstream Analyses 

So 

Component S/L 538 No. 1 

Tract No. 115 

S/L 625 No. 1 

Tract No. 114 

Methane 87 .8094 81 .6009 

Ethane 5 .1768 8.1108 

Propane 1 .8705 4.0283 

iso-Butane 0 .5377 1 .2805 

n-Butane 0 .3583 0.8869 

iso-Pentane 0 .1110 0.3143 

n-Pentane 0 .0436 0.1245 

iso-Hexane 0 .0065 0.0366 

n-Hexane 0 .0034 0.0178 

Heptanes Plus 0.1015 0.2750 

Hydrogen Sulfide 0.0030 0.0065 

Nitrogen 0.1375 0.1597 

Carbon Dioxide 3 .8408 3.1582 

100.0000 100.0000 

urce: Alabama Oil and Gas Board, Exhibit 14, Petition by Exxon, Item No . 1 ,20,21 ated 9-4-86. 

96 
In 1993, Exxon returned to AOGB to propose that the North Central Unit be partitioned into a 

114 Unit and a 115/116 Unit. The proposed 114 Unit is shown on Figure 5 .4 to include tract 

114 and the northeast corner of tract 113 . Exxon witness Martin Fleckenstein testified that the 

"Tract 114 gas reservoir is separated from the North Central Gulf Unit consisting of Tracts 115 

and 116 by an interdune area with no reservoir sand present. 1183 Exxon's 114 wells are shown 

as well as Shell's five producing wells. 

Figure 5.5 shows the reservoir structure underlaying tracts 113 and 114 . Sealing faults in tract 

113 and on the northeast of 114 are described as defining the reservoir structure. Figure 5 .5 

does not depict the extension of the structure into MOEPSI's tract 95, but no indicated sealing 

fault is shown. Figure 5 .6 depicts the deposition of the sands that typically form the Norphlet 

structures . The darker areas represent the thicker sand; the white area represents the interdunal 

area in which Exxon's well 114-1 found gas that flowed at only 1 .2 MMCFD in 1985 . The 

witness stated "The Norphlet formation in the Mobile Bay area including the tract 114 Unit was 

deposited as large linear dunes in a desert environment. These sand dues consisted of thick 

parallel sand bodies oriented northwest to southeast that were separated by thin interdune areas . 

This depositional style is responsible for the characteristic thick-thin geometry of the Norphlet 

in the Mobile Bay area including tract 114. "1 

5.3 Eon Northwest Gulf Field 

The Northwest Gulf Field was named and defined by AOGB Order 86-269 in Docket 11-21-86 

to include tracts 110, 111, 112 and 131 . It was amended to exclude tract 110 in Docket 9-19-

873 . Testimony in the 1987 docket showed that tracts 111, 112 and 131 are underlain by a 

common Norphlet gas pool. Well 112-1 was tested December 1984 at 21,500 feet as the 

discovery well . Figure 5 .7 shows the common structure that underlies the three tracts but does 

not show structural interpretation on other operators' (Mobil and Shell) adjacent leases, although 

the structures can be inferred to extend into OCS 823 . The structural interpretation extends into 

Exxon's then-owned tracts 90, 91 and 92 to show the fault complex that separates the Northwest 

gas pool from areas to the north. Exxon well 91-1 encountered water north of Fault Y which 

is visible on the figure proving that the fault defines the northern boundary of the gas pool under 

111 and 112. 

The hydrocarbon trap is an east-west trending, faulted salt anticline . The dune sandstone in the 

reservoir is predominantly eolian deposition with an average thickness of about 400 feet. 

5.4 Shell Fairway Field 

AOGB Order 86-280, Docket 11-21-86, established the Shell Fairway Field consisting of tracts 

113 and 132. Testimony in Docket 12-13-90165 by Mr. R. J. Stancliffe described the basis for 

the unitized area of the revised Fairway Field . Figure 5 .8 shows the location of the structures 

underlaying tracts 113 and 132 along with wells drilled and proposed in 1990 . Figure 5.9 shows 

83AOGB Docket 11-9-937, p. 287 . 

'AOGB Docket 11-9-937, p. 295 . 

97 
\-o 00 

315000 320000 330000 340000 350000 360000 370000 380000 

85000 

:~,::~:: i. ~ :~ :t:~ :~: . ... . . .. .... ..~d~ ., ... . ... .~ ... .~ .. . ~ i ~ i ~ 

... . 

.~ ., . tn ..... .. . 

... ..... .. . .... .. ... ... ..... .... .. . . . ... . 

..... ..... .. . .. .. . ... ..... .... ... . .. .... . ...... .... . ...... ... 

.... .... .... ..... 

..... 

.... .. ..... ., ...... .... . . .... .... . .. . . 

. .....~ :~ :::: ::::.. ..... . . ..... ... . . . ... . .... ..... .... ..~:: :~ 

.. .... ..... . 

. .. . : ::~.:- . a 

.. ..... .. - 85000 

. . . . ... . ... ... ... .. .... .... . . 

I I .~:... i .i. .n:: .... 

... . ..... ... ... . ... :, ~ :: .. ..... ... 

. ... 

80000 ~ ~ - -- 

-- 

097 S/L 80000 

75000 

i 

i 

5000 

i its iit iii 

,~114S/L 

i 

70000 ~#~3. ~~} 

113S/ 

2 ; ~ 

1 

70000 

i 

1 16 S /L 

65000 ~ 

113S/ " ~ ~ S /L 

1 

~ 827 CS 65000 

ff 26 OCS 

60000 ' -- 60000 

I S~ ' 7 ~ f 132 S/L i i 3 

826 827 

55000 I .: ! .-! ~ C. ._ . . . . . ~ . . . ,~ 'n~ ssooo 

EXXON COMPANY USA 

_^ 

e 7za S 

DOCKET N0.11-9-937 

. ' r ~ . . . . ._ . . . . 

50000 

. 

50000 

TRACT 114 (NORP6IET) UMT 

eYafefr i 

45000 45000 

9 am 

rtn SC11E-8000FEET NICN 

PREPMmBYY. fLECKENSTON , NOVEMBER 0.1G93 B%1 ' . ._ .._ ._ . . _ . .. . .~ . ..~ .~-R-. ?~2--- .._. . .. ..._ __ .__ . 

40000 ~ 40000 

W315000 320000 330000 340000 390000 3BOO00 370000 38000p 

Figure 5 .4 . Exxon Tract 114 Unit Expansion. 
Z3 

Figure 5 .5 . Exxon Tract 114 Reservoir Structure . 

1.0 
., 0 0 

i 

. . , 

. . . . . 

. . 

Figure 5 .6 . Exxon Tract 114 Reservoir Dunes . 
Figure 5 .7 . Exxon Northwest Gulf Structure . 0 
., 0 

N 

«_-- 

Figure 5 .8 . Shell Fairway Field Structure . 
Figure 5 .9 . Shell Fairway Field Dunes . 0 W 
that tracts 113 and 132 "consist of two Norphlet pods of varying thicknesses which extend into 

and across both tracts . . . . [T]he Norphlet has very good reservoir characteristics both in terms 

of porosity and permeability . . . [and] excellent lateral continuity which we feel equates to an 

extensive per well lateral drainage capability ."" 

The fault that separates the Fairway Field Unit from the 114 Unit is visible on Figure 5.8 . 

Shell's witness stated that the bottomhole pressures between the 113-1 and the 114-1 differ by 

greater than 2000 psi, suggesting different reservoir accumulations . The witness also stated that 

a large fault located along the northern border of tract 113 separates Shell Fairway from the 

Mary Ann Field. The hydrocarbon trap in the Fairway Field salt anticline trends northwestsoutheast . 

Mr. Len Falsone testified that Shell intended to develop the field with five wells producing 40 

MMCFD each beginning in the fall of 1991 . These flow rates were thought to be high but 

consistent with reservoir properties and comparable data from Mobil tract 823-3 well which was 

tested at 62 MMCFD in 1990. 

In 1993, Shell appeared with Exxon to confirm that the northeast corner of 113, separated by 

the fault is in a common Norphlet pool with the Exxon 114 Unit . Shell witness Claudia 

Hackbarth confirmed that the reservoir northeast of the fault in 113 extends to the "adjacent 

tracts to the north and east leased by Mobil and Exxon, "g6 as shown on Shell Figure 5 . 10. She 

further testified that "Exxon's tract 114-2 well will likely drain the entire central pool shown in 

this cross section. "8' This statement preceded Mobil's well 95-5 into the same reservoir. The 

location of MOEPSI's well 95-5 (not shown on the figure) in the southwest corner of MOEPSI's 

tract 95 clearly penetrates the common reservoir. 

5.5 MOEPSI Aloe Bay Field 

Mobil's Aloe Bay Field was established by AOGB Order 92-17 in Docket 2-6-92 to include 

tracts 74, 75 and parts of 92 and 93 . The field is located west of the Mary Ann Field as shown 

on Figure 5 .11 . Mr. Peter Andronaco appeared as Mobil's witness to demonstrate that the Aloe 

Bay Field was discovered by well 75-1 and underlies much of Dauphin Island as can be seen on 

Mobil Figure 5.12 . Figure 5 .13 is the structure map of the Norphlet Formation in the Aloe Bay 

Field. The two westernmost Mary Ann wells 76-1 and 76-2, the 91-1 well and the Aloe Bay 

discovery well 75-1 are shown on the figure . The witness explained that "the structure tested 

by the 75-1 well is a syncline separated from both the Mary Ann Field structure to the east and 

the Tract 91-1 and 91-1ST wells to the west. . . . The gas-water contact associated with the 

Tract 75-1 discovery well is distinctly different from the gas-water contacts in the gas 

accumulation to the east and to the west. The 75-1 contact of 21,012 feet subsea is 133 feet 

shallower than the water contact in 91-1ST well to the west and 136 feet deeper than the water 

IAOGB Docket 12-13-90165, p . 405-406. 

86AOGB Docket 11-9-933, p. 266. 

$'AOGB Docket 11-9-933, p. 268. 

104 
Exhibit No. 3 

Docket No. 11-9-933 & 934 

Shell Offshore Inc. 

Fairway Field Unit 

Offshore Alabama 

Top Norphlet Porosity 

eLp _ 94 

I 

' ~ BILK . 95 

N StrucUire, 10 /92 , n ' 

Gas/WalerContact -21,500' 

0 3000' ~ I 

$ 

r '~~b~`frt~ 

Prepared by: C .J . Hackbarlh 10193 ~ ` nu ~ ~ ~ ~'~y 

~ ~~ r, 4 I. 

- 

, 

' " ' ' ' 

4 

I J C 

a 

. . . . ~ . ._ . .~ i 

/ Ih ,r 

Q 1 -21 .924' 

j <jVl-~-~~ _ .1 - t ~+ r 

g± ~ 11-~z :~'3 _ 9 

A 

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114 

i BI-K . 

. " : " ' . Yti4, 

, y.. 

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o 

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/21,241' 

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n FT No N6.9-24-926 ,~\ 1/,60 

SHELL OFFSHORE INC. 

'fRA 14 (NORPH UNIT 

, 

\ 

OF RE A 1A 

70P NORPFII .Ef IN . STRUCTURE 

G-lSWAR -21,SW' \ 

0' 

r` ~, 

13 \ \ / 

/ ~ SCALE 

~ 

BLK . 826 

BLK . 132 

I rnN(n BY : R.I.STnNaurt ~ng_ 

r BILK . 133 / 

~ " \ / 

-21 .508' 

f6 11u~OP~.~O" Ildl~ln' .I .PIn 

Figure 5 .10. Exxon & Mobil Common Structure . 0 LA I 
.r 

57 58 059 60 , ~ 61 62 63 64 

d ON E UR BAY FIELD 

P OPOSm 

110 BAY FIELD 

---__WEiT AUPMN 72 73 j 7.A , 75 7 77 78 79 8( 

ISLAM ) FIELD 

---- --- ~. ..; . + 

LOWER w BAY - 

~IA ElD 

88 89 gp , 91- 42 

J3 

. 

- 

94 

- 

95 ,~ ~lu~'~y ~~~~~ 

I 

r . ,: ~ 

` 'I I 

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. ~ 

_ 

96 97 9f 

107 108 Mpg I 110 111 112 

82 

113 114 115 116  11 . 

'' ezz 3 pRTHW~ET NORTH F FELD 

_ 821 l!L!~ FIELD 

M WAY 819 820 ~OIlILE "41 F 

"._ 

6 827 -- 828 MOBILE FIELD ZS MELD 

824 132 13 

864 865 $fi6, 867 868 !J, 

_~ 

~'~ \ 870 871 72 

- 

869 

r- ~-. 

907 90 09 911 ~ \ 913 914 915 916 

~ 

AND 3AS - 

STAT 

1 P e' . . . . 

L 

Figure 5 .11 . Mobil Aloe Bay Field Location. 
Figure 5 .12 . Mobil Aloe Bay Field . 0 

~1 
0 00 

Figure 5 .13 . Mobil Aloe Bay Top Norphlet Structure . 
contact established in the Mary Ann Field to the east . . . . Norphlet gas accumulation in the 

Aloe Bay Field is separate and distinct from both the Mary Ann Field and the 91 sidetrack ."" 

Full wellstream analysis of the test demonstrated that Aloe Bay gas is 8.4 percent HzS, as shown 

on Table 5 .2. The gas is sour like the Mary Ann Field gas. 

Mobil's Mary Ann Field gas plant was debottlenecked in 1996-1997 with an oxygen plant to 

double its sulfur handling capacity to 480 LT per day to handle the Aloe Bay gas. Aloe Bay was 

completed and brought on line during late summer 1997. 

Table 5.2 

Aloe Bay Well 75-1 Full Wellstream Analysis 

Component State Lease 701 

No. 1 

Tract 75 

Methane 87 .13 

Ethane 0 .16 

Propane 0 .00 

iso-Butane 0 .00 

n-Butane 0 .00 

iso-Pentane 0 .00 

n-Pentane 0 .00 

iso-Hexane 0 .00 

Heptanes Plus 0 .00 

Hydrogen Sulfide 8 .37 

Nitrogen 1 .00 

Carbon Dioxide 3 .34 

100.00 

Source: State Oil and Gas Board, Exhibit 7, Petition by MOEPSI, 2/6/92 . 

5.6 Lower Mobile Bay-Mary Ann Field: Revisited 

Lower Mobile Bay-Mary Ann Field was established by AOGB Order 80-209 and amended to 

excise the northeast corner of tract 77 on April 15, 1992 . Mobil reappeared July 17, 1996 to 

amend the Special Field Rules to "recognize the existence of the new pool within the unit area 

. . . a new Norphlet pool in the Mary Ann Unit and Field . . . in the same strata that can be 

88AOGB Docket 2-6-924, p. 150, 153. 

109 
correlated with the Norphlet formation in the State Lease 347 Well (76-1] ."g9 Figure 5 .14 

shows the wells that Mobil has drilled in the four leases . Mobil's witness Bob Jorden described 

the development of the southern portion of Tract 95 beginning with the spudding of the 95-5 

well in July of 1994, which deviated 7400 feet east from a rig located outside the shipping 

fairway in tract 94 . The well was eventually sidetracked to a better location 8100 feet 

east of the rig reaching total depth in October 1995 . Platform 94-C was installed in late 1996 

and production began in November 1996 . 

Figure 5 .15 shows the general northwest-southeast trending dune structures that characterize the 

eolian Norphlet sands that Mobil's witness Mr . Gerald Greiner explained. "Contour intervals 

illustrate the broad anticlinal nature of the Norphlet . . . reflecting the alternating depositional 

thins and Chicks respectively of the Norphlet interdune and dune areas. "' The figure also 

shows the fault to the south of tracts 94 and 95 (Exxon's fault Y shown on Figure 5.3) that 

separates the Mary Ann Field into two Fault Blocks, labelled "A" and "B . " Mr. Greiner made 

the point that 3-D seismic data were able to produce the figure thereby "clarifying the top and 

base of Norphlet, enabling accurate characterization of the reservoir [and] profoundly changing 

the aerial distribution of the Norphlet verses the 1986 map. "91 Figure 5 .16 shows the gross 

isopach map of the Norphlet to illustrate its classic dunal nature with thicks and thins within 

Mobil's four tracts . Figure 5 .17 shows the geologic depth cross section on the Well 95-5 and 

95-SST to emphasize the effects of 3D seismic data on well placement. " . . . [C]onventional 

2D seismic could be relied upon to supply information on structural position only . . . . Well 

locations are now planned to maximize both structural height and stratigraphic thickness."' 

Moving the well 800 feet further east from its original bottomhole location improved porosity 

from 11 .7 percent to 12 .8 percent and increased productivity of the well markedly .93 

The ST well tested 77 .3 MMCFD on October 23, 1995 . Mobil's witness referred to the gas as 

"a Norphlet pool previously undiscovered in the Mary Ann Unit" and asked that Special Field 

Rules be amended to recognize the new pool as included within the Mary Ann Field and Unit. 

5.7 State Geologic Structures Summary 

Figure 5 .18, taken from the Gulf of Mexico Atlas, pulls together AOGB exhibits presented in 

this section. State Norphlet reservoir tops and wells are depicted as of 1994 . No 

representations of federal areas are available . This structure map shows the magnitude of the 

state Norphlet area . 

$9AOGB Docket 7-17-964, p.95-96 . 

IAOGB Docket 7-17-964, p . 119 . 

9'AOGB Docket 7-17-964, p . 119 . 

IAOGB Docket, 7-17-964, p. 123 . 

9'AOGB, Docket 7-17-964, p. 131 . 

IAOGB Docket 7-17-964, p. 144 . 

