A. D. Koen
Senior Editor
News
Mobile Bay is fulfilling its early promise as a major U.S. offshore gas play, nearly a quarter century after Alabama issued the first offshore leases in the area.
After more than a decade of slow development, gas production is ramping up in and around the bay. Operators are bringing more wells on line and building and expanding production, gathering, and processing facilities. At the same time, pipelines are beginning to reach out to the next wave of prospects, mostly in federal water off Alabama, Mississippi, and Florida.
Major integrated companies are leading the push, mostly pursuing large reserves of sour Jurassic Norphlet gas in hot, high pressure reservoirs more than 20,000 ft deep. But more independents are getting a piece of the action by focusing on relatively small Miocene gas reserves at depths of less than 3,000 ft.
Mobile Bay gas flow began gaining momentum in 1992, when operators in state water produced a little more than 306 MMcfd of Norphlet and Miocene gas. Alabama's offshore gas production in 1991 fell just short of 90 MMcfd, up from about 26 MMcfd in 1988.
Early estimates place the state's yearend 1993 offshore gas production at more than 600 MMcfd. Also at yearend, major company gas plants in Mobile County, Ala., were treating more than 700 MMcfd of gas, up from 400 450 MMcfd at the beginning of the year.
EXXON PRODUCTION
Exxon Co. U.S.A.'s start up in fourth quarter 1993 of its large Norphlet gas project in Mobile Bay accounted for most of Alabama's new offshore production in 1993.
Exxon on Oct. 20 began treating Norphlet gas onshore from Northwest Gulf field on State Tracts 111, 112, and 131. Gas from Bon Secour Bay field on Tracts 62, 63, and 64 reached the processing plant about Nov. 12 and from North Central Gulf field on Tracts 114, 115, and 116 about Nov. 29.
The company's processing plant is on an 86 acre site in Mobile County just south of Theodore, Ala. Gas reaches shore by way of a 30 in. pipeline that makes landfall near Bellingrath Gardens.
Exxon estimates the cost of its Mobile Bay facilities at more than $1 billion, plus lease acquisition costs of about $600 million and as much as $30 million to drill and complete each of the 11 wells in the three fields.
Development costs were high because of the challenges of producing extremely, sour gas from very deep, hot, high pressure reservoirs. Hydrogen sulfide concentrations of Norphlet wells off Alabama range from as little as 50 ppm to as much as 10%, and carbon dioxide content can reach 4%. In addition, temperatures in productive Norphlet intervals exceed 400 F., and bottomhole pressures range from 10,000 to 20,000 psi.
David E. Bolin, assistant supervisor of production and engineering at the Alabama Oil and Gas Board, Tuscaloosa, said Exxon reached the 300 MMcfd capacity of its Mobile Bay facilities soon after all three fields were on line. By mid December, Exxon was selling about 306 MMcfd, he estimated.
OTHER MAJOR COMPANIES
Other major producers in 1993 maintained gas flow in state waters at about the same levels as in 1992.
Shell Offshore Inc. in 1993 produced about 172 MMcfd of gas, 25 long ton/day of sulfur, and 1,000 b/d of natural gas liquids from its Fairway field. Shell's Yellowhammer plant in Mobile County processed about 188 MMcfd during the year.
Operator Shell and Amoco Production Co. kicked off Fairway production in December 1991 from five wells on State Tracts 113 and 132, about 3 miles south of Dauphin Island. Shell owns a 64.3% interest in the development, Amoco 35.7%.
Mobile Bay's other major Norphlet gas producer, Mobil Exploration & Producing U.S. Inc., in 1993 produced 80 90 MMcfd from its Mary Ann field on State Tracts 76, 77, 94, and 95. Mobil's Mary Ann gas production a year earlier averaged about 81 MMcfd.
After working over one Mary Ann well last year, Mobil boosted the field's deliverability to about 130 MMcfd. However, production is constrained by capacity of the Mary Ann gas plant. Mobil intends to resolve the problem by November by expanding facilities.
Mobil at yearend 1993 also was shipping about 170 MMcfd of Norphlet gas from three wells on Mobile Block 823, across Mobile Bay, to a 250 MMcfd processing plant alongside the Mary Ann plant. Mobil owns a 100% interest in Mary Ann field and a 97% interest in Mobile 823.
MOBIL'S NORPHLET EXPANSIONS
Phil Moses, Mobil's Mobile Bay asset management team adviser, said expanding capacity of the Mary Ann gas plant to about 160 MMcfd will allow Mobil to increase production of Norphlet gas in state and federal water.
Mobil's plans include expanding its Mobile Bay gathering system and installing a 60 MMcfd production train on its Mobile 823 A platform to handle high sulfur gas from the tract's A 4 well. That well in December 1993 flowed 68 MMcfd of Norphlet gas with about 2.8% H2S content through a 70/64 in. choke with 2,550 psi flowing tubing pressure from pay at 22,570-730 ft. Other Mobil Norphlet wells on Block 823 have H2S contents ranging from 100 to 200 ppm.
Mary Ann gas plant after the expansion will be able to process as much as 160 MMcfd with an average H2S content of 5%. Capacity of the Block 823 plant will be about 250 MMcfd for gas with as much as 200 ppm of H2S.
Under an agreement with Shell, Mobil is to begin shipping about 10 MMcfd of sour Mary Ann gas through Shell's Fairway field facilities to the Yellowhammer gas plant. Gas is to flow from the idle Mary Ann D platform on Tract 95 through about 800 ft of pipeline Mobil is to lay to a shorebound Shell gathering line.
PIPELINE INFRASTRUCTURE
Mobil's gathering line construction from Mary Ann A platform to shore will create a 20 in. corridor for Mobile Block 823's relatively sweet Norphlet production all the way to the Block 823 gas plant.
Low sulfur Norphlet gas from Mobile 823 now flows through a 20 in. pipeline to Mary Ann A platform, where it enters a 16 in., 250 MMcfd pipeline for delivery to the Block 823 plant onshore. Mobil plans to lay a 20 in., 400 MMcfd gathering pipeline from Mary Ann A platform to Block 823 plant to deliver low sulfur Mobile 823 gas to shore. That will open the 16 in. line to high sulfur throughput.
Once the gas plant expansion and pipeline construction projects are complete, Mobil will transport sour gas from Mobile 823's A 4 well to A platform on Tract 76 across an idle 8 in. pipeline. Sour Mary Ann and A 4 Norphlet gas will be commingled in the 16 in. line at A platform for delivery to the Mary Ann plant.
Mary Ann gas currently flows to shore through a 10 in. pipeline that Mobil will mothball when the 16 in. pipeline begins shipping Mary Ann gas.
When Mary Ann and Mobile 823 sour Norphlet production begins to decline, Mobil expects to be ready to fill the unused processing and transportation capacity with gas from its Aloe Bay field. Mobil discovered Aloe Bay in January 1992 with a well on State Tract 75. Aloe Bay field focuses on that tract, but also covers parts of Tracts 74, 92, and 93.
FEDERAL NORPHLET DISCOVERIES
As Norphlet development has progressed within Mobile Bay, operators have continued defining Norphlet gas prospects in the Mobile and Destin Dome federal planning areas to the south.
Among recent activity:
- Union Oil Co. of California last month began producing Norphlet gas from a 100% owned, three platform development on Mobile Block 904. Production of 20 25 MMcfd was expected.
- Chevron U.S.A. Production Co. early last month reported its third Norphlet trend discovery after tests of Norphlet intervals on Mobile Blocks 861 and 917 flowed a combined 103 MMcfd (OGJ, Dec. 20, 1993, Newsletter). Chevron was planning to spud two more Norphlet wildcats in the Mobile area last month and two this year.
Unocal's installation on Mobile 904 includes a two slot wellhead platform, an 80 MMcfd processing platform, and a quarters platform. The complex is considered a prototype for development of other Unocal acreage in the Mobile area. Unocal operates 16 of 24 blocks in the Mobile area in which it owns interests.
Unocal began Mobile 904 production last Dec. 22. The Mobile 904 processing platform is to treat Norphlet gas on the tract with hydrogen sulfide concentrations as great as 120 ppm. In addition, Unocal is to process Mobile 861 gas on Mobile 904 facilities. Unocal estimates cost of Mobile 904 facilities at about $24 million.
Gas from Mobile 904 and 861 is to flow to shore through a 10 in. gathering line connected to a 12 in. lateral on the Chandeleur offshore gas pipeline system. Onshore, the gas is to be delivered to Chevron's 295,000 b/cd Pascagoula, Miss., refinery. Gas not consumed at Pascagoula is to flow through Koch Gateway Pipeline Co.'s interstate pipeline system to industrial customers on the Gulf Coast.
Mobile 904 is part of a 23,040 acre, four tract, 100% Unocal owned unit that covers Mobile Blocks 904, 905, 948, and 949. The development is based on a February 1992 discovery that achieved the highest flow rate measured in the Mobile area. Unocal's 1 OCS G 5749 well flowed 97.6 MMcfd through a 42/64 in. choke from perforations in a 146 ft interval at 22,130 290.
CHEVRON'S NORPHLET OUTLOOK
Chevron in December disclosed its No. 8 well in Mobile Block 861 field flowed 57 MMcfd of gas from Norphlet pay below 21,000 ft. Mobile 861 field is a three tract federal unit off Mississippi. Operator Chevron with 50% interest and partners Unocal and Pennzoil Exploration & Production Co. with 25% interest each expect to begin selling gas from the field early this year.