110 
76 

z 77 

b 

'qM76-D 

76-A 

2 

77-B 

PROPOSED / M 

PIPELINE ; 2 ST 2 

94 ~ ~ 

I 

3 

95-E r~ 

~ 4 

7K 

95 

' 

- 

5 SSii 

MOBILE BAY 

EXISTING PIPELINES 

e 

9`}I 95 ' FORT MORGAN PENINSUU 

PROPOSED PIPELINE 

Figure 5 .14 . Map of Mary Ann Development. 

1- 

-PROPOSED PLATFORM 

"-PLATFORM LOCATION 

3~ -GAS WELL 

- - -DEVIATED WELL TRACT 

E ..moir Ho. l Dockets 7-17-9se 

_ . 

Mobil Oil Exploration 

8 Producing Southeast Inc . 

LOWER MOBILE BAY-MARY ANN FIELD 

(NORPHLET) UNIT 

BALOtii14 A140 MOBILE COUNTIES . ALABAIAA 

MAP OF EXISTING DEVELOPMENT 

PREPARED 0l: P

.R .P,10'.ES DA7Et6-2~-96 

Cdi.f~(14YL11Qi0.0Y0FV7uiP . ' 
N 

77 

?l 750 

- 

SL 348 

v ~~so o - 

'21000 Z: 

So zi 

yr ?fOp~ ~ 2~5~0 

a o 

50 

o O L 

~ 19 \ J ~ ~.l 

,f L 349 `% \ /]/ ~o ~ 3 

If r f 

.s 

4NR 

\C_ ^' (' K 

1 . ¬ . 

PTO " o ~ J 

a~ so aul 

O 

t ,N u 

s 

Figure 5 .15 . Mobil Mary Ann Field Base Norphlet Structure. 

STATE OIL AND GAS BOARD 

Exhibit 

Petition '?y 

Item No . ..15A, 

?estimor; ;, 
/'/sa~-~- `V 

.a s 

~~. 

I R . . . ~ . ~ , A . 

: . . ~~~. . . . . . .~ . . : . . . ~ : : . . . : . . 

i1 . . ., : ., . . .~ 

~i 

~ ,3r~1 ~° ~u: 

: . 

1 v. . . 

v 

. . 

. . . . Q's 

. \ . 

'ATE OIL AND GAS BOARD 

;hi71t i0. .___.(_. -_....___ .. 

., , 

M ~2 

Figure 5.16 . Mary Ann Field Norphlet Gross Isopach. 

W 
West MARY ANN CROSS SECTION A-A' East A' 

xorw 

oaoo 

:csoo 

rasoo 

> r 

: 

150 

. . 

. _ . . . ._ . 

. . ._ . . . . . .., . . . . . . . . . . 

- 

yM uM 1 

11~1 

. . . . .. .. . . . . . . . . . . . . 

. . . . . . . . . . . . . . . . . . .. .. . . . . . . . . . . .. . . .. . . . . 

v~ lNH I i "oo ~ : ao a oo 

.. . . .. . . . . . . . . . . . .. . . 

. . . . . .. . . . .. . . . .. ._ . . . . . . ._ .. . ._ .___ . . ._ .. ._ ._ .__ . 

~~ ~e o v oo 

. . . . 

-- --- - - 

. . . . . . . . 

. . . . . . . . . . . . . . . . . . . .--------------- 

:~ x> x~ oo :a oo xr r 

. . . . . . . . . . --- -- -- 

. . . . . . -- ---- --- ------- . . . . . . . . . . . . . . . . . . 

TOP~ PO ROSITY 

:oo ' 

.~ .oo I 

I 

. :owo 

TOP NORPHLET 

. . 

\ 

. . . . ; 

-- - - --~-~-- - -- ---- 

. : . ~ 

------- - - ---- - ------- t , -- - ------ ------- ._J.~ 

. . 

~; -asn - 

- \ 

~ 

/ a~s~am %~, 

. / ; i' 

.- . 

- 

G /W CONTACT 4b-5 

----- --- :BASE NORPHLET 

~

. . . . . .. . . . . . . . . . : .--~---~--- -- --- -- ---- ---- ---- ---- ---- --- ------ --- 

- - --- 

. .- .-1 t- r - tom- --- .--- . . . . . . . . . . ; . . . . . ---- - ---- --- ----- -- ------ - --- .----. . .-- - --- ---- ,.~ 

- :rrw ~ooo xooo woo ~ooo soo woo ~ooo eooo vooo ~oioo ~~iaa ixiao ~~eoo ~~ioa ~7ioo ~uao ~rioo ieioo ~vioo ~qoo ~~iao ~xioo bioo x~ioo a~eoo ieiao ~iioo :eiao 

::too 

STATE OIL AND GAS BOARD 

Exhibit No . 9 

PetilinnBy MOETSj 

Item No . J_S,)~ J~ D;te, 7/Q ~ 

Te ;linony 01 JhD,1enG1 

Received 8y M R 

Figure 5 .17 . Mobil Mary Ann Cross Section-95-5 . 
0 5 mi 

i =T ' r-L-, --- 'i 

0 8km 

CoNOUr interval 100 h oMws7o~ 

Figure 5 .18 . Alabama Norphlet Structure Map. 

Source: U.S . DOI, MMS, 1994 . 
Figure 5 .19 gives a view of the areal extent of the Coastal Alabama Norphlet play, which 

extends southeast towards Destin Dome, and west-southwest toward Union's 904 Field. The area 

directly south of Mobile Bay mostly has been explored and no economic reservoirs of Norphlet 

gas have been found . 

116 
MISSISSIPPI i ALABAMA 

CZA 

Q- Uo_ 

0 

o U oo t 

Lower Mobile Bay- Mary Ann 

West Dauphin Island_0'' 

.~, 

N 

Mobile Bay 

Bon Secour Gay 

North Central Gull 

-- male i~a ~ .~-. 

. 

" 

- " M082

~

1 .-". A.3 

" ~+°" 2 M0823 /~ ~ 

.~.. . . .a 

aM0827 ~F i PENSACOLi 

- ~ ~ 

,, 

N 

a rw a 

.::  o hhweslGulf 

M 

~ " MOB 72 

M 0861 O O 868 

M0904 UU A 1 

M 09166 

. 

o 

0 

0 10 i M OBIL E AR EA m 

7-1 1 DESTIN 

0 VIOSCA KNOLL AREA I / I I I I I I I DOME 15 km 

Play boundary --- " -- State-Federal boundary ~« Cross-section line `Field in play O Field 

QAb4215c 

Figure 5 .19 . Norphlet Play Map. 

Source: U.S . DOI, MMS, 1994 . 
6 .0 Development Projects and Production History 

Exxon describes Norphlet gas development as an integrated system involving specialized 

technologies for production, spur lines, and processing . Over $4 .0 billion has been spent since 

the early 1980s installing these systems and drilling wells in addition to the $1 .4 billion in bonus 

payments to acquire the leases . MOEPSI, Exxon, and Shell located sour gas processing plants 

onshore Mobile County. BP, first, and subsequently Union and Chevron, decided to process sour 

Norphlet gas on the platform, shipping pipeline-quality gas on DIGS and saving the cost of 

special carbon steel spur lines to shore . Shell uniquely transports corrosive wet gas to shore for 

dehydration and processing at the Yellowhammer Plant, relying on a proprietary corrosion 

inhibitor compound Shell developed in lieu of water separation on the platform . 

This section describes the innovative approaches and technologies the companies applied to 

develop their Norphlet discoveries . Sections 6.1 - 6 .4 discuss MOEPSI, Exxon, Shell and 

Union/Chevron. Section 6 .5 tabulates facilities in place, summarizes production through 1997 

and projects annual production into the future in relation to remaining recoverable reserves by 

field. 

6.1 Development and Production of Mary Ann Field" 

MOEPSI filed a formal Mary Ann Field development plan in September 1984, having already 

received a permit to construct a gas plant in South Mobile County, near Coden, to process the 

hot, sour, high pressure, corrosive Mary Ann Field gas. Design, development, and production 

was a challenge every bit as herculean as the environmental hurdles of the 1970s. Many aspects 

of the project required new technology or new applications of existing technology . Mobil 

repeatedly put the total cost of exploration and development of the Mary Ann Field at more than 

$400 million through start-up in 1988. Subsequent expansions and successes in the federal 823 

and 869 Fields have raised Mobil's expenditures in Coastal Alabama to substantially more than 

$1 .0 billion. OG7' reported the following 1984 cost estimate for the Mary Ann Development: 

'This section draws extensively from two articles : 

J. R. Moseley, MOEPSI, "Mary Ann field facilities reflect Mobile Bay demands, conditions," OGJ, May 

8, 1989, p. 36 ; 

Richard A. Alexander, MOEPSI, "Environmental Method Controls Corrosion/Cracking in Mobile Bay," 

JPT, January 1990, p. 62 - 66. 

1OGJ, "First development, gas strike listed off Alabama," September 24, 1984, p . 44. 

118 
Mary Ann Fiel d Development Millions 

Well Drilling & Completion $204 

Platforms 122 

Pipelines 31 

Gas Plant 72 

Total $429 

6.1 .1 Safety and .Environmental Considerations 

The location issues alone ; given the HZS content of the Mary Ann Field gas, were 

overwhelming. The field is adjacent to resort, tourist and historic attractions. Laying between 

Fort Morgan on the Gulf Shores peninsula and Fort Gaines on Dauphin Island, Mary Ann Field 

is the site of Admiral Fanagut's good fortune with those "damn . . . torpedoes" in 1864. 

Sunken ships from that battle and "literally thousands of cannonballs and other battle debris 

remain scattered across the bay."' The shipping fairway passes through the Mary Ann Field 

and serves traffic to Mobile, the 12th largest port in the United States . Mobile Bay's prized 

oyster grounds are just a few miles northwest of tract 76. The Mary Ann Gas Plant is four 

miles from the town of Coden and within two miles of unique, world famous Bellingrath Home 

and Gardens, which receives about 175,000 visitors a year. 

A state-of-the-art environmental monitoring and warning system was installed to provide 

protection for the Mary Ann facilities and surrounding community . Six air monitoring stations 

were installed around the plant, on Dauphin Island and on the Fort Morgan Peninsula. Thirtytwo HZS sensors within the plant and 53 sensors on the offshore platforms detect HZS and warn 

operating personnel . 

6.1.2 Special Materials to Handle Norphlet Gas 

Production of the Norphlet gas required new methods to deal with the unusual gas. The gas 

contains all the ingredients necessary for severe metal-loss corrosion-HZS and COZ at relatively 

high pressures in contact with free water. All facilities had to be designed for 40-year life with 

zero risk of catastrophic failure . All of the platform's sour-process piping and vessels are made 

of carbon steel lined with corrosion-resistant alloy (CRA) tubing . Hastelloy C-276 was selected 

after 12 months of extensive testing as the CRA. This cold-worked, extremely tough alloy is 

recognized for its resistance to sulfide cracking and corrosion and its high temperature rating ; 

but it costs as much as ten times the cost of ordinary steel tubing used in standard wells. The 

well stream from each wellhead is injected with corrosion inhibitor oil (CIO) to protect the 

surface equipment. 

The Mary Ann Field development began with two platforms built by McDermott in Morgan 

City, LA, (76A and 77B), each designed for two wells producing 15 - 20 MMCFD, and one 

auxiliary platform (76Aux), designed as a central gathering platform bridge-connected to 76A. 

Platform 95E designed for 60 MMCFD was installed in 1988 . Each well stream is cooled from 

"Damn the torpedoes. Full speed ahead," Shell article, undated . 

119 
temperatures over 230° F to 120° F on the platforms . Produced gas is dehydrated on the 76A, 

77B and 95E platforms and dry, sour gas is pipelined ashore . Produced water and corrosion 

inhibitor oil (CIO) are pipelined to the plant for water disposal and reconditioning of CIO. 

Completion of the first two production wells, 94-2 and 77-1, began in June 1986. Production 

was initially anticipated before year-end 1986 . Leaks and problems ensued, however . A 

decision was made that the wells could not be safely produced without installing new casing 

liners because of corrosion. Four existing wells were reworked. First production did not flow 

until nearly two years later on April 5, 1988, from 77-2 at 15 MMCFD; 77-1 was brought online April 9, at 14 MMCFD. 

Processing on the platforms worked well for about a month, when pressure drops were 

encountered across the 77-2 and 77-1 production cooler . Expecting a sulfur clogging problem, 

the system was shut down. Minute volumes of "a white powder was discovered which was 

analyzed as a rare hydrocarbon called diamonoid . This substance had been found in 1983 in 

Canada's Hanlan Swan Hills Gas Field . . . . [Experimentation revealed] that modifications . . 

. of the CIO . . . and piping modifications avoided the contamination. "9g Diamonoids, 

produced under heat and pressure from carbon, are a relative to the solid, hard mineral 

substance found in jewelry . MOEPSI found the "diamond as big as the Ritz" just a few million 

years too soon. 

The fourth well, 76-2, brought field production up to 40 MMCFD sour gas in mid-July 1988. 

This well produced for two months and was shut in; it has never produced again. Production 

dropped back to 30 MMCFD by the fall of 1988 . A year later Mary Ann was still producing 

three wells below 50 percent of design capacity-40 MMCFD of sour gas, yielding about 35 

MMCFD of pipeline quality gas. Weak demand caused Mobil to delay installation of production 

equipment on its platform at the 95E location, which was brought on line in the summer 1989. 

Well 95-1 had a casing problem and was never produced. Two of MOEPSI's completed six 

wells, thus, developed mechanical problems, which caused them to be P&A'd. MOEPSI was 

the first to discover that maintaining production from $30 million Norphlet production wells is 

difficult. 

6.1 .3 Pipelines Used Special Techniques 

The offshore facilities are connected to the onshore gas plant by five pipelines : 

" 16-in. sour-gas pipeline ; 

" 6-in. bidirectional fuel-gas pipeline; 

" 8-in. regenerated (CIO) to offshore pipeline ; 

" 6-in. CIO/produced water to the plant pipeline ; 

" 10-in. spare pipeline . 

98J . R. Moseley, III, MOEPSI, "Lower Mobile Bay - Mary Ann Field Development," undated paper made 

available by Mobil. 

120 
The network is about 14 miles long, 10 miles offshore . The pipeline was buried deep under the 

ship channel by a boring technique instead of simple trenching to avoid any problems with 

shipping traffic. The boring technique was used to bring the pipeline ashore to avoid future 

problems with a deteriorating shoreline and at the Fowl River to avoid any intrusion with the 

bottom of the river. Oyster beds were carefully avoided . The rest was trenched 

McDermott's Marine Construction Division began work in October 1985 and finished laying the 

pipelines in July 1986. Laying all five pipelines at once greatly reduced the risk of pipes 

crossing over each other, and being damaged, but required special equipment to inspect the 

welds on each pipe section. The logistics of getting all equipment and personnel on the laybarge 

was the first obstacle . Protecting the workers from substantial X-ray exposure while inspecting 

welds was a major challenge . Storing all waste water on board to achieve zero discharge was 

another challenge . Gutters were built around the barge so that rainwater would not flow over 

the barge into the Bay:' 

6.1 .4 Norphlet H2S Variability and Mary Ann Gas Plant 

Sulfur variability-is a fact in the Norphlet fields . Not only does the HZS content vary widely 

among the different dune structures of the Norphlet formation, it varies within fields and within 

tracts . Producing wells in the Mary Ann Field vary from 3.2 percent HZS to 7 .6 percent as 

shown on Table 6 .1 . The two wells in tract 77 range from 3 .5 percent to 5 .9 percent. The 

newest well in production in the Mary Ann Field, 95-5, is only 40 ppm HZS while the 

forthcoming Aloe Bay gas is over 8 percent HZS. HZS in the 823 Field is less than 200 ppm in 

wells A1 - A3, but 2.3 percent in A4. 

Table 6.1 

H2S Content of Producing Mary Ann Field Wells 

Well 76-1 77-1 77-2 94-2 95-3 95-5 

HZS 6-7% 3 .5-5% 5 .9% 7 .6% 3 .2-3 .5% 0.004 

Source : Alabama Oil and Gas Board, 1997. 

The original Mary Ann Gas Plant was sized to process about 80 MMCFD sour gas containing 

7 .5 percent (avg) HZS and 4 .5 percent CO2, and produce 72 MMCFD pipeline quality gas with 

225 long tons a day of liquid sulfur . The gas plant removes the sulfur, C02 and water. CIO 

is recaptured and regenerated for return to the wells. 

6.1 .5 Mary Ann Sales and Transport Problems 

At the time of the 1979 discovery, the price of deep gas was about $4.00 MCF and expectations 

were that prices would rise to $7 .00 MCF with the deep gas provisions of NGPA . Decontrolled 

Pipeline and Gas Journal, "Specialized Techniques Developed," March, 1987, p . 38 - 40. 

121 
section 107 gas actually sold for more than $10 MCF for a brief period . MOEPSI made the 

decision to develop in third quarter 1984 when U.S. gas prices averaged $2.62 . When 

production started in April 1988, average U.S . gas prices were about $1 .40 at the wellhead. 

Having invested more than 20 years and $400 million, the Mary Ann project was uneconomic 

when it started production based on then current prices, according to Executive VP, Paul J. 

Hoenmans .'°° 

Mobil had difficulty finding a firm market for its Mary Ann production. Having surmounted 

the regulatory challenges of the 1970s and the technical challenges to develop and produce the 

Norphlet gas, finding a market became yet another challenge . When ANR Pipeline Co. said it 

could not take Mary Ann gas as scheduled, Mobil cancelled a contract with ANR in mid-1986. 