Chevron last month planned to spud a well on nearby Mobile Block 863.
Chevron's well on Mobile 917, which flowed 46 MMcfd of gas from Norphlet pay below 22,000 ft, extended Mobile 916 field off Alabama 2 miles to the east. Chevron holds a 91.3% interest in the discovery, Offshore Bechtel Associates Ltd. 8.7%. Block 916 field operator Unocal and Chevron each own 45.65% interests in the unit and Bechtel 8.7%.
Chevron estimates combined production from five multitract Norphlet prospects in the Mobile area could reach 330 600 MMcfd. The company expects combined production from an 11 tract block it holds with three partners off Florida in Destin Dome area to amount to 150 360 MMcfd.
Operator Chevron and Conoco Inc. with 33.3% interest each and Mobil and Pennzoil with 16.7% interest apiece in December planned to spud a Norphlet wildcat on Destin Dome Block 97, about 30 miles south of Pensacola. The test will be about 9 miles northeast of Chevron's 1987 Norphlet gas discovery on Destin Dome Block 56.
TENNECO GATHERING LINE
Growing Mobile Bay area gas production and successful Norphlet exploration in federal water prompted Tenneco Gas Gathering Co. last October to announce plans to lay a 200 MMcfd gathering system into the area.
Tenneco's 20 in., 30 mile line at first will connect Mobile 916 field wells to the interstate gas pipeline systems of Koch and Transcontinental Gas Pipe Line Corp.
Transco since 1989 has been moving gas from the Mobile Bay area through a 123 mile, 30 in. pipeline. Koch Industries Inc., Wichita, Kan., in November 1992 acquired the interstate pipeline system of United Gas Pipe Line Co. United about mid 1992 began shipping gas from the Mobile Bay area through the 28 mile, 30 and 16 in., 600 MMcfd line.
Jim Gotcher, director of supply development for Tenneco Gas, said Tenneco has asked the Army Corps of Engineers for permits to lay the pipeline and is preparing to order pipe for the project. Tenneco expects to call for construction bids in February and start construction as early as April or May.
GATHERING FLEXIBILITY
Tenneco expects its gathering line to have enough capacity to add volumes from other discoveries in the area if the opportunity arises. If subsequent discoveries warrant extension of the pipeline into the Destin Dome area, Tenneco could increase its capacity to 400 MMcfd by adding compression at the system's onshore links with the Transco and Koch lines.
Gotcher said Tenneco's agreements with Chevron, Unocal, and Bechtel call for them to feed low sulfur gas treated on the Mobile 916 platform into the new gathering system.
"But things change as the world turns," he said, "so just to be on the safe side, we'll install pipe that allows us to later handle more sour gas if we need to because the incremental construction costs of installing sour gas handling capability is very small."
Much of the new gathering system coming on fine in the Mobile Bay area can deliver Norphlet or Miocene gas into either Transco's or Koch's Mobile Bay pipelines.
MIOCENE GAS PRODUCERS
While majors have been focusing mainly on finding and developing Norphlet gas off Alabama, Mississippi, and Florida, several independents have been pursuing smaller, shallower Miocene gas prospects in the region.
Offshore Energy Development Corp. (OEDC), The Woodlands, Tex., since its formation in 1988 has become one of the most active independents in Alabama state water by following a two fold strategy that involves:
- Acquiring and developing low risk Miocene gas prospects revealed by 3D seismic data in state and federal water near Mobile Bay.
- Developing gathering lines in the area to move gas to shore.
OEDC Pres. David Strassner said Miocene reservoirs in the area tend to be quite small. But OEDC last year was able to develop several Miocene prospects around Mobile Bay by clustering projects and tying them into centralized production or gathering facilities.
Upon seeing the need for a pipeline to transport gas to shore, OEDC conceived and developed the Dauphin Island Gathering System (DIGS). DIGS at yearend 1993 was transporting 70 80 MMcfd of gas from Miocene wells just outside Mobile Bay, up from about 30 35 MMcfd earlier in the year, due mostly, to start of production from OEDC operated wells.
DIGS transportation volumes by spring 1994 could exceed 100 MMcfd and by fall could reach 150 200 MMcfd. Beyond that, the system will compete with Tenneco's proposed gathering pipeline for uncommitted Miocene or low sulfur Norphlet gas produced in the area.
DIGS DEVELOPMENT
OEDC began permitting the DIGS route to shore before it drilled its first Miocene gas discovery in summer 1991 on Alabama Tract 90.
Rather than skirt Dauphin Island by wax, of the ship channel and main pipeline corridor at the mouth of Mobile Bay, OEDC decided DIGS could best be routed by boring under Dauphin Island and heading straight to shore.