Transcontinental Gas Pipe Line Corp (Transco) later that year agreed to buy the gas for resale 

to Alabama Gas Corp in Birmingham . Algasco agreed to buy 18 BCF per year (50 MMCFD 

pipeline quality gas, or 58 MMCFD sour Mary Ann Field gas) for 15 years based on a formula 

that indexed to the price of alternate supplies . Transco built a lateral intrastate pipeline from 

the Coden plant north to connect to their trunk line at Butler, Alabama. Mobil received $2 .15 

MCF for its production, a premium of $0.60 above current spot, from Transco . 

6.1 .6 Mobil Mary Ann Field Production Profile 

Production from the Mary Ann Field began in April 1988 but only climbed to plant design limits 

after wells 76-1 and 95-3 came online in January and November 1990 . Well 95-4 was drilled 

and logged in May 1991, but never produced. Records show it temporality abandoned. 

Although eight wells have been completed, the Mary Ann Field original reservoir produces from 

five wells. Figure 6.1 shows the Mary Ann Field production profile through 1997 . Aloe Bay 

75-1 is included after July, 1997 . Field production climbed from below 40 MMCFD in January 

1990 to 80 MMCFD in February 1991 . Mobil achieved planned utilization of original facilities 

during 1991 as well 95-3 was ramped up. Well 95-3 is the original Mary Ann Field's best well 

producing as much as 35 MMCFD during 1996, with lower than field average H2S, 3 .5 percent. 

Field production has varied between 50 MMCFD and 100 MMCFD over 1994 - 1996 . Various 

technical problems-ranging from power outages to amine foaming problems-plus some selfcurtailment to limit production when prices are low and maximize production when prices and 

seasonal demand are high explain the monthly variability in field production . 

Mobil's newest well in the Mary Ann Field, 95-5, came on line during November 1996 

producing 66 MMCFD during 20 days of November and averaging 71 MMCFD during 

December and January. Field production topped 160 MMCFD in December, 1996, January and 

February, 1997 . With 40 ppm HZS, the 95-5 gas is in a different reservoir than the rest of Mary 

Ann production. This was the first of a new generation of Norphlet wells producing twice the 

average of the 823 Field wells, three to six fold as much as older Mary Ann Field wells, and 

more than any of Exxon's then-producing or Shell's wells. Enhanced 3D seismic capability to 

find the "best" place in the reservoir to produce, plus larger diameter pipes are key elements to 

the extremely high production rate of well 95-5 . Mobil's first well into the reservoir was judged 

capable of producing about 50 MMCFD; they sidetracked the well and averaged 70 MMCFD 

'°°OGJ, "Mobil steps up Norphlet gas flow off Alabama," July 18, 1988, p .18. 

122 
£Zi 

0 

c 

~-! 

n 

(D 

a 0 

00 

Ut? 

O 

O 

n 

O 

MMCFD 

N -P Q1 0o O O O O O O O 

1988/04 , -~----}---~--

1988/10 - 

1989/04 -

1989/10 -

1990/04 

1990/10 -

1991/04 

1991/10 

1992/04 

1992/10 

1993/04 

1993/10 

1994/04 

1994/10 

1995/04 

1995110 

1996/04 

1996/10 

1997/04 

1997/10 

N ~ O~ o0 

O O O O 
during November and December 1996 . The well is drilled with a 30° angle, but not horizontally 

completed . The well is considered a "world offshore cementing record [for] using foamed 

cement on a 9 5/8-in . drilling liner .""' The well technology plus the zero-discharge operating 

requirements were special challenges to completing the well. Keeping up production from the 

new well is also a problem. The well is on the edge of reservoir and close to water contact. 

Produced water and related scaling has become a problem. Production has declined from the 

high start-up rates to average 42 MMCFD during the fourth quarter, 1997. The well shut down 

for workover in April 1998. 

Table 6.2 shows Mobil Mary Ann Gas Plant 1996 total intake, intake by well, gas sales and 

sulfur production. About 70 percent of the 95-3 gas production goes to the Mary Ann Plant. 

The balance is routed to Shell's gas plant to make room in the Mary Ann Plant for gas from 

Mobil's federal field well 823-A4, which came in with HZS too high to process in the 823 plant. 

Mobil doubled its capacity of the Mary Ann plant to 160 MMCFD to take in the unexpectedly 

sour gas from 823-A4 well . That well tested 68 MMCFD with 2.8 percent HzS from 22,570 feet 

on December 11, 1990 . The high HZS was a surprise ; production was not started until March 

1994, after the Mary Ann Plant sulfur handling capacity was increased . The low HZS 95-5 gas 

goes to the 823 Plant. 

6.1 .7 Aloe Bay Field and Mary Ann Plant Expansion 

The S percent HZS Aloe Bay well 75-1 was brought online at 10 MMCFD in July, 1997 . Design 

production is between 30 - 50 MMCFD; the well averaged 24 1VIMCFD during the fourth 

quarter, 1997. The Aloe Bay Field is producing from a single platform just north of Dauphin 

Island . A three pipeline bundle transports gas and utilities between the tract 75 platform and the 

existing 76A platform in the Mary Ann Field for processing in the Mary Ann Plant . During the 

first quarter 1997, the Mary Ann plant averaged 141 MMCFD. Debottlenecking in early 1997 

increased the sulfur recovery capacity of the Mary Ann Plant from 285 LTD to 470 LTD to 

handle the Aloe Bay well and give the plant capacity for 180 MMCFD high sulfur gas . 

Production declines, well problems and warm 1997-1998 winter conditions have not tested the 

capacity limits of the Mary Ann Plant since Aloe Bay was added to production, as can be seen 

on Figure 6.1 and Table 6 .2. Mobil is considering adding a second Aloe Bay well, 75-2, during 

1998. 

The Aloe Bay pipeline bundle is bored deep beneath the northwest trending section of Little 

Dauphin Island between tracts 75 and 76 to avoid oyster beds and other sensitive environmental 

areas ." The route is shown on Figure 6.2 . 

"Glen Benge, Jim McDermott, Joey Langlinais, and James Griffith, "Foamed cement job successful in deep 

HTHP offshore well," OGJ, March 11, 1996, p. 58 - 63 . 

"Army Corps of Engineers, "Joint Public Notice: Emplacement of Pipeline System, Mobile Blocks 75 and 76, 

Aloe and Mobile Bays," October 28 1996. 

124 
Table 6.2 

Mobil Mary Ann Plant Gas Per Day 1/96 -12/97 

MMCFD 

Wells Gain thr. 

Total gas 76-1 77-1 77-2 94-2 95-3 95-5 823-A4 Aloe Bay 75 Plant 

Jan 96 147.230 12 .025 

Feb 148.263 13 .923 

March 121 .440 9.682 

April 145 .228 13.191 

May 147 .448 12.947 

June 151 .415 12.758 

July 148 .565 13.689 

August 151 .396 13 .838 

Sept . 151 .926 13 .435 

Oct. 128 .140 11 .261 

Nov. 142 .864 14 .597 

IIDec 138 .311 13 .189 

Jan 97 136.253 14 .584 

Feb . 155 .038 16 .190 

Mar 140.034 14 .624 

April 132 .284 14 .637 

May 67.098 7.712 

June 20.812 3 .109 

July 66.566 10.303 

August 47.072 4.773 

Sept. 139 .614 12 .218 

Oct . 137.782 1 1 .291 

Nov. 134.468 11 .186 

Dec 122 .669 9.725 

Source : Alabama Oil and Gas Board, 1997 

Sulfur 

Production 

Sales Long tons 

10.243 23 .685 12 .115 26.923 0.000 62.239 132 .190 232.510 

11 .770 24 .691 13 .984 23 .737 0.000 60.158 133.303 245.200 

8 .830 19.902 10.824 21 .909 0.000 50.294 109.123 219.232 

11 .245 25.212 13.076 25.432 0.000 57.073 131 .596 252.703 

11 .563 26.170 13 .720 25.439 0.000 57.610 132 .902 262.949 

11 .353 25.429 12.996 25.319 0.000 63 .571 137 .280 246.742 

11 .702 24.946 13 .070 22.912 0.000 62.245 134 .917 259.189 

12.097 25327 13 .889 24.685 0.000 61.560 137 .032 261 .932 

12.781 26.222 13 .581 25.242 0.000 60.664 137 .826 260.424 

10.902 23.625 11 .130 23 .365 0.000 47.856 114 .486 213 .881 

13 .248 28.777 14 .998 13 .870 0.119 57 .254 127 .480 220.206 

12.777 27.778 13 .916 14 .742 0.213 55.696 125 .283 279.793 

12.852 27.736 14 .031 14 .967 0.201 51 .884 124.166 249.545 

13 .678 29.744 14.875 16 .656 0.160 63.735 141 .802 276.423 

12 .354 26.865 13 .436 15 .044 0.145 57.567 128.079 249.672 

11 .930 26.148 11 .479 11 .372 0.233 56.486 119.599 228.504 

6 .973 15 .211 4 .077 1 .182 0.148 30.529 1 .265 60.099 124.613 

3 .277 6.444 2 .061 3.474 0.148 2 .299 0.000 17 .126 0.684 

9.615 18 .447 10 .042 0.017 0.241 7 .641 5.528 4.731 58 .083 175 .665 

6.458 13 .027 4.361 4.162 0.133 3 .434 9.518 1 .207 39.058 104 .140 

12.828 23.849 11 .815 4.838 0.090 45.812 27.257 0.000 127 .765 242.282 

10.485 21 .256 10 .948 9.696 0.071 47.953 25 .419 0.662 126 .112 269.833 

11 .012 22.808 11 .523 5 .025 0.130 47.775 24 .197 0.000 121 .682 260.461 

10 .297 21 .230 10.472 10 .776 0.105 39.151 20 .912 0 .000 110.459 253.097 

N 
N 

LEGEND : 

A -PLATFORM 

~ ::" : :" 

A ~WELLHEAD 

.~:; : : . ., . .OYSTER BED 

\~1 PIPELINE RUNNING UNDER LITRE 

DAUPHIN ISLAND 

PROPOSED PIPELINE ROUTE 

~~ .INSERTION POINT FOR DIRECTIONALLY 

DRILLED UNDERGROUND PIPELINE 

75 76 

MOBILE 

BAY 

- EXISTING --

PIPELINES 

0J 

d Qr 

..~O.~ 

_ ~Y 

H d 

0 N 

J 

PLATFORM 

<F~ 

ALABAMA 

YO&LE 

'RAY 

I 

SURVEY 

AREA 

LOCATION hUP 

Pti 

..AuxPUTFORM 

ALOE 

BAY 

'. +1 ." :~,:~'~ .~ ' " .FACIUTiES'r;;^.i 

~ ' ~~~ DAUPHIN ISLAND 

0 1000 7000 3000 1000 FEET 

Figure 6.2 . The Aloe Bay Pipeline Route . 

Source: MOEPSI, "Environmental Information for a Pipeline Route Within Blocks 75 and 76 Mobile Bay Area, Alabama," August 28, 1996. 
6.1 .8 Federal 823 and 869 Fields 

Mobil received MMS approval to construct the 823 platform and gas plant facilities in September 

1989 as the first Norphlet development in federal waters . McDermott Marine Construction 

engineered, constructed and installed the platforms and facilities in Mobil's 823 Field . Platform 

823A, a single well platform, went in mid-1991 at a cost of $41 million. The platform includes 

facilities for separation and dehydration of the gas. Production is separated and dehydrated for 

corrosion abatement on the platform. 

103 The Mobile 823 Gas Plant facilities began 

construction in 1990 and were completed in the third quarter 1991 . 

Gas started flowing at 40 MMCFD from a single well in November 1991 . Two more wells 

brought production to 160 MMCFD in March 1992 with less than 200 ppm HZS." At year 

end 1993, MOEPSI was producing 150 MMCFD from three wells in 823 to its 250 MMCFD 

capacity Mobile 823 plant. 

A 20-inch gathering pipeline system was installed from the 823 processing Platform A to the 

Mary Ann Auxiliary Platform for delivery to the 823 onshore treatment plant. Planned with a 

250 MMCFD capacity, construction was contracted in late 1989. A separate 8-inch line was 

required to deliver sour 823-A4 gas to the tract 76Aux Platform for delivery to the Mary Ann 

plant. 

Mobil's most recent well started production from the 869 Field in late January 1997 at about 60 

MMCFD. HZS is about 90 ppm. The well produced 78 MMCFD in February, 85 MMCFD in 

March, and averaged 64 MMCFD during the fourth quarter, 1997 . The gas is transported to the 

823A platform and then to the 823 Plant for processing . 

Figure 6 .3 shows the 823 and 869 Fields' production history from the start-up of 823 in 

November 1991 . Production averaged about 160 MMCFD from three 823 wells during most 

of 1992 . Production from Well 823-A2 was shut down for most of 1993, bringing field 

production down to 100-120 MMCFD. The high HZS well brought production above 190 

MMCFD in the highest producing months of 1994 . Production from the four wells varied 

between the 194 MMCFD peak and 170 MMCFD until late 1995, then dropped off in late 1996 

as wells 823-A1 and 823-A2 declined from peak. Well 823-A5, spudded in December, 1997, 

will stave off decline . Mobil produced close to 250 MMCFD of federal gas in March 1997 after 

869-3 came online . Production from the two federal field averaged 203 MMCFD during the 

fourth quarter, 1997 . Mobil, acting with partners Enron and Chiefton, spudded well 914-4 in 

December, 1997, to the southeast of producing well 869-3 to add to production from this area. 

Table 6.3 shows the 823 plant gas throughput. Beside the low H2S 823 wells, the plant is taking 

Hunt's 25 percent share of Exxon's tract 114 production, plus most of the gas from 95-5 and 

gas from the 869 Field. The plant capacity has been debottlenecked to 300 MMCFD. In 

January 1997 the plant received 193 MMCFD and sold 189 MMCFD. In February, March, and 

'o30GJ, "Norphlet gas development set in federal water," October 9, 1989, p . 24. 

`OGJ, "Gas flowing from field off Alabama," November 11, 1991, p. 27 . 

127 
N 

00 

300 

250 

200 

A 

w 

~ iso 

ioo 

50 

. . . . . . . . 

N N N M M M ~t ~ d ~ ~n ~n ~D ~p ~D l~ l~ (~ O~ Q~ O~ ~ O~ O~ O~ O~ O~ O~ O~ O~ O~ Q1 Q~ T O~ Q1 Q~ 

O ~ 0 O ~ ~ O ~ ~ O ~ ~ O ~ ~ O ~ ' ~ O z z z z z ~ ~ z ~ ~' z 

Figure 6 .3 . Mobile 823 and 869 Fields Norphlet Production. 

Source: Dwights/PI, 1998 ; Foster Associates, Inc., 1998. 
Total 

Table 6.3 

Mobil 823 Plant Gas Per Day 1/96 -12/97 

MMCFD 

Hunt 

25% 

Share 

Lease 

95-5 823-A1, 2,3 114 869-3 Sales 

Sulfur 

Production 

Long tons 

Jan 96 163 .554 147 .914 15 .640 160 .130 

Feb 167.972 152 .037 15 .935 164 .350 

March 165 .805 149.372 16 .434 161 .643 

April 170 .585 150.183 20.402 167 .150 

May 167 .954 147.515 20.439 164 .395 

June 168 .796 148 .115 20.682 165 .274 

July 162 .448 143 .564 18.884 161 .707 

August 146 .477 133 .985 12.491 142.778 

Sept . 144 .617 131 .948 12.669 141 .181 

Oct. 121 .813 111 .934 9.879 119.123 

Nov 175.821 44.115 118 .746 12.961 171 .351 

Dec 200.171 71 .956 83.624 12.333 194 .506 

Jan 97 192.813 69.378 110 .390 12.044 1 .001 189 .931 

~Feb 269.047 67.335 112 .229 11 .740 77.743 265.561 

Mar 247.731 44.396 107 .011 10.928 85 .396 244.221 

April 258.844 61 .635 105 .084 12 .079 80.046 254.693 

May 202.552 40.918 85 .028 9.286 67.321 200.083 

June 252.890 58 .273 108 .006 11 .671 74.940 244.880 

July 227.874 46.692 105 .079 10 .045 66.058 218.032 

August 236.206 42.649 111 .347 11 .570 70.640 230.037 

Sept . 230.271 49.061 101 .351 11 .637 68.222 225.252 

Oct. 211 .977 38.425 95.903 10.411 67.238 207.936 

Nov 219.163 47.805 95.473 11 .029 64.856 213.023 

Dec 191 .123 39.630 83.687 7.194 60.613 186 .645 

Source : Alabama Oil and Gas Board, 1997; US DOI, MMS, 1998 

0399 

0304 

0.318 

3.736 

2.117 

3.432 

1 .868 

3 .105 

7.271 

7.553 

1 .692 

2.579 

2.796 

5 .151 

N 
April, with 869-3 hitting 78 - 85 MMCFD, the plant processed 247 - 269 MMCFD, the high 

for 1997 . 

6.1.9 Mobil Production Summary: 1997 

Mobil's Aloe Bay and Mary Ann fourth quarter, 1997, average production, 134 MMCFD, was 

well below the spring peak . The 823 and 869-3 wells fourth quarter average production 

averaged 203 MMCFD. Combined, Mobil produced 337 MMCFD at the end of 1997, about 

70 percent of their plant processing capacity . 

6.2 Development and Production of Exxon Project"' 

With discoveries in Bon Secour Bay (BSB), North Central Gulf (NCG), and Northwestern Gulf 

(NWG) state fields, plus 827 and 867 federal fields, Exxon announced the second Mobile Bay 

project in October 1986 to develop its extensive leaseholds . OGJ subsequently reported that 

Exxon's discoveries in state waters amounted to 2 .8 TCF.lo6 Exxon hoped to produce as much 

as 600 MMCFD from its fields, according to the OGJ article. Eon filed plans with the COE 

to install multiple production platform complexes in tracts 64, 112, 114, 827, 867 and 868 . The 

platforms on state tracts 62, 63, 111, 112, 114 & 115, and the platform on OCS tract 827 are 

currently producing. The 868 reserves were developed by the Mobil-operated well 869-3, with 

Exxon a 30 percent partner. 867 is planned for development in 1998 .1°' Exxon referred to 

a gas sales contract as one hurdle to overcome during the development process .l°8 Exxon, like 

Mobil, was caught-up in the middle of the "gas bubble . " 

"This section is based on five Exxon papers delivered at the May 1994 OTC . 

Johnson, H. E., R. J. Kartzke, and R. M. Kruger, "The Mobile Bay Project," OTC 7447. 

Gallagher, M.J ., T. T. Arthur, D. E. Boening, and K. A. Sortland, "An Overview of the Mobile Bay 

Project Offshore Facilities and Installation Approach," OTC 7448 . 

Gordon, J.R., D.V. Johnson, S.R. Herman and J.B . Darby, "Well Design and Equipment Installation for 

Mobile Bay Completions, " OTC 7571 . 

Arthur, T. T., E. L. Cook, and J.K Chow, "Installation of the Mobile Bay Offshore Pipeline Systems," 

OTC 7572 . 

Page, W. A., R. D. Teague, "Mobile Bay Project Quality Management Program," OTC 7449. 

`OGJ, "Industry slates more exploration, development in gulf Norphlet trend," March 6, 1989, p. 15 - 18 . 

"Exxon note to William Wade, May 5, 1997 . 

'1OGJ, "Development activity dots Mobile Bay trend," April 6, 1987, p. 27 

130 
6.2.1 Integrated Norphlet Production and Processing Facilities 

Exxon described its Mobile Bay Project as the world's largest offshore sour gas development. 

Their reported costs included $1 .0 billion for facilities to produce and process 400 MMCFD 

from its three state fields (including 827) plus nearly $600 million bonus payments and $30 

million each to drill and complete each well."' Offshore magazine estimated the project cost 

at $2.0 billion for the 30 year project, including the bonus payments .l'o Exxon's project 

emphasizes that developing Norphlet gas requires an integrated system of field production 

facilities, processing plant and gathering lines designed specifically for the gas from specific 

fields . 

Exxon's basic plan entailed development of its three state fields simultaneously, plus the federal 

827 Field within the tract 115/116 development plan, and bringing the sour gas ashore for 

treatment at a single plant . Brown and Root designed the production facilities and flow lines. 

Fluor-Daniel designed the gathering system. H. B. Zachry, San Antonio, designed the onshore 

treating plant, with Steams-Roger, Denver, subcontractor for plant construction .' 11 

The offshore work was done under rigid environmental stipulations that required all discharges 

to be collected and barged for onshore disposal . Siltation was avoided to protect nearby oyster 

beds. Production of sour gas from hot, high pressure reservoirs required exceedingly high 

standards of equipment integrity and reliability. Risks associated with the sour gas, and high 

cost wells and facilities, made quality of products used a high priority . 

Like MOEPSI, Exxon's project had to deal with HZS that varied greatly among tracts and even 

among wells in different dunes within tracts as shown on Table 6.4. HZS on tract 111 varies by 

a factor of 300-fold between wells . (100 ppm equals 0.01 percent.) Tract 62 gas is nearly 10 

percent HZS-1000 times greater than well 112-2 HzS. 

Table 6.4 

H2S Content of Eon's Wells 

Well 111-1 111-2 112-1 112-2 114-2 115-1 116-1 62-1 63-1 78-1 827-1 

H2S 100 3 % .2% 100 .3% 100 120 9.7% 1 .5% 1 .4% 90 

ppm ppm ppm ppm ppm 

Source : Alabama Oil and Gas Board, 1997. 

The onshore gas plant was originally designed to treat a mix of gas containing 95 percent 

hydrocarbon, 4 percent C02 and the range of HZS content gas shown on Table 6 .4.112 The 

varying compositions in the produced sour gas led to a plant design that incorporated two sulfur 

`OGJ, "Mobile Bay gas flow rising in response to E&D campaigns," Jan 10, 1994, p . 22. 

"'Offshore, "Exxon USA's massive Mobile Bay Project getting underway," October, 1991, p. 34 . 

"'OGJ, "Exxon to develop gas reserves off Alabama," September 24, 1990, p. 46. 

"ZOGJ, "Exxon to develop gas reserves off Alabama," September 24, 1990, p . 46. 

131 
trains, one initially designed to handle 110 long tons (LT) sulfur per day and the other 40 LT 

sulfur per day, and required what Exxon described as a unique air-emissions permit. I" The 

plant was designed for 300 MMCFD, but with minor modifications was debottlenecked in 1994 

to process 400 MMCFD. Subsequent sulfur plant modifications to pumps and valves have 

enabled Exxon to take in gas with higher average HZS content. Capacity remains rated at 400 

MMCFD, with a higher average sulfur content producing as much as 228 LT of sulfur per day 

in early 1997 . By winter 1997 Exxon could extract 285 LT of sulfur per day. 

Figure 6.4 shows that eleven wells on Exxon's three state fields and federal 827 Field are 

produced to Exxon's onshore treating facility . Besides the varying 112S content, all of the gas 

has high pressure (Initial bottom hole pressures were 10,500 to 13,500 psi.) and high 

temperature (as high as 385 - 420° F). Production from the NCG Field flows to the NWG Field 

and then to shore. BSB gas is added to the 24 inch-pipeline that takes the combined gas to 

shore. 

Each field has a production platform that separates and dehydrates gas on the platform . 

Separation sends a dry sour-gas stream and a liquids (mostly water) stream ashore for 

processing . Solid corrosion resistant nickel alloy (CRA) is used in all the flowlines to withstand 

the pressure, temperature and corrosive nature of the gas. To absorb diamonoids and prevent 

plugging, fresh diesel is injected into well streams, if needed . All wells were completed with 

3 .5 and 4-inch CR.A tubing . Four early exploration wells with steel production casing at total 

depth were retrofit with the CRA liners . Different classes of CRA were used in the wells 

dependent on the HZS, bottomhole pressure and temperature of the gas produced in the well . 

This saved the project substantial money while assuring safety and quality of materials . 

Nearly 200 miles of high pressure alloy and carbon steel pipe is installed to connect the three 

production platforms and five well templates with the onshore treating facility . Like Mobil, a 

five line gathering system connects the onshore plant with the production platforms to transport 

diesel, fuel gas, produced gas produced liquids and dilution water . Water depths along the rightof-way range from 2 to 50 feet in both the protected inshore Mobile Bay waters and the high 

current, open waters outside the Bay. 

A separate 42-person living quarters is bridge-connected to the NWG production platform. This 

houses offshore personnel from all three fields . Each platform has a separate bridge-connected 

template for one or more producing wells. There are five remote well templates. 

6.2.2 Project Management and Quality Control 

Planning and management of the construction and installation of platforms, production 

equipment, and flowlines among three fields and an onshore treating plant simultaneously was 

yet another herculean milestone in the Norphlet story. Quality, supervision and inspection were 

planned for at the inception to assure that the project met program objectives : 

" Assure that completed facilities met design, functional and regulatory requirements ; 

"30GJ, "New Mobile Bay complex exploits major sour gas reserve," May 23, 1994, p. 49 - 51 . 

132 
ONSHORE 

TREATING 

: .. 

NORTMNEST GULF FIELD 

BON SECOUR BAY F1FLD 

NORTH CENTRAL 

GULFFIELD 

2.5144Tos 

mmummmmi 

?72~Q071 

Figure 6.4 . Mobile Bay Area . 

* ExisnNc PROaacnvE wQts - > > 

Q PRODUCTION PLATFORMS - 3 

--- GATHERING SYSTEM 

Source: Exxon, 1997. 
" Ensure timely documentation and compliance; 

" Build in quality to virtually eliminate risk of failure. 

A project management plan was implemented to assure quality by lines of responsibility, 

anticipated audits and inspections, and documentation . Eight thousand units of pipe, valves, 

fittings, and welds were inspected with only one reject found. Eon designed critical 

components with zero tolerance for failure. 

Exxon developed much new or untried technology . Cold-worked CRA was identified early as 

an optimum material for flowlines. A pipe-in-pipe insulated system was selected. This created 

a challenge for welding technology because cold-worked materials had not previously been 

considered candidates for welding applications . A welding procedure had to be developed that 

would produce high strength, repeatable welds in an offshore environment. Welders had to be 

trained to perform the welding with repeatable exactitude . At the initiation of the welding 

development program, Gas Tungsten Arc Welding (GTAW) took about seven hours to complete 

a weld . By the time field welding was to begin, this time had been reduced to 35 minutes . Full 

documentation of each weld including X-rays and interpretation by a small group of specialized 

personnel assured the integrity of the welding program. 

Pipelines were installed during the summer months of 1991 and 1992 . The BSB pipe bundle was 

installed in 80-foot joints in a common ditch using conventional lay methods . The 1992 

workscope achieved the following : 

" Offshore flowlines were installed ; 

" Nearshore gathering lines were installed; 

" Offshore gathering lines were installed; 

" Inshore gathering line from the tie-in at the east end of Dauphin Island to the beach 

approach was installed. 

This entailed directionally drilled crossings, which required much coordination between pipe 

string layout, drilling and excavation contractors . Exxon specially constructed a laybarge to 

allow the installation of five pipelines in the bundle simultaneously . 

Planning for the project started in early 1986. Wells were drilled between 1983 and 1993, with 

six final wells tested and completed in 1993 . Offshore work was accomplished between 1991 

and 1993 with 2 .7 million contractor hours. Figure 6 .5 shows the scheduling of the offshore 

work, exclusive of drilling, by month. The onshore plant work was completed during the same 

period . At one time Exxon had 2,000 contractors working with 200 Exxon people . Over 100 

contractor firms were involved with various aspects of the work, with Exxon assuming an 

overall coordination role . The offshore pipelines team used 1 .5 million of the entire 2.7 million134 
.. 

0 0 0 

N 

O 

x 

300 

200 

100 

0 

Figure 6.5 . Exxon Project Contractor Hours Worked Offshore . 

Source: Exxon, 1997 . 

W 

1991 1992 1993 
hour project. There were no significant environmental incidents and no "lost time" safety 

incidents . The pipeline segment of the project came in 20 percent under budget . 

6.2.3 Exxon Project Production Profile 

Startup of the eleven wells in state and federal waters was completed over a 45-day period 

beginning with the Northwest Gulf Field in October 1993 . Figures 6.6 - 6.8 show the monthly 

production rates from the three state fields, including production from 827-1 on Figure 6 .6 . By 

March 1994 Exxon was producing at the following rates : 

Field MMCFD~ 

NCG 93 

827 19 

NWG 189 

BSB 80 

Total 381 

The NCG/827 Field has maintained the nearly 120 MMCFD production rate with only 

occasional variation since start up . This gas is lower in HZS than BSB . The spike in September 

1994, common to all fields, reflects routine maintenance at the onshore treating facility . Exxon 

spudded well 114-3 in March, 1997, to offset Mobil's 95-5 well . Production started February 

10, 1998, and ramped to 65 MMCFD March 5, 1998 . 

The NWG Field has had periodic production problems, illustrated by the shutdown of its 112-1 

well on June 12, 1996; 112-1 is reported to have had mechanical problems . The well produced 

42 .3 MMCFD in January 1996-the high for the year. The well returned to service in 

September 1997 . Well 112-2 was shut down in April 1997 for a workover to clean scaling and 

repair the SCSSV, which was completed in August 1997 . Production in the field for the three 

months ending January 1997 averaged 105 MMCFD, about 55 percent of the average for the 

three months ending March 1994. Keeping Norphlet wells producing at design rates is a 

challenge. Exxon brought well 111-3 online in March 1997 at 77 MMCFD to supplement 

production. Exxon refers to its high initial production as "a typical NWG well with standard 

diameter tubing ; processing capacity was available [for high production rate] and well facilities 

were designed for maximum initial rate .""' Returning wells 112-1 and 112-2 to service 

brought field production back to 200 MMCFD in October . 

BSB production increased from 40 MMCFD at start up to 120 MMCFD in December 1996 . 

The same three wells have ramped up consistently since they came on line in November 1993 . 

BSB wells were ramped up even further to maintain plant throughput and sales commitments 

after the 112-1 well was taken out of production in 1996 for a workover. BSB wells averaged 

106 MMCFD during the fourth quarter, 1997. Mobil and Exxon are planning a joint well on 

"'Exxon note to William Wade, May 5, 1997 . 

136 
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199702 

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1997/11 
Mobil's tract 61 during 1998, which will add production from the BSB reservoir, and be 

processed in the Mary Ann Plant. 

Table 6.5 shows the Exxon Gas Plant's 1996-1997 gas intake, intake by well, sales gas and 

sulfur production by month . This does not include the Hunt gas produced from NCG. Hunt, 

with 25 percent ownership of tract 114 within NCG, takes its gas in kind and processes the gas 

in Mobil's 823 plant. Sales gas declined from 94 .5 percent to 93.9 percent of intake gas from 

January to December because of the much more sour BSB gas production that was increased to 

replace the lost production from NWG well 112-1 . Sulfur production increased nearly 20 percent 

since mid-1996 when BSB production was lower . The Exxon plant is reported to be sulfur 

removal limited with the current mix of gas ; the plant averaged 274 long tons per day during 

the fourth quarter, or 96 percent of its reported 285 It sulfur capacity . 

6.2.4 Eon Production Summary: 1997 

With Exxon's well 111-3 sustaining production over 70 MMCFD, Exxon's Gas Plant approached 

estimated capacity of 400 MMCFD at year end 1997 . Well 114-3, producing near 65 MMCFD 

in April, 1998, pushed Exxon's production to 445 MMCFD, above plant capacity, even though 

the federal well 827-1 was shut in for balancing. Production from Eon's 867 field, slated for 

1998, clearly gives Exxon producibility exceeding plant capacity . 

6.3 Development and Production of Shell's Fairway Field and Yellowhammer 

Projectils 

Shell Offshore Inc (Shell), having discovered gas on their $57 million state tracts 113 and 132, 

announced plans to develop the Fairway Field on November 8, 1989. Construction began in the 

first quarter 1990; the onshore plant and offshore production came on line December 5, 1991 . 

Shell's Fairway Field was the second field brought into~production. Natural gas was selling for 

$0 .93 per MCF when Shell initiated production-about 10 percent of the industry's price outlook 

when Shell bid on the leases within the State's first lease sale ten years earlier. 

6.3.1 Development Avoided Shipping Channel and Civil War Artifacts 

With its May 1986 discovery well 113-1 confirmed by the late 1988 132-1 delineation well, and 

with time running on its lease, Shell filed for an application for an air permit on December 5, 

1988, to develop and produce the Fairway Field three miles south of the entrance to Mobile Bay. 

Individual well platforms are connected to a Central Production Facility (CPF). Production from 

"'This section is based on the following articles : 

Gallaher, Dale and Michael J. Mahoney, "New technologies used in development of sour Fairway gas," 

OGJ, February 22, 1993, p. 57 - 62. 

Gallaher, Dale and Michael J. Mahoney, "Fairway sour gas development proves new materials, 

monitoring," OGJ, March 1, 1993, p. 76 - 79. 

"Yellowhammer: Alabama's Newest Resource," Shell internal undated publication. 