Oystermen, fishermen, and other offshore businesses and environmental interests supported OEDC's plan. Officials granted the necessary permits. Its right of way approved, OEDC in fall 1991 began focusing on how to pay for the Miocene gas gathering system.
Also in fall 1991, BP Exploration Inc. had an earlier Miocene gas discovery in federal water on Mobile Block 821 for which it needed a shorebound gathering line. BP agreed to dedicate Block 821 gas to DIGS, and OEDC and BP that fall formed a strategic relationship through which BP temporarily financed OEDC's pipeline crossing under Dauphin Island that has become the hub of DIGS.
Under the strategic relationship, BP began laying a 12 in. DIGS gathering pipeline for OEDC from Block 821 toward OEDC's crossing point under Dauphin Island. At about the same time, OEDC began inserting a bundle of three 12 in. pipes into a 4,000 ft long bore under Dauphin Island. The 12 in., 4 mile line from BP's Block 821 well included a side tap where OEDC later connected wells on State Tracts 90, 91, and Mobile Block 822.
In fourth quarter 1991 OEDC hooked one of the DIGS 12 in. lines under Dauphin Island into a 12 in. line running to shore from ARCO Oil & Gas Co.'s North Dauphin Island field platform on Tract 73. So at first, DIGS gathered BP gas from Block 821 and shipped it under Dauphin Island to Tract 73, where it moved to shore through the 12 in. ARCO line.
GROWTH OF DIGS
In spring 1992, OEDC began seeking permits to lay a 20 in. DIGS pipeline from the north end of the Dauphin Island tunnel to onshore links with interstate gas pipelines.
In January 1993 OEDC and Enron Gas Gathering Inc., a unit of Enron Gas Services, Houston, formed Dauphin Island Gathering Partners (DIGP), a 50 50 venture to own and operate DIGS. DIGP in spring 1993 installed a 12 mile, 20 in. line across Mississippi Sound, and gas began flowing across the span last May.
All the while, OEDC continued acquiring more offshore acreage south of Dauphin Island, including the south half of Tract 91 from Amoco and Shell and shallow rights on the federal Block 823 unit from Mobil and partners. In spring and summer 1993, the company drilled four successful shallow Miocene gas wells south of Dauphin Island, including two wells on Mobile 822, one on Tract 91, and a second well on Tract 90.
OEDC then set a four pile platform on Mobile 822 to serve as a centralized gathering facility and laid 4 in. flow lines to tie its Miocene wells into the facility. Next, OEDC laid an 8 in., 3 mile gathering line from its Mobile 822 platform to BP's 12 in. pipeline between Mobile 821 and the DIGS Dauphin Island crossing.
DIGS partners this month began laying a 40 mile extension of the 400 MMcfd DIGS gas gathering system across federal water south of Mobile Bay.
The new DIGS 20 in. span during third quarter 1994 is to begin gathering low sulfur gas from shut in wells in the Mobile planning area and northern tier of tracts in the Viosca Knoll area.
NEW MIOCENE PRODUCERS
Miocene gas from OEDC wells on Tracts 90 and 91 and Block 822 began flowing into DIGS in late August or early September 1993.
Also in September, OEDC combined parts of Tracts 90 and 91 to set up South Dauphin field. Then in mid-December 1993, OEDC unitized the field and at yearend was producing 35 40 MMcfd of Miocene gas from the field's three wells and the two wells on Mobile 822, all between 2,000 2,900 ft deep and several with multiple completions.
Two other independents stepped up activity near Mobile Bay in mid-1993 by acquiring ARCO's Miocene gas producing leases in the Mississippi Sound area of western Mobile Bay.
A production platform and five single well caissons in North Dauphin Island field on State Tract 73 and parts of Tracts 72, 90, and 91 went to Callon Petroleum, Natchez, Miss. A single well caisson in Northwest Dauphin Island field in the northeast quarter of Tract 71 and southeast quarter of Tract 57 was bought by Offshore Group Inc. (OGI), Houston.
Miocene gas production in 1993 from North Dauphin Island field averaged about 45 MMcfd and from Northwest Dauphin Island about 2.3 MMcfd, compared with 52.7 MMcfd and 1.7 MMcfd, respectively, in 1992.
OGI in second half 1993 drilled one well on Tract 57 and permitted another north of the well it took over from ARCO.
Alabama's Oil and Gas Board in late December approved an OGI application to set a platform jacket on Tract 57. OGI began installing the jacket just before yearend. Oil and gas board permission to install the platform's topside is expected this month.
If all goes as planned, OGI early this year is to begin producing Miocene gas from its three Northwest Dauphin Island wells.
Pipeline companies believe producers' optimism and upstream spending indicates the gas resource base in and around Mobile Bay is very large.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