140 
Table 6.5 

Exxon Plant Gas Per Day 1/96 -12/97 

MMcFn 

Wells Production 

Total gas 62-1 63-1 78-1 111-1 111-2 111-3 ' 112-1 112-2 115-1 116-1 114-2 827- 1 long t ons 

Jan 96 369 .803 18342 26.255 56 .190 26.293 66 .699 42 .251 28 .146 10 .912 27.049 33 .872 33 . 794 349.356 197.184 

Feb 361 .918 17 .460 26 .151 55 .971 26.584 66 .622 38 .000 24390 11 .179 26.838 32 .984 35 . 740 341.231 188.793 

March 354 .276 16 .604 26320 57 309 25 .489 65 .851 31 .322 26 .919 10 .753 26.293 33 .148 34 . 268 333.180 189.715 

April 343. 533 15 .684 27 .426 55 .109 24 .805 64.476 30 .564 27 .352 10.373 26346 27 . 477 33. 927 322.650 175.432 

May 342. 871 15 .955 26 .098 55 .480 24 .776 64.103 31 .311 25319 10.503 28.036 27 . 809 33. 481 323.156 179.809 

June 318. 139 15 .844 27 .122 56 .093 23 .869 62.716 9.728 23 .772 10.498 27.766 27 . 674 33. 056 299.799 176.438 

July 303. 820 14 .927 26 .438 55 .115 23 .933 61 .041 0.000 24.902 10.150 25.060 29 . 838 32. 416 285.236 171 .502 

August 305. 442 15.073 27 .305 54 .670 23 .802 60.348 0.000 25.634 9.692 19.468 37 . 142 32 310 286.616 165.085 

Sept. 326. 871 25.932 32 .609 54. 082 25 .028 59.219 0.000 24.945 10.135 26.745 36 . 763 31 . 414 307.437 211 .976 

Oct. 345. 252 29.649 34330 54. 703 25 .880 58.617 0.000 24.094 11 .233 30.946 40 . 240 35 . 559 324.367 225.331 

Nov. 342. 790 31 .833 35.017 55 . 994 25 .194 58 .232 0.000 23.435 10.906 29.584 37. 036 35 . 559 320.568 228.521 

Dec 336. 454 31324 33.505 56 . 499 24.698 57 .543 0.000 23.199 9.887 28 .691 36. 479 34 . 628 315.998 233.454 

!an 97 323. 529 27.930 30.670 55 . 238 24.778 56 .785 0.000 22.078 9.529 26 .708 36. 488 32 . 891 304.461 216.844 

Feb. 319. 873 26.106 29.612 56 . 750 23.933 58 .930 0.000 22.916 7321 26 .457 34. 893 33 . 709 298.624 209.479 

Mar 342. 898 21 .568 29.380 56 . 936 23.033 58 .562 36 .162 0.000 16.527 9310 25 .097 32. 794 33 . 529 322317 227.720 

April 364. 524 16.143 29.291 55 . 961 23.489 57 .886 81 .905 0.000 0.000 9.227 24 .140 34. 176 32 . 307 342.205 254.940 

May 362. 082 19.067 28 .826 54 . 781 22.906 56 .425 80 .262 0.000 0.000 9.550 22 .476 36. 230 31 . 558 342.406 264.948 

June 357. 120 19.416 28334 55. 001 22 .651 55 .011 78 .344 0.000 0.000 8.671 25 .244 33 . 445 31 . 002 334.106 260.923 

July 342. 793 20.662 26.560 52. 118 21 .567 50 .991 74 .111 0.000 0.000 9.373 24 .757 32 . 856 29 . 799 319.802 247.640 

August 358 390 26.261 26 .625 53. 874 21 .805 51 .154 74 .830 0.000 5.853 9.531 25.120 33 . 061 30 . 276 335.166 271.217 

Sept . 383. 054 25 .642 25 .141 54. 058 21 .746 50.503 73.294 17 .586 21 .161 8.409 23.916 32 . 659 29. 340 360.993 269.194 

Oct. 401. 757 24 .157 23332 54. 290 22 .446 51 .822 72.691 41 .023 20 .672 8.367 22.572 31 . 663 28. 723 377.521 282.238 

Nov. 407. 684 23 .543 28 .998 54. 581 21 .439 53.296 74.502 38 .424 19 .486 9.590 22.661 31 . 893 29. 281 380.804 273.828 

Dec 383. 913 23 .806 31 .295 54. 453 21 .252 51 .563 70.359 24 .825 19 .480 8.709 22.896 26 . 772 28. 504 360.298 266.545 

Source : Alabama Oil and Gas Board, 1997 
the CPF is pipelined 17 miles to Shell's Yellowhammer gas treatment plant. The plant, named 

for the Alabama state bird, is located east of the Mobil Mary Ann Plant in the general vicinity 

of Coden, Alabama. The plant is sized to process 200 MMCFD of sour gas (0 .8 percent 

average HzS) and produce 190 MMCFD sales gas, 60 LTD sulfur and as much as 2,300 b/d 

mixed NGLs . 

The Shell Fairway gas contains about 3 percent C02, NGLs that are not present in either Mobil's 

or Exxon's dry gas, and HZS in the wells that ranges from 100 ppm to 1 .5 percent within tract 

113 ; 150 ppm in well 132-1 . The gas in the west dune of Shell's tract 113 has lower HZS than 

the gas in the east dune . (See dunes in Figures 5 .8 and 5 .9 .) 

Like Mobil's and Exxon's plants, Shell's plant was built to achieve rigorous environmental 

protection and safety standards. Computer operated electronic sensors, automatic shutdown 

devices, and warning systems monitor all processes. Electronic sensors throughout the 

surrounding community constantly monitor for HzS. 

Downhole production tubing, wellheads, well flow lines and primary processing on the CPF 

employ bimetallic nickel-alloy CRA materials. Downstream of the corrosion inhibitor injection, 

Shell employs carbon steel for the pipelines to shore. In contrast to Exxon's and Mobil's 

processing approach, Shell's gas is dehydrated onshore, rather than on the platform. Shell 

avoids corrosion of the pipeline and fittings by using Champion T265 corrosion inhibitor 

chemical, which Shell developed. As pipeline corrosion is a significant concern, and Norphlet 

gas has all of the ingredients necessary for severe metal-loss corrosion-HZS, COZ and free 

water-Shell's approach is unique among the Norphlet producers. The liquid hydrocarbons and 

water are separated in the first step at the plant. Then the contaminants in the gas are 

removed-H2S and C02-and the gas, NGLs and sulfur are sold. Pipelines from the offshore 

field bend around Dauphin Island to avoid underwater magnetic anomalies possibly related to 

sunken ships and artifacts from the Battle of Mobile Bay. 

Shell planned for a budget of $440 million to develop gas wells, offshore facilities, pipeline 

system, and the Yellowhammer plant, broken into the following categories. The plant was 

designed to accommodate peak production rather than a reduced flat production profile. 

Millions 

Wells $175 

Platforms/Jackets $20 

Offshore Facilities $25 

Pipelines/flowlines $55 

Yellowhammer Plant $90 

Future wellfield improvements 75 

Total $440 

The construction contract for the plant was awarded to a team comprised of BE&K of 

Birmingham and Davy McKee Corp of Tulsa . Davy performed the engineering and major 

equipment procurement services . BE&K constructed the plant. Local contractors, David Volkert 

142 
and Associates of Mobile, and J. H. Adams of Chickasaw constructed the plant office building 

and access roads . Construction of the plant, building and roads required about 400 workers . 

During construction, the Yellowhammer plant created more than 500 jobs, primarily instate . 

Construction started in 1989 and was completed in later 1991 . Start up occurred on December 

5, 1991 . The plant operates with 23 technicians and 14 staff. Offshore operations are handled 

by four crews of two technicians each. 

6.3.2 Shell Fairway Field Production History 

Figure 6 .9 shows that Shell's production was sustained near their 200 MMCFD plant capacity 

between September 1992 and March 1994 . Production has declined since. The field also has 

scaling problems related to calcium fluoride and calcium carbonate. Well 113-3 has been down 

for a workover since December, 1997 . The Yellowhammer gas plant processed between 92 -

170 MMCFD during 1996 and 1997 including 10 - 11 MMCFD from Mobil's 95-3 well as 

shown on Table 6.6 . With Shell's declining production, Mobil's 3 .2 percent HzS gas fits into 

Shell's processing capacity. Shifting the gas to Shell made room in the Mary Ann Plant for 

Mobil to take in the 823-A4 gas. Gas from Chevron's 1 .6 percent HZS well 863-3, which came 

online in February 1997 at 18 MMCFD, is now being processed at Shell's plant . The well 

averaged 39 MMCFD during the fourth quarter, 1997. Shell still has unused capacity in its 

Yellowhammer plant. 

6.3.3 Federal 821 Field and Shell Summary 

Shell purchased the producing BP joint federal/state 821/109 Field in August 1996 (92 .5 percent 

federal/7 .5 percent state) . BP had only the one successful Norphlet discovery . The 821 gas, 

100 ppm 112S, will continue to be processed offshore on the 821 platform. Pipeline quality gas 

is brought to shore in Mobile County on DIGS for connection with the interstate pipeline . 

Figure 6 .10 shows the 821 production history . The field shut down in October 1994 with a 

severe scaling problem that plugged the well. After that, BP constrained production to 15 

MMCFD to manage the scaling accumulation problem. Shell hopes to restore production to 

about 20 MMCFD. Shell is evaluating a second well on tract 821 . 

6.4 Development and Production of Union and Chevron Federal Projects 

Union and Chevron dominate recent Norphlet development activities on the eastern and western 

edges of the federal Mobile Bay OCS. These companies acquired the acreage for much lower 

lease bonus amounts as shown in Section 3 .0 because they started later, after gas prices dropped . 

But nothing is low cost when dealing with the Norphlet . 

Development of Union's and Chevron's Norphlet discoveries in western Mobile Bay OCS 

overcame superpressurized reservoirs (> 15,000 psi) as well as the other hostile downhole 

challenges encountered in Norphlet reservoirs : HZS, CO2, water, 420° F temperatures ."' 

Several gas wells have been damaged or lost during either completion or start-up, as show on 

"'Offshore, "Unocal building range of solutions for drilling deep Norphlet environment," June, 1995, p. 32 -

33. 

143 
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144 
Table 6.6 

Shell Gas Per Day 1/96 - 12/97 

MMCFD 

Wells Sulfur 

Mobil Chevron Sales Production 

Total gas 113-1 113-2 113-3 113-4 132-1 95-3 863-3 Gas Long tons 

Jan 96 144.154 29 .085 30.529 22.494 22 .623 28 .416 11 .008 135.381 20 .129 

Feb 132.013 26 .115 26 .913 15 .104 29 .889 25 .360 8.726 124.048 16 .552 

March 138.640 27 .108 29.288 15 .288 30 .946 25 .944 10 .066 131.261 18 .935 

April 139.006 26.437 27.872 19.968 29.160 25.501 10 .068 131 .761 22.933 

May 135.156 26.098 26 .962 18 .109 28 .349 24 .818 10 .821 130.597 23 .000 

June 133 .049 25.724 25.894 19 .205 27.373 23.401 11 .429 128 .371 21 .833 

July 126 .902 24.730 24.775 17 .193 26.436 22.157 11 .610 121 .729 18.226 

August 130 .641 25.631 26.453 18 .345 26.514 22.691 11 .008 124 .348 16.194 

Sept . 124.971 25.876 24.680 16 .496 25.039 22 .467 10.414 120.674 19.633 

Oct. 92.185 19 .692 18.844 10 .362 18 .862 17.129 7.296 86.592 13 .806 

Nov. 129.369 26.510 25.359 15 .419 26.042 23.016 13 .023 121 .110 17.100 

Dec 128.751 26 .958 24.346 18 .395 25.083 22 .421 11 .548 119.200 17.387 

Jan 97 122.447 26 .690 22.684 16.497 23 .545 21 .428 11 .603 107.792 18 .452 

Feb 123 .769 26.294 23.068 10.989 23.675 21 .606 11 .449 6.688 114 .658 18 .714 

Mar 144.375 26.084 22.678 17.595 23.222 20.977 12 .623 22.417 134 .982 21 .548 

April 164.969 25.178 21.150 15 .176 21.751 19 .763 15 .508 42.622 150 .287 20.484 

May 166 .298 25:577 21 .491 14 .317 22.212 19 .540 19 .544 45.508 157 .597 22.323 

June 170 .454 24.390 20.466 17 .372 21.327 18 .713 20.960 43.756 155 .647 22.355 

July 122 .265 24.904 20.483 5 .103 21 .635 19.405 23.465 9.541 116 .075 17.871 

August 96.344 22.877 12 .657 6.481 19350 11 .662 25.816 0.000 90.745 15.129 

Sept . 134.840 23 .542 20 .602 14 .874 19 .716 26.733 22.035 5.122 121 .980 20.032 

Oct. 154.597 24.641 20.723 13 .723 21 .289 27.565 13 .508 34.455 147.574 31.903 

Nov. 155.539 23.685 19 .192 6.158 19 .215 25 .511 15 .926 42.377 144.116 30.032 

Dec. 142.843 26.143 18.856 0.517 19 .212 28 .018 12.543 38.768 134.380 49.548 

Source : Alabama Oil and Gas Board, 1997 . 
35 

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Figure 6.10 . State 109 / Mobile 821 Field Gas Production per Day. 

Source: Dwights/PI, 1998; AOGB, 1998. 
Table 6.7 . Chevron's well 861-1 blew out underground in 1985 after discovering Norphlet gas . 

Three of the wells have a produced water problem; i .e ., so much water has intruded that the 

wells are either P&A'd or only can produce at a reduced rate. This is the same problem that 

Shell has with the BP-completed well 821-1 . Norphlet wells that are completed too close to the 

water contact at the bottom of the reservoir can develop a water coning problem due to the tight 

rock. Assuming a cost of close to $30 million to drill and complete a Norphlet well, these six 

wells represent a $180 million problem with a lot of lost production. 

Union and Chevron combined are producing close to 150 MMCFD Norphlet gas at year end 

1997 with plans that could add at least 100 MMCFD of new production by the end of 1998 . 

The problem wells have resulted in lost production easily in the range of 150 MMCFD. 

Assuming $1 .00 per MCF netback to wellhead these losses total nearly $55 million annually. 

Everything is big when it comes to Norphlet wells. 

Table 6.7 

Union's and Chevron's Problem Wells 

Well Operator Problem Problem 

Date 

Status 12/97 

861-1 Chevron Underground 1985 P&A 

Blowout 

861-8 Chevron Water Intrusion August 1994 producing at 

reduced rate 

904-1 Union Casing/Tubing August 1994 P&A 

excessive wear 

864-3 Chevron Water Intrusion August 1996 P&A 

916-B3 Union Water Intrusion June 1995 P&A 

872-1 Chevron Formation Plugged September producing at 

by Kill Fluid 1995 reduced rate 

Source : Telcons with Union and Chevron Personnel, April 1997. 

6.4.1 Western Mobile OCS 

Union and Chevron are developing discoveries in the 861, 904, 820 and 864 Units on the 

Mississippi side of the Mobile OCS. These include processing on Central Processing Facilities 

(CPF) on platforms at tracts 864 and 904. Together these facilities can process 230 MMCFD 

of Norphlet gas. Figure 6 .11 shows the location of these fields . 

Union's 904 platform includes two wells and processing capacity sized to handle 80 MMCFD 

of Norphlet gas plus separate crew quarters . Four crew members serve a seven day rotation. 

Processing anticipates 120 ppm average HZS. Gas from tracts 904 and 861 is processed on the 

904 platform and flows to shore via a 10-inch connection to the Chandeleur pipeline to the 

Pascagoula refinery, where it connects to the Koch Gateway Interstate . 

147 
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, 

992 ' 993 ' 994 ' 985 ' 998 ' 997 '998 '999 1000 . 1001 10021 . 1003 X 1004 ' 1005 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . I . . . . . .1 . . . . . . . . . . . . . . . . . . . . ~. ~ .~ .r ~. .J . . . . . , . . . . . .. 

Source : AL Oil and Gas Board, 1988, 1993a; MMS. 1991, 1993a. 

Blocks and structures not drawn to scale. 

Figure 6 .11 . Western Mobile OCS Union & Chevron Fields . 
Unocal's initial production came from the 904 Field, which started with 904-1 on December 22, 

1993 at 20 MMCFD, as can be seen on Figure 6 .12 . The well reached a peak production rate 

of 22.3 MMCFD-well below its record test rate-but was lost in August 1994 . The well has 

been P&A'd. Chevron started production from 861-8 March 1994, flowing to Union's 904 

facility . The gas is 120 ppm HZS. The well initiated production at 30 MMCFD, but developed 

water problems and was off production from August 1994 until January 1995 . It has never 

produced near the high rates of its initial production, currently maintaining 10 - 12 MMCFD. 

This was the only production to the 904 facilities after 904-1 was lost until Union brought a new 

well 904-2 on line December 24, 1996 at 32 MMCFD. The well stepped up to 52 MMCFD in 

February 1997 . This well solved the water coning problem encountered in so many Norphlet 

wells by being completed at the top of the reservoir sand, just below the pyrite zone found 

between the Norphlet and Smackover. The ultimate production rate from the 904 field is yet 

unknown. 

Chevron initiated production from its 820-1 well October 21, 1996 at 25 MMCFD, ramping up 

to 50 MMCFD for the month of April 1997 . The well averaged 34 MMCFD during the fourth 

quarter 1997 . This well is 100 ppm HZS. Chevron's well 864-3 started production at 20 

MMCFD October 21, 1996, but encountered a water production problem and was shut in. It 

was P&A'd April 1997 . Well 864-4 spudded in July, 1997, to replace 864-3 . The well came 

online in December, 1997, at 16 MMCFD, 40 ppm HZS. Ultimately, the well is expected to 

produce 30 MMCFD. Well 863-3 initiated production February 19, 1997 at 18 MMCFD. The 

well tested with 112S unexpectedly high, 1 .6 percent, to process on the 864 platform. Production 

was delayed until a pipeline could be installed to Shell's Fairway Field for processing in the 

Yellowhammer Plant. Well 863-3 produced 44 MMCFD April thru June 1997, encountered a 

mechanical problem with the safety valve and was shut-in through April 1988 for repairs. The 

well returned to service at 44 MMCFD. Figure 6.12 shows that Chevron's and Spirit's western 

Norphlet fields reached peak production April thru June, 1997, before they were beset with 

problems. Lost production from 863-3 and the downturns of 820-1 and 904-3 explain the 

October, 1997, dip . Added new production from 864-4 partially explains the December, 1997, 

upturn. 

Chevron spudded well 819-1 September 1, 1996 . The well reached total depth (TD) December 

1996 and confirmed gas. The well was completed in December, 1997, and added to production 

January 1, 1998, at 22 MMCFD. Flowlines were constructed between the well and the 864B 

Central Production Facility . Flowline bundles are described as a six-inch gas pipeline, a threeinch solvent pipeline and a two-inch fuel gas pipeline . 

Chevron contracted Ralph M. Parsons to provide design and procurement services for a $50 

million natural gas treatment plant to be built at Pascagoula. The plant was described as the first 

of three phases, each providing 300 MMCFD of capacity . Planned completion was 1994 .11' 

Chevron decided, however, to forego onshore processing and treat its gas either on its own 864 

platform, or Union's 904 and 916 platforms . This saved the cost of lengthy, expensive carbon 

steel pipelines from the eastern and western Mobile Bay OCS areas to Pascagoula. Instead, 

Chevron delivers its pipeline quality gas to DIGS for conveyance to the Chandeleur Pipeline to 

"'OGJ, Industry Briefs, October 19, 1992, p. 40. 

149 
0 

160 

140 

120 

100 

A 

w 

80 

60 

40 

20 

O~ O~ O~ O~ ~ ~ Q~ ~ ~ 

a l, Q~ ~ O~ O~ O~ a O, l I 

Q ~ ti Cn Cn rn Cn Q 

Figure 6.12 . Mobile 820, 861, 863/4 and 904 Fields Norphlet Production. 

Source : Dwights/PI, 1998 ; Foster Associates, Inc., 1998 . 
Pascagoula and the Koch interstate connection . 

Chevron constructed facilities on the 864B platform Central Production Facility capable of 

processing 150 MMCFD of sour gas . In April 1998, Chevron is treating approximately 75 

MMCFD gas from its wells 820-1, 864-4, and 819-1 on the platform. Spirit is treating 904-2 

and 861-8, about 50 MMCFD, on the 904 CPF. Planned new well 904-3 will be treated on the 

904 CPF. 

Table 6 .8 summarizes Union's and Chevron's activities on the western side of the Mobile OCS. 

Counting January 1998 production plus the 863-3 workover well, five wells produced about 170 

MMCFD, with about 120 MMCFD of that being processed in either the 904 or 864 CPFs. 

Chevron's planned 862-1ST, a second well in the producing 863 reservoir, 863-4, planned for 

later in 1998, and 819-2 likely will fill the capacity of their 864 processing facility during 1999. 

A Miocene well, 861-9, was completed in December 1996 . This well is reported to be 

pressurized with the Norphlet gas that escaped from Chevron's 1985 blowout. It is treated on 

the 904 platform before transport to Pascagoula on the Chandeleur pipeline . 

Table 6.8 

MO 904, 861, 820 & 863/4 Production Summary & Plans 

Well 

904-1 

904-2 

861-8 

861-9 

864-3 

820-1 

863-3 

864-4 

819-1 

Total 

Operator 

Union 

Union 

Chevron 

Chevron 

Chevron 

Chevron 

Chevron 

Chevron 

Chevron 

Formation 

Norphlet 

Norphlet 

Norphlet 

Miocene 

Norphlet 

Norphlet 

Norphlet 

Start Up Date 

12/93 

12/96 

3/94 

12/96 

10/96 

10/96 

2/97 

Production 

Rate 1/98 

MMCFD 

P&A 

39 

10 

7 

P&A 

32 

Workover 

44-April 1998 

-16 

-22 

-170 

Norphlet 

Norphlet 

Combined 

12/97 

1/98 

862-1ST Chevron Norphlet 1999 

863-4 Chevron Norphlet 1999 

819-2 Chevron Norphlet 1999 

904-3 Union Norphlet 1999 

gas 

gas 

gas 

gas 

Source: U .S . llUl, MMS, 1998; Chevron, 199 ; Union, 1998 . 

151 
6.4.2 Eastern Mobile OCS 

The eastern area of Mobile OCS includes Chevron's 100 percent owned 872 Field comprised 

of tracts 872 and 873 plus the 916 Unit consisting of 6-1/4 blocks shown on Figure 6.13-871 

S/4, 915, 916, 917, 918, 961, and 962. Union and Chevron are equal 45 .7 percent owners of 

the 916 Unit, with Bechtel's Fremont Energy Corp owning the rest . Union is the operator, 

although Chevron has drilled individual wells that provide gas to the processing facilities . The 

state boundary likely artificially truncates the Norphlet play in the area to the Alabama side of 

the line . 

The Mobile 916 area facilities are called the Fort Morgan Complex because the field is located 

about 12 miles southeast of Fort Morgan. Facilities include a Central Processing Facilities 

platform, crew quarters platform, two wellhead platforms and two caisson wells. The three 

bridge-connected platforms are capable of producing and treating on the platform 150 MMCFD 

sour gas and 30 MMCFD sweet Miocene gas. The Norphlet is 60 ppm HZS, 4.5 percent C02 

flowing at 300° and 15,835 psi. The commingled pipeline quality gas is shipped on the 20-inch 

DIGS pipeline to the Mobile County Interstate connection . Enercon Engineering Inc, Houston, 

provided the engineering and procurement for the production facility ."' Like other Norphlet 

developments, extensive CRA is used for flowlines upstream from dehydration. Eight crew 

members serve a seven day on/off rotation . 

The Fort Morgan Complex initiated production in April 1995 . Union started production from 

916-A2 in April 1995 at 17 MMCFD; this ramped to 32 MMCFD in June and averaged 25 

MMCFD through the end of 1995 . 916-B3 came on line in April and hit 15 MMCFD in June 

1995 before encountering a water intrusion problem.'19 Chevron started-up well 917-A2ST 

in April 1995 producing 40 MMCFD, 80 ppm HZS. Production was down to 11 MMCFD in 

April 1997 . Union, which had a different view of the structure's geology, is not a partner in 

this well. Chevron's 100 percent-owned well 872-A1 began production March 1996 and 

averaged 11 MMCFD in mid-year. Well 961-A2 initiated production July 31, 1996 at 24 

MMCFD. The well ramped up to 50 MMCFD in February, 1997, and averaged 35 MMCFD 

during the fourth quarter, 1997 . Union's two Miocene wells began production in April 1995 . 

Figure 6.14 shows Norphlet production from the two fields in the eastern Mobile OCS. 

Union and Chevron produced between 100 - 110 MMCFD Norphlet gas delivered to the 916 

platform facilities from five Norphlet wells from September, 1996, thru April, 1997. The loss 

of 916-B3 and a repair on 916-A2 caused the spike shown down to 58 MMCFD in June, 1997. 

Table 6.9 summarizes the producing wells to the 916 CPF. 

"gOGJ, "Another Mobile Block production facility nears completion," Jan. 30, 1995, p. 91 . 

"90GJ, "Unocal steps up gas/condensate production," May 29, 1995, p. 24 . 

152 
56 - 57 58 .59 180 ' 81 1 62 ' 83 ' 84 i 65 ' 88 ' 87 ' 

70 '71 172 73 ~ 74 76 178 80 81 

.88 ,89 ..90 ,91 ;92 ;93 g4 ,95 98 ,97 ,98 ,99 , 

' 

r 

. . . 

1:114 

~w .---

. . . . . . . . . . . .------

. . .. . - - " - -' - - . . . . 

....... . ~113-. .~ 

' 107 . . 108 

. . . 

.,109 . 110 111 -115 ,118 ,117 , 118 ' ' . ., .w ~ ne/na- ,1 12 ~ f 

' 819 .820 821 _ ~ 822 '823 '824 I . . . . . . . . . . . . . I . 828 827 `828 ;829 ' 830 

. . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 

131 132 1133 m 2 I 

F E -D 

'-863 

. 

864 865 866 867 68 '869 870 873 874 

. . . . . . . . . . . . 

W 

907 ' 908 1909 '910 '911 .912 '913 , 914 915 . ~3 8 $ t~,~s`±8" 1~6 a ' 

' 951 1 952 953 + 954 955 958 : 957 ' 958 , 959 980 9Q1 .~c 9,82 ~r ' ? ' a ' 

.~ ~ . . . .. . . . ~ . . . . . . . . . . . . . . . . . . . . . . ~ . . . . . J . . . . . . . . . 

' 995 ' gg6 ' gg7 .

998 : .999 . 1000 . 1001 ' 1002 . 1003 ' 1004 ' 1005 ' 1008 ' 

8oundaires not drown to scale . 

Source : Foster Associates, Inc ., 1007 . 

Figure 6.13 . Mobile 916 & 872 Units . 

w 
.P 

120 

100 

80 

A 

V 60 

40 

20 

. . . . . . 

~n W) kn W) W) ~O 110 %o 1-o 110 110 t- t- t- t- c- n 

o~ o~ o~ o~ C~' o, v, o~ C, o, o, o, o~ 0, o, o~ o~ 

o 

. 

o 

z 

. . . . . . o 

z 

Figure 6 .14 . Mobile 916, 961, and 872 Fields Norphlet Production. 

Source: Dwights/PI, 1998 ; Foster Associates, Inc., 1998 . 
Table 6.9 

MO 916 Processing 

Well Operator Formation Start Up Date 

Production 

Rate 4Q/97 

MMCFD 

916-A2 Union Norphlet 4/95 19 

916-B3 Union Norphlet 4/95 P&A 

917-A2 Chevron Norphlet 4/95 10 

872-A1 Chevron Norphlet 3/96 12 

961-A2 Union Norphlet 7/96 34 

915-1 Union Miocene 4/95 2 

961-1 Union Miocene 4/95 2 

Total Combined 79 

Source: U.S . DOI, MMS, 1998. 

Union and Chevron will spud two wells in the area, 918-1 and 871-1 during 1998 . Plans include 

a drilling schedule that will add as many as 12 more Miocene and Norphlet wells between 1998 

and 2004 as economics justify. 

6.5 Production Facilities Summary 

Extensive gas industry activity in Coastal Alabama has yielded over 7.5 TCF recoverable 

reserves and annual production over 1 .0 BCFD from 17 active Norphlet fields . Six state 

Norphlet fields and ten federal Norphlet fields are producing with one more, Destin Dome, 

scheduled to begin development activity when its DPP, submitted December 1996, is approved. 

Production will begin in 2001 . One joint state/federal field, 821/109 straddles the three-mile line 

with 92.5 percent of the field and production considered federal. 

6.5 .1 Producing Fields and Production Increases by End of 1998 

Forty wells were producing 1 .1 BCFD in the active 17 Norphlet fields in February, 1998, 

averaging 27 .5 MMCFD per well . Over the last 24 months, production ramped from 880 

MMCFD in January, 1996, to a peak over 1 .1 BCFD in April 1997, and then dropped below 

1 .0 BCFD at the end of 1997 . Figure 6 .15 shows that state production has remained stable near 

600 MMCFD over this period, as Exxon's 112 workovers and new production from Mobil's 95-

5 and 75-1 overcame declines from Shell's Fairway field . Federal production increased from 

300 MMCFD beginning in October, 1996, to 530 MMCFD at its peak in April, 1997 . 

Production thereafter was offset by lost production from problem wells (863-3 & 916-B3) and 

natural decline observed in Mobil's 823 field. New federal wells increased year end 1997 net 

production by 80 MMCFD above the January, 1996, production level . Table 6 .10 shows ten 

155 
.- 

700 

600 

500 

w 400 

U 

300 

200 

100 

0 

~o 110 ~ 110 

o' v~ o~ o~ 

*10 110 t-- r -

C~ o~ o~ o~ 

o 

z ~ z 

Federal -0- State 

o~ a~ o~ 

z 

Figure 6 .15 . State and Federal Norphlet Production Offshore Alabama (1996 - 97) . 

Source: AOGB, 1998 ; Dwights/PI, 1998 ; Foster Associates, 1998 . 
new wells added to production during 1996-1997, plus two added in January-February, 1998. 

Ten wells added 499 MMCFD of new production at their peaks, sustaining 368 MMCFD based 

on year end 1997 data. Recent information about the new Chevron and Exxon wells adds 76 

MMCFD of new production . 

Table 6.10 

Norphlet Wells Added to Production during 1996-97 

Operator Field Well Start-up Peak 

Production 

MMCFDDate 

Recent 

Production 

Chevron 872 872-1 3/96 14-3/97 13 

Spirit 961 961-1 7/96 50-1/97 32 

Chevron 820 820-1 10/96 50-4/97 32 

Mobil Mary 95-5 11/96 72-12/96 40 

Ann 

Spirit 904 904-2 12/96 60-8/97 39 

Mobil 869 869-3 2/97 83-3/97 61 

Chevron 863 863-3 2/97 44-5/97 44 

Exxon NWG 111-3 3/97 82-4/97 70 

Mobil Aloe 75-1 7/97 28-9/97 21 

Bay 

Chevron 864 864-4 12/97 16-12/97 16 

Chevron 820 819-1 1/98 22-2/97 22 

Exxon NCG 114-3 2/98 54-4/97 54 

Total 1997 499 368 

Added 

Production 4/98 575 444 

Source: Telcons with operators . 

Besides the five wells planned for the Destin Dome Field development, 16 wells are shown on 

Table 6.11 that potentially will added to production by year end 2000 . The wells are listed as 

TA, drilling, workovers, or under evaluation for spudding within 12 months . Table 6.11 shows 

their December 1997 status . 

157 
Table 6.11 

Norphlet Wells to Add to Potential Production by Year-end, 2000 

Operator Field Well Status December, 1997 

Chevron 820 819-1 TA ; Start-up January 1, 1998 

Exxon North Central 114-3 TA ; Start-up February 10, 1998 

Gulf 

Mobil 823 823-A5 TD ; 2/98 

Mobil 914 914-4 Drilling 

Shell Fairway 113-3 Complete Workover 

Chevron 861 862-1 Spud Sidetrack, 1998 

Chevron 863 863-4 Spud, September 1998 

Chevron 819 819-2 Planning 

Mobil Mary Ann 95-4 TA; reevaluation 1998 

Exxon 867 867-1 TA; Produce 1998 

Mobil BSB 61-1 Spud project w/Exxon, 1998 

Mobil Aloe Bay 75-2 Spud, 199$ 

Spirit/ 916 918-1 Spud, May 1998 

Chevron 871-1 Planning 

Shell 821 821-2 Planning 

Spirit 904 904-3 Spud, After 918-1 

Source: Telcons with operators. 

6.5.2 Sour Gas Processing Capacity and Utilization 

The start up of Mobil's Aloe Bay Field, Mobil's 823-5 and 914-3 wells, expansion of Chevron's 

820 and 864 Fields by two producing wells, recovery of Shell's 113-3 workover, and Exxon's 

114-3 well will move production from Coastal Alabama fields toward capacity of existing gas 

treating facilities during 1998. Table 6.12 shows the existing processing capacity and amounts 

of sour gas processed in these facilities during December 1997 . The plants operated at 72 

percent of capacity at year end, 1997 . 

158 
Table 6.12 

Gas Processing Facilities in Mobile Bay Region 

(MMCFD) 

Operator 

Onshore 

Capacity 

Offshore 

Capacity 

Total 

Capacity 

Capacity 

Use 4Q 

Avg/ 1997 

Mobil Mary Ann 180 0 180 132 

Mobil 823 300 0 300 207 

Shell (821) 0 60 60 15 

Yellowhammer 200 0 200 151 

Exxon 400 0 400 398 

Unocal 916 0 150 150 62 

Unocal 904 0 80 80 50 

Chevron 864 0 150 150 79 

Total Capacity 1080 440 1520 1094 

Source: Foster Associates, 1997; Alabama Oil and Gas Board, 1997. 

6.5.3 Gas Production Summary through 1997 

Mobile Bay Norphlet production exceeded 1 BCFD on a sustained basis for the first time in 

1997, averaging 1 .02 BCFD for 1997, 371 BCF for the year--18 percent more than 1996 

production of 863 MMCFD Norphlet gas. Annual state production since 1988 is shown on 

Table 6.13. Annual federal production is shown on Table 6.14 . Cumulative production has 

amounted to 1 .7 TCF of Norphlet; 288 BCF Miocene. Miocene is in decline . 

State Norphlet production rose to nearly 550 MMCFD during the first quarter of 1997 with the 

addition of MOEPSI's well 95-5 and Eon's well 111-3 . State production stepped up in the 

late summer when Aloe Bay well 75-1 came online and when Exxon's workovers on 112-1 and 

112-2 come back online . State production averaged 580 MMCFD for the year. Federal 

Norphlet production increase by 38 percent in 1997 over 1996 and averaged 435 MMCFD. 

Gas production began in Alabama state waters in 1987 when MOEPSI first produced gas from 

its Miocene well in the Southeast Mobile Bay Field. Production from this well was limited and 

was used solely as fuel for ongoing operations . Production ceased after 1989. The Mary Ann 

Field began production in 1988. Shell's Fairway Field started up in late 1991 along with 

MOEPSI's federal 823 Field. BP brought its 821/109 Field online in early 1992, and Exxon 

started its three fields in late 1993 . 

159 
o Table 6.13 

Summary of Gas Production in Mobile Bay State Waters by Reservoir and Field 

(BCF) 

Cumulative 

State Field Current O eratoi 1988 1989 1990 1991 1992 1993 1994 1995 1996 '1997 Thru 1997 

Miocene Fields 

East Mississippi Sound Legacy - - - - - - - 0.1 1 .8 0.1 2.0 

Goose Bayou Legacy - - - - - - - 0.1 1 .3 0.1 1 .5 

North Dauphin Island Callon - - - 0.2 19 .3 15 .9 11 .1 7.4 3 .8 2.1 59 .8 

Northeast Petit Bois Pass Offshore Group - - - - - - 0.4 0.1 1 .2 0.5 2.1 

Northwest Dauphin Island Offshore Group - - - - 0.6 0.9 2.0 1 .2 0.9 0.6 6.2 

South Dauphin Island SCANA - - - - - 0.6 3.5 2.6 1 .5 0.7 8.9 

Southeast Mobile Bay MOEPSI 0.2 0 .1 - - - - - - - - 0.3 

Subtotal Miocene 0.2 0 .1 - 0.2 19.9 17.4 17 .0 11 .5 10.5 4.1 80.9 

Norahlet Fields 

Aloe Bay MOEPSI - - - - - - - - - 3 .5 3 .5 

Bon Secour Bay Exxon - - - - - 3 .3 25.8 33 .8 38 .7 38 .7 140.2 

Fairway Shell - - - 3.4 63 .1 65 .8 64.2 50 .1 43 .7 36.7 326.9 

Lower Mobile Bay - Mary Ann MOEPSI 9.3 12 .8 19 .9 29 .3 29 .8 31 .6 31 .4 34.2 38 .8 45 .8 283.0 

North Central Gulf Mobile Area Exxon - - - - - 1.7 32.0 32.2 32 .0 28 .3 126.2 

Northwest Gulf Mobile Area Exxon - - - - - 11 .8 60.0 52 .3 46 .8 58 .1 229.0 

State 109/ Federal 821 Shell - - - - 0.7 0.8 0.5 0.4 0.3 0 .4 3 .1 

Subtotal Norphlet 9.3 12 .8 19 .9 32.7 93 .5 115.0 213.8 203 .1 200.2 211 .5 1,111 .9 

Total BCF 9.5 13.0 19.9 32.9 113.4 132.4 230.8 214.6 210.7 215.6 1,192 .8 

111MCFD 26.0 35.6 54.6 90 .0 310.8 362.8 632.5 587.8 577.2 590.6 -- 

Source : Alabama Oil & Gas Board, 1998 . 
Table 6.14 

Summary of Gas Production in Federal OCS Waters by Reservoir and Field 

(BCF) 

Cumulative 

OCS Field OCS Blocks Current O eratot 1991 1992 1993 1994 1995 1996 1997 Thru 1997 

Miocene Fields 

Mobile 823 778, 779, 822, Scana - - 23 6.8 5 .2 3 .2 2 .1 19 .5 

823, 824,867 

Mobile 861 860, 861, 862 Chevron USA - - - - - 0.0 2 .0 2.0 

Mobile 864 863, 864, 907, Chevron USA - 18 .8 20 .5 18 .2 13 .8 11 .5 8 .7 91 .5 

908,909 

Mobile 865 865 Scana - - - 2 .9 3.4 2 .8 1 .5 10.6 

Mobile 866 822,866 Scans - - - 0.9 0.9 1 .0 0.6 3 .4 

Mobile 870 870 Enron - - - 1 .1 4.7 53 5.6 16.7 

Mobile 914 914,958 Enron - - - 1 .0 2.5 1 .5 0.7 5 .6 

Mobile 945 945 Apache 0.1 1 .1 0.8 0 .6 0.5 0 .2 0.1 3 .5 

Mobile 947 947 Apache 0.1 1 .9 1 .6 1 .0 1 .1 0.9 0.6 7 .3 

Mobile 952 952,953 Murphy - 0.8 1 .1 1 .0 1 .0 1 .3 3.4 8 .6 

Mobile 955 955 Murphy - 1 .0 1 .4 1 .2 1 .1 1 .0 0.9 6 .7 

Mobile 959 915,959 OEDC/CJnocal - - - - 4.9 3.1 1 .4 9.5 

Mobile 959 960 OEDC - - - - 0.9 0.6 0.4 1 .9 

Mobile 961 917,961 Unocal - - - - 1 .4 1 .3 0.8 3.5 

Mobile 990 990, 991, VK22 A ache/Enron 0 .4 4.3 3 .9 2.9 2 .5 1 .8 1 .2 16 .9 

Subtotal Miocene 0.6 27.9 31 .7 37.5 44 .0 35.4 30.0 207.1 

Jurassic Fields 

Mobile 819 819 Chevron USA - - - - - - _ _ 

Mobile 820 820 Chevron USA - - - - - 2 .2 14 .5 16.7 

Mobile 821 821 Shell - 8 .7 10 .1 6 .0 5.4 4 .4 5 .5 40.1 

Mobile 823 778, 779, 822, MOEPSI 2.7 49.4 44.4 63.1 70.7 65 .1 49.8 345 .3 

823, 824,867 

Mobile 827 826,827 Exxon - - 0.5 7.0 4.1 1 1 .9 11 .0 34 .5 

Mobile 861 861,862 Chevron USA - - - 2.0 3 .5 3 .2 3 .3 11 .9 

Mobile 864 863,864 Chevron USA - - - - - - 5 .1 5 .1 

Mobile 868 868, 869, 914 MOEPSI - - - - - - 23 .3 23.3 

Mobile 872 872 Chevron USA - - - - - 3 .2 4 .6 7 .8 

Mobile 904 904 Unocal - - 0 .1 3 .9 - 0.2 15 .9 20.2 

Mobile 916 916 Unocal - - - - 9 .7 11 .3 7 .0 28.0 

Mobile 961 917,961 UnocaUChevron - - - - 4.7 133 18 .7 36.8 

Subtotal Jurassic 2.7 58 .1 55.2 82.0 98.1 114 .7 158 .8 569.7 

Total BCF 3.4 86 .0 86.8 119 .6 142 .1 150 .1 188 .7 776.8 

MMCFD 63.4 247.6 265.6 347.6 404.4 456 .3 518.6 -- 

o~ ( Sources : Dwights/Pl, 1998 ; U.S . Dept . of Interior, MMS, 1998 . ~ Production beginning in 1998 . 
Chevron initiated its federal Miocene production in 1992 in the 864 Field and started Norphlet 

production in 1994 in the 861 Field. Unocal started production in the 904 Field in 1993 and the 

916/961 Fields in 1995 . 

Shell and Exxon required 10 and 12 years from the 1981 lease sale to first production, with no 

significant regulatory delays . MOEPSI took nine years from first discovery to first production, 

after a ten year regulatory delay. These lead times match Alaska petroleum project lead times . 

The frontier nature of the Norphlet geology and the associated production engineering and 

technology challenges closely substituted for the challenges of Alaska's harsh, remote locale . 

Only the major oil and gas companies could afford the billions of dollars and years of investment 

necessary to bring the Norphlet into production . 

6 .5.4 Remaining Recoverable Reserves by Field 

Cumulative Norphlet production through year end 1997 totals 1 .7 TCF. Shell's Fairway Field 

and Mobil's 823 Field, both of which initiated production in 1991, have produced the most, over 

325 BCF each. Table 6 .15 shows that Fairway's 1996 cumulative production amounts to 38 

percent of discovered gas in place (GIP) ; 823 Field 1996 cumulative production amounts to 23 

percent of GIP. Fairway Field was shown on Figure 6 .9 to have been in decline since mid1994. Shell, sizing plant and equipment to peak, produced approximately 20 percent of GIP on 

peak before natural decline set in. Mobil and Exxon, by comparison, have sized plant and 

equipment to sustain a flat production rate longer, and have produced a substantially lower 

percentage of discovered reserves over comparable lengths of time. Nonetheless, some wells 

in 823 are showing signs that natural decline set in during 1996 . If so, the 823 Field decline 

set in at about the same 20 percent of produced GIP as Shell. 

Discovered state reservoirs are shown on Table 6.15 to be generally larger than federal 

reservoirs. Between 4 - 4 .4 TCF state recoverable reserves remain. Between 1 .3 - 1 .9 TCF 

federal recoverable reserves remain at year end 1996. These GRI estimates are in line with, but 

somewhat larger than AOGB and MMS estimates shown in Section 2 .1 . Reserve estimates tend 

to differ among practitioners . 

The 1997 average production rate, 1 .02 BCFD, results in a remaining reserve to production ratio 

(R/P) at year end 1996 of 14 to 17 . This is in line with the R/P calculated with AOGB and 

MMS reserve estimates in Section 2.1, which was 13 - 19. Shell, which has produced their field 

at the highest recovery rates, has the lowest R/P, 4 - 8. Fairway Field production in 1997 

amounted to 56 percent of peak year 1993 production . 

162 
Table 6.15 

Remaining Recoverable Reserves by Field : Year End 1996 

(BCC 

Field Cumulative 

Production 

12/96 

Discovered 

Gas in 

Place 

Percent 

Produced 

12/96 

Remaining 

Recoverable 

at 75% 

Remaining 

Recoverable 

at 55% 

Fairway 290 765 38% 284 130 

Mary Ann 237 1,400 17% 813 533 

(excl 95-5 

GIP) 

Northwest 171 1,125 15% 673 448 

Gulf 

Bon Secour 102 1,335 8% 899 632 

Bay 

North 98 985 10% 641 444 

Central Gulf 

State 109 3 20 15% 12 8 

Aloe Bay 0 1,500 0 1,125 825 

Total State 901 7,130 13% 4,446 4,020 

823 297 .8 1,325 23% 696 431 

821 35 .6 125 29% 58 33 

827 23 .4 275 8 % 183 128 

916/961 38 .2 715 5 % 498 355 

861 9.4 55 17% 32 21 

868 0 315 0 % 236 173 

904 5 170 3 % 123 89 

872 3 .5 185 2 % 135 98 

820/864 2.4 > 200 1 % 148+ 108+ 

Total 415.3 3,365+ 12% 2,109+ 1,436+ 

Federal 

Source: Production from Tables 6.13 & 6 .14; Reserve estimates from GRI, MMS and industry contacts . 

163 
6.5.5 Norphlet and Miocene Platforms 

A total of 39 fixed structures and platforms are located in Alabama state waters . Twenty five 

of the structures are platforms; the remainder are single well caissons . Table 6 .16 summarizes 

the types of platforms located in each field by operator. MOEPSI initiated production from the 

first platforms installed in 1988 . Six of the seven structures installed in 1991 are operated by 

Shell, with the remaining platform operated by Callon Petroleum (originally owned and installed 

by ARCO). Exxon installed 11 platforms and caisson wells in preparation for first production 

from its three state fields in 1993 . 

The number of structures installed on the Mobile OCS near Alabama waters to support 

production totals 44, comprised of platforms and well caissons . Table 6.17 summarizes the 

number of structures installed in each field by operators within the Mobile Area OCS. The first 

Mobile OCS platform was installed by Chevron on Mobile Block 861 . The next to be installed 

was also by Chevron in 1987 on Mobile Block 862 . 

Table 6.18 shows annual platform installation for Mobile OCS waters compared to those placed 

in Alabama state waters since 1979 . 

6.5.6 Forecast of Mobile Bay Gas Development & Production 

The forecast for gas production in Coastal Alabama, including total Miocene and Norphlet gas 

production through 2010, is shown on Table 6.19 along with 1996 and 1997 actuals. Norphlet 

production for 1998 will increase 10 percent over 1996 levels . Miocene production is declining . 

Coastal Alabama production will increase about ten percent annually for each of the three years, 

1998 - 2000. Destin Dome will supplant declining Coastal Alabama after 2001, and sustain 

Norphlet production levels above or near 1 .4 BCFD through 2005 . 

To create Norphlet production estimates for 1998 and beyond, wells in production in December, 

1997 plus the wells on Table 6.11 that have advanced beyond the planning stages are assumed 

to be added to existing reservoirs, produce 30 percent of discovered GIP on peak, and then 

decline at rates of between six and twelve percent annually until between 55 - 75 percent of GIP 

is produced . (See Table 6.15 for GIP.) The new wells (which are delineation and development 

wells) are assumed to be successful, and produce at an average rate of 33 MMCFD. Varying 

decline rates for different fields are specified based on historic and current production data, 

reserve estimates, and miscellaneous operator intelligence . Production forecasts for Chevron's 

Destin Dome unit were furnished by the operator. 

Miocene production averaged 98 MMCFD for 1997, down from 125 MMCFD for 1996 and 150 

MMCFD in 1995 . The decline in state and federal fields is assumed to continue at a rate of ten 

percent annually. No significant new Miocene production has been announced . 

Mobile Bay region Norphlet production will rise to near-peak levels of over 1,300 MMCFD 

(annual average) in 2000. The region's gas treatment capacity of approximately 1,520 MMCFD 

(excluding forthcoming Destin Dome capacity) may be utilized near capacity during the winter, 

1999-2000 and forthcoming years. After 2002, existing Mobile Bay Norphlet production will 

164 
Table 6.16 

Offshore Structures Located in Alabama State Waters 

Offshore Field Operator Type of Platform Installed 

Bon Secour Bay Exxon Well Platform (1) 1993 

Bridge-Connected Well 

Platform (1) 

Production Platform (1) 1993 

Fairway Shell Well Platform (4) 1991 

Bridge-Connected Well 

Platform (1) 1991 

Production Platform (1) 1991 

Goose Bayou Legacy Single Well Caisson (1) 1995 

Lower Mobile Bay - Mobil Well/Production Platform (4) 1988 

Mary Ann Bridge-Connected Well/ 

Production Platform (1) 1988 

Production Platform (1) 1988 

North Central Gulf Eon Well Platform (1) 1993 

Bridge-Connected Well 

Platform (1) 1993 

Production Platform (;1) 1993 

North Dauphin Island Callon Production Platform (1) 1991 

Petroleum Single Well Caissons (5) 1991 

Northwest Dauphin Offshore Production Platform (1) 1994 

Island Group Single Well Caissons (3) 

Northwest Gulf Exxon Well Platform (2) 1993 

Production Platform (1) 1993 

Bridge-Connected Living 

Quarters Platform (1) 1993 

Bridge-Connected Well 1993 

Platform (1) 

Northeast Petit Bois Offshore Single Well Caisson (1) 1994 

Pass Group 

South Dauphin Island Scana Single Well Caissons (3) 1992 

East Mississippi Legacy Production Platform (1) 1995 

Sound Single Well Caisson (1) 

Source : AL Oil and Gas Board, 1997. 

165 
Table 6.17 

Platforms and Caissons in Mobile OCS Waters 

Field Name/ 

Block Number 

Operator Structure Name Year 

Installed 

M0821 

821 BP A-QUARTERS 1991 

M0823 

822 Scana A 1993 

822 MOEPSI B 1994 

823 MOEPSI A 1991 

M0827 

827 Exxon CB 1992 

M0861 

861 Chevron A 1985 

861 Chevron AB 1991 

M0864 

863 Chevron #2 CAISSON 1990 

863 Chevron A 1994 

864 Chevron A-5064 1991 

864 Chevron BA(43) 1994 

864 Chevron B 1995 

864 Chevron BQ 1995 

908 Chevron A-5071 1991 

908 Chevron SAT. #2 1991 

M0865 

865 Scana 43 1994 

M0866 

822 OEDC A 1993 

822 OEDC B 1994 

M0868 

868 MOEPSI A 1992 

869 MOEPSI A 1990 

M0870 

870 Enron #2 PLAT. 1988 

870 Enron A 1994 

M0872 

872 Chevron #1 CAISSON 1996 

166 
Table 6.17 (continued) 

Platforms and Caissons in Mobile OCS Waters 

Field Name/ 

Block Number 

Operator Structure Name Year 

Installed 

M0904 

904 Unocal AP 1993 

904 Unocal AQ 1993 

904 Unocal AW 1993 

M0914 

914 Enron A 1994 

M0916 

916 Unocal #1 CAISSON 1987 

916 Unocal #2 1991 

916 Unocal AP 1994 

916 Unocal AQ 1994 

916 Unocal B 1994 

M0945 

945 Apache #1 CAISSON 1990 

M0947 

947 Apache #1 CAISSON 1990 

M0952 

952 Murphy # 1 1992 

953 Murphy # 1 1992 

M0955 

955 Murphy #2 1992 

M0959 

915 OEDC #1 CAISSON 1988 

959 A 1994 

M0960 

960 OEDC A 1995 

M0961 

917 Unocal A 1994 

961 Unocal #1 CAISSON 1987 

M0990 

990 Apache #1 CAISSON 1990 

990 Enron A 1991 

Source: US DOI MMS, 1998 . 

167 
Table 6.18 

Mobile Bay Offshore Structure 

Installations by Year 

State Federal 

1985 0 1 

1986 0 0 

1987 0 2 

1988 6 2 

1989 0 0 

1990 0 5 

1991 12 8 

1992 3 5 

1993 11 5 

1994 5 12 

1995 2 3 

1996 0 1 

Total to 39 44 

1997 

Sources: US DOI MMS, 1998; AL Oil & Gas Board, 1997. 

168 
Table 6.19 

Mobile Bay Offshore Gas Production Forecast 

Annual Average (1996 - 2010) 

(MMCFD) 

Year Nor phlet Miocene 

Coastal Alabama Coastal Alabama Total Gas 

Alabama Mobile Destin Total Total Alabama Mobile Production 

State OCS Dome Norphlet Miocene State OCS 

1988 26 - - 26 0.5 - 0.5 26 

0 1989 35 - - 35 0.4 - 0.4 36 

1990 55 - - 55 - - - 55 

to 1991 90 7 - 97 0.5 1 .7 2.2 99 

1992 254 159 - 414 55 76 131 545 

1993 313 151 - 464 48 87 134 598 

1994 585 225 - 809 47 103 149 959 

1995 555 269 - 824 32 120 152 976 

1996 548 298 - 846 29 97 126 972 

1997 581 423 - 1,004 11 77 88 1,092 

Source : Foster Associates, 1998. 

169 
begin a slow decline, falling below 900 MMCFD by 2008, if no other reserves are brought on 

line . The addition of Chevron's Destin Dome production in 2001 will sustain peak regional 

production levels for five years over 1 .4 BCFD into 2005 . 

Production of natural gas from the Destin Dome Area located in the Eastern Gulf of Mexico is 

shown on Table 6 .19 . Destin Dome gas production will start up in 2001 with estimated 

production of 42 BCF, or 115 MMCFD, that year . Destin Dome gas production is projected 

to reach peak at 110 BCF in 2004, producing 300 MMCFD, and to remain on peak for seven 

years . By 2004, Mobile Bay production (excluding Destin Dome) will have declined to about 

1,210 MMCFD from its 2000 - 2001 peak near 1,400 MMCFD. Destin Dome's contribution 

to total Mobile Bay regional production is shown on Figure 6.16 . Destin Dome production will 

account for a quarter of total regional Norphlet production after 2005 . 

Combining both the Alabama state and federal OCS baseline offshore production, the forecast 

for total offshore production in the area is shown on Figure 6 .16 . This figure plots monthly 

production data. Coastal Alabama and Florida natural gas production will rise to 1 .4 BCFD in 

2000 and remain above 1 .4 BCFD through 2005-with no more discoveries. The forecast on 

Figure 6.16 yields over 9 .5 TCF cumulative production of Norphlet and Miocene by 2015 . 

170 
1,800 

1,600 

1,400 

1,200 

w 1,000 

800 

600 

400 

200 

0 

00 

00 

M AL State Norphlet D Mobile OCS Norphlet 

D Destin Dome OCS ES Miocene 

Figure 6.16 . Mobile Bay Offshore Gas Production History and Forecast. 

Source : Foster Associates, 1998. 

O N ~' ~1O 00 O N d' ~D oo O N V' O~ Q~ O~ ON O O O O O O~ O~ ~ O~ O1% O O O O O O O O ^' '-' ~ ~ N N N N N N N N 

APPENDIX 

Offshore Gas Forecast Reserve and 

Decline Rate Assumptions 

Post -1997 Well Startups Assumed in Mobile Bay 

Gas Production Forecast 

Field Name Well No. Startup Date 

Production 

Rate 

(MMCFD) 

A1 State 

North Central Gulf 114-3 Feb-98 33 

Aloe Bay 75-2 Jul-99 33 

Bon Secour Bay 61-1 Jul-99 33 

Mary Ann 95-4 Mar-00 33 

Aloe Bay 75-3' Jun-O1 33 

Aloe Bay 75-41 Jun-03 33 

Federal 

M0820 819-1 Jan-98 22 

M0864 864-4 Dec-97 16 

M0823 823-A5 Jun-98 33 

M0914 914-4 Jul-98 33 

M0861 862-1ST Jan-99 33 

M0864 863-4 Mar-99 33 

M0870 870-1 Mar-00 33 

M0918 918-1 Mar-00 33 

M0871 871-1 Jun-00 33 

Total New Wells Through 2001 15 467 

Source: Telcons with operators. 

' A new well is assumed at some point in the future to utilize large 

proved reserves in this field. 

175 
Offshore Gas Forecast Reserve and Decline Rate Assumptions 

M0823 

250 8096 

70% 

200 

609'0 

150 

." 

'~ mom 509'0 

0 

_ . 

UP 

"f 

i OeGine . . . 40'S'o 

1~5 . . 

.. .. . 

0.6696 

100 3096 

~' 

209'0 

50 

105'0 

0 0% 

29i Si 2Si 2fi ZSi 2i g 25 25 2S o 0 0 0 0 0 '- e- N N N N N N N N N N N 

-Production ----GIP Produced 
Offshore Gas Forecast Reserve and Decline Rate Assumptions 

v 

M0861 

as so% 

ao 70% 

35 .' 60% 

30 % 

50gb~ 

0 25 

409' 

~ 20 

15 

30% 

N10961 

10 20% 

_ ._ .w,.. ..m~...k ,... ..... .... 

GIP (bcfl Decline ' ~ .. . ..

29D

. .. .. .. e. .. .. .

0.50°k

.. . . 103'0 

0 ~ 09'0 

I °s "s s o 6 

Co 

,C11 C4 - ~- e- ~- r N N N N N N N N N N N 

Production ----GIP Produced 

M0872 

1s sow 

14-- 

-- 50% 

12 -- 

'0 40%~ 

0 

8 30%~ 

6 

NI08M 

20°k 

4 r~ 

i . .__.~. .~,..V,.., .w.,. .. ............., .. ...._ 

' (bCi) Decline 109'0 

.. ..

p 86 

. .. ... .> ... .. .

0.60°

.. . . 

0 0'Yo 

"s s o s °s N N N N N N N N N N N 

Production ----GIP Produced 

M0868/914 

goo aos% 

so i' 70% 

80 

70 ` I 6096 

Ln'I 

60 ' u 509'0 

50 

40 '' 3090 

30 ~' N1086fi1914 

20 

.. .. . 

209'0 

_.GIP.(bcP) Decline 

; .. . . . . . . . 

10 500 0.60°h 10% 

.. . . 

0pp p ~ ~p~~~pppp~p~p OYo 

O1 O1 OI W O1 ~ O S ~ O O 

O N if 10 aD N 

N N N N N N N N N N N 

-Production ---- GIPProduced 
Offshore Gas Forecast Reserve and Decline Rate Assumptions 

00 

M0916/961 

1so soy, 

140 80% 

120 

.' 

709'0 

60%$ 

100 ` 

o i SOYo1 

' 40% 

60 L~ I 

30%a 

40 IV109161961 

, 

20% 

20 " ' 

V^ 

,. ..~. .~ .., . ., . .. ..w.~ . .w ._ 

. GP #0 Dedins 

.. . . .. .a . . .. .. .. .. .. .. . .

. .. . 

716 0.66°k 

10% 

0 0% 

2fi 2fi 2Si ~ gi 25 g 25 25 25 0 0 0 0 0 0 r r r e- ~- e- N N N N N N N N N N N 

-Production ----GIP Produced 

Mobile Bay Miocene Production 

Federal + State 

70 

60 - - 

I 

60 - - 

40 - C) - 

~ 30- - 

20 

10 

0 cp 

Of OI Ol O1 ~ OI N N N O N N N N 
Offshore Gas Forecast Reserve and Decline Rate Assumptions 

J 

Aloe Bay 

120 60% 

100 " 50% 

I 80 40% 

I'o 

60 30% 

40 

' Aloes say 

20% 

1 

l-1 . . .. .. .. .. . ... .. ., . . .. .. ... . .. .. .. .. . . 

20 ~' GIP.(bCf) DBC.IIr18 10'Yo 

'18D0

. . .. ; . . ..

0.60° 

. .. . . 

0 0% 

~ °s o °s o s s e- r r r ~ ~- N N N N N N N N N N N 

Production ----GIP Produced 

Bon Secour Bay 

160 809'0 

140 - " 70% 

120 6090 

100 y SOg'o 

O 

80 409'0 A 

60 30Yo 

i 

40 r 

Bon Secour Bay 

2096 

_.....:w. , ......._ ..., .. .,.~, .,..., ,.,... ., ... . "' GIP (bcf) Decline 

20 

1336

. .. .. x .. .. ..

0.60%

.. . . 109'0 

0% 

"s~~~oN .~~~oN § N N N N N N N N N N N 

-Production ----GIP Produced 

Lower Mobile Bay/Mary Ann Less 95-5 

120 7090 

100- 60% 

509'0 r 

o aoo~ 

so 

--30%-

40 - 

Lower Mobile Say(Mary --20% 

. .Ann Les966 

.. .. . ... .. .. . .. .. . .. . .. .. .. . .. . .. . 

20 -- GP (bc0 Decline 

. . :. .. . . .. . . . .. .. .. . 1090 

1400 0.0/0 

0 0% 

00 0 N It 0 00 0 N V 0 0 0 

~ o~+ ~ ~ ~ tS ~5 g 25 25 0 0 o p 

N N CV N CV N N CV N CV N 

-Production ----GIP Produced 
00 Offshore Gas Forecast Reserve and Decline Rate Assumptions 0 

North Central Gulf + 95-5 

zoo so% 

180 

- 70% 

160 

60% 

140 

North Central Qif + 95-6 

120 

. .. . . 

(ten o~~~e

.. ... o 

100 -- . .. .. .. .. ; .. . . .. .. .. . . .. .. . 4U% a 

i 995 0.85°h 

80 30% 

60 -- 

20% 

40 

20 i ~ 

10°"6 

0 0°.6 

O O O O O 

N N ~ N N N N N N N N 

-Production ---GIPProduced 

Northwest Gulf 

250 - g0% 

70°h 

200 

60% 

r S0% 

o ~N 

U 

I 

40°h a 

100 L 

30°,6 

i fVorThwe4 QO 

20% 

50 ' ,~ 

GP ~n 

. . .. .. .

Decline

.. . . 1125 0.60° _ . 

' 

10% 

0 

. 

O N of f0 t0 ON 

O1 ~ Of ~ Of ~ O O O O O 

r N N N N N N N N N N N 

-Production ---GIP Produced 
7.0 Bibliography 

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181 
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182 
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7.2 Magazine Articles 

Natural Gas Intelligence, Chevron, Mobil, Phillips, Apache Announce Large Finds, February 

10, 1992, pp. 5-6 . 

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26, 1979, p. 29 . 

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37. 

Oil and Gas Journal, Sixth Dry Hole Plugged on Eastern Gulf Acreage, August 10, 1981, pp. 

202-203 . 

Oil and Gas Journal, Mobile Bay Wildcat Drilling Programs Outlined, August 17, 1981, pp . 80-

81 . 

Oil and Gas Journal, Mobil, Partner to Make Joint Bid for Marathon, December 7, 1981, p. 

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Oil and Gas Journal, OSC Sale 67 Bids Top $1 .2 Billion, February 15, 1982, p. 64. 

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185 
Oil and Gas Journal, Mobil to Pay for Mobile Bay Discharges, October 4, 1982, p . 46. 

Oil and Gas Journal, Exxon to Join Drilling Action in Lower Bay, January 10, 1983, p . 44 . 

Oil and Gas Journal, Big Area-wide Sale Shaping Up in Gulf of Mexico, May 16, 1983, p . 31 . 

Oil and Gas Journal, Gulf Acreage Draws Record High Bids, May 30, 1983, pp. 62-63 . 

Oil and Gas Journal, Gulf of Mexico Lease Sale Exposure Totals $4 .5 Billion, June 6, 1983, 

p. 48 . 

Oil and Gas Journal, Interior Awards Flurry of Gulf of Mexico Leases, June 20, 1983, p. 81 . 

Oil and Gas Journal, Gulf Sale High Bids Top $1 .5 Billion, August 29, 1983, pp. 30-31 . 

Oil and Gas Journal, $500 Million Exposed for Gulf Tracts, January 16, 1984, pp . 56-58 . 

Oil and Gas Journal, OCS Sale 81 to Offer about 6,400 Tracts, April 2, 1984, p. 53 . 

Oil and Gas Journal, Gulf Deepwater Tracts Spark Bidding, April 30, 1984, p. 36-40 . 

Oil and Gas Journal, Hot Gulf of Mexico Head Gulf Coast/Southwest Action, May 21, 1984, 

pp. 112-121 . 

Oil and Gas Journal, Exxon Leads Spending in Mobile Bay Lease Sale, August 27, 1984 . p . 30. 

Oil and Gas Journal, Sohio, Eon Test Gulf of Mexico Discoveries, September 10, 1984, p . 

98. 

Oil and Gas Journal, First Development, Gas Strike Listed Off Alabama, September 24, 1984, 

p. 44 . 

Oil and Gas Journal, Mobile Strike Retested; Mississippi Sets Sale, November 5, 1984, p. 71 . 

Oil and Gas Journal, Mobile Bay Shaping Up as Major Gas Producing Area, January 14, 1985, 

p. 25 . 

Oil and Gas Journal, Exxon to Step Up Mobile Bay Search, February 18, 1985, pp . 66-67 . 

Oil and Gas Journal, Leasing, Drilling State and Federal Alabama Waters, April 22, 1985, pp. 

134-135 . 

Oil and Gas Journal, Deep Water, Mobile Bay Tracts Spark Sale 98, May 27, 1985, p . 46-50. 

Oil and Gas Journal, Exxon and Chevron Score in Mobile Bay, June 17, 1985, p. 143 . 

186 
Oil and Gas Journal, Interior Marks Eastern Gulf Leases to be Offered, August 26, 1985, p. 32. 

Oil and Gas Journal, Mobil Has First Mobile Bay Production in Sight, June 30, 1986, p. 36 . 

Oil and Gas Journal, Exxon Gauges Latest Discovery in Norphlet Trend Off Alabama, 

September 15, 1986, p. 49 . 

Oil and Gas Journal, Exxon Mobile Bay Project Hinges on Gas Market, November 10, 1986, 

pp . 40-42 . 

Oil and Gas Journal, Mobile Bay Development Project Progressing, March 16, 1987, p . 36. 

Oil and Gas Journal, Development Activity Dots Mobile Bay Trend, April 6, 1987, p. 27. 

Oil and Gas Journal, Mobil Eyes New Norphlet Test off Alabama, January 11, 1988, p. 76 . 

Oil and Gas Journal, Chevron Plans Mississippi Sound Norphlet Test, May 9, 1988, pp. 58-59 . 

Oil and Gas Journal, Mobil Steps Up Norphlet Gas Flow Off Alabama, July 18, 1988, p . 18 . 

Oil and Gas Journal, Lack of Metallurgy May Delay Norphlet Drilling, November 21, 1988, 

p. 32 . 

Oil and Gas Journal, Norphlet Gas Find Indicated Off Pensacola, February 21, 1989, p. 18 . 

Oil and Gas Journal, Industry Slates More Exploration, Development in the Gulf Norphlet, 

March 6, 1989a, p. 15-16. 

Oil and Gas Journal, Smaller Miocene Targets Draw Attention in Norphlet Areas, March 6, 

1989b, p. 17 . 

Oil and Gas Journal, Some Key U.S. Gas Trends Busy ; Others Await Higher Prices, April 24, 

1989, pp. 55-59. 

Oil and Gas Journal, Norphlet Gas Development Set in Federal Water, October 9, 1989, p . 24 . 

Oil and Gas Journal, Gulf of Mexico Report, Tempo of Gulf Activity Brightens Outlook, OGI 

Special, December 11, 1989, pp. 41-47 . 

Oil and Gas Journal, Mobil Gauges Gas Off Alabama; More Subsea Wells Due in Gulf, June 

18, 1990, p. 30. 

Oil and Gas Journal, Exxon to Develop Gas Reserves Off Alabama, September 24, 1990, p. 46 . 

Oil and Gas Journal, Gas Flowing from Field Off Alabama, November 11, 1991, p . 27 . 

187 
Oil and Gas Journal, Industry Briefs, October 19, 1992, p . 40. 

Oil and Gas Journal, Onshore Alabama Norphlet Test Under Spotlight, August 23, 1993, pp. 

18-19 . 

Oil and Gas Journal, U.S . Firms Boosting U.S . Production, Reserves, November 8, 1993, p. 

101 . 

Oil and Gas Journal, Mobile Bay Gas Flow Rising in Response of E&D Campaigns, January 10, 

1994, p. 23 . 

Oil and Gas Journal, U .S . Gulf, April 25, 1994, p . 74 . 

Oil and Gas Journal, New Mobile Bay Complex Exploits Major Sour Gas Reserve, May 23, 

1994, pp . 49-51 . 

Oil and Gas Journal, Industry Briefs, October 10, 1994, p . 36. 

Oil and Gas Journal, More Norphlet Gas Coming On Line Off Alabama, November 28, 1994, 

p. 38 . 

Oil and Gas Journal, Another Mobile Block Production Facility Nears Completion, January 30, 

1995, p. 91 . 

Oil and Gas Journal, Unocal Steps up Gas/Condensate Production, May 29, 1995, p . 24. 

Oil and Gas Journal, Economics and Technology Help Spark Gulf Deepwater Projects, March 

13, 1995, pp. 25-31 . 

Pipeline and Gas Journal, Specialized Techniques Developed, March 1987, pp. 38-40 

7.3 Newspaper Articles 

Birmingham Post Herald, Bay Oil Drilling Block Asked, January 11, 1972. 

Birmingham Post Herald, Storm Brewing Over Fate of Lease Funds, April 3, 1981 . 

Cullman Times, Oil Bonanza Couldn't Have Come at Better Time for State, April 21, 1981 . 

Mobile Press, Baxley's Negative Stand on Oil, January 12, 1972 . 

Mobile Press, Coastal Drilling Plans Shape Up, June 23, 1981 . 

Oil, Gas Board to Hold Proposed Rules Hearing, undated news clip, 1972 Alabama newspaper. 

188 
7.4 Alabama Oil and Gas Board Dockets 

Alabama Oil and Gas Board Reference Number: 

11-7-808 

6-30-83 

12-17-879A 

9-6-86 

11-9-937 

7-17-964 

4-14-929 

12-13-90165 

11-9-933 

2-6-924 

189 

PS~ENT OF Tjr~ The Department of the Interior Mission ~P 

y~ 

a - p As the Nation ' s principal conservation agency, the Department of the Interior has responsibility for 

~ most of our nationally owned public lands and natural resources. This includes fostering sound use 

of our land and water resources; protecting our fish, wildlife, and biological diversity; preserving the 

,y _ a9 

4 9 

environmental and cultural values of our national parks and historical places ; and providing for the 

ACM 3 ~ enjoyment of life through outdoor recreation . The Department assesses our energy and mineral 

resources and works to ensure that their development is in the best interests of all our people by 

encouraging stewardship and citizen participation in their care. The Department also has a major 

responsibility for American Indian reservation communities and for people who live in island territories 

under U .S. administration . 

The Minerals Management Service Mission 

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS) primary 

respons ibiliti es are t o manage th e m i nera l resources l oca t e d on t h e N at i on ' s Outer Continental Shelf 

(OCS), collect revenue from the Federal OCS and onshore Federal and Indian lands, and distribute 

those revenues. 

,r ~E ~` Moreover, in working to meet its responsibilities, the Offshore Minerals Management Program 

administers the OCS competitive leasing program and oversees the safe and environmentally sound 

exploration and production of our Nation's offshore natural gas, oil and other mineral resources. The 

MMS Royalty Management Program meets its responsibilities by ensuring the efficient, timely and 

accurate collection and disbursement of revenue from mineral leasing and production due to Indian 

tribes and allottees, States and the U.S . Treasury. 

The MMS strives to fulfill its responsibilities through the general guiding principles of : (1) being 

responsive to the public's concerns and interests by maintaining a dialogue with all potentially affected 

parties and (2) carrying out its programs with an emphasis on working to enhance the quality of life for 

all Americans by lending MMS assistance and expertise to economic development and environmental 

protection .