Mobile Bay gas enjoying banner year despite production problems

William W. Wade, Jay Plater
Foster Associates Inc.
San Francisco

• Outlook for Mobil Bay offshore gas production [98,310 bytes]

• Remaining Norphlet Reserves; Yearend 1996 [50,987 bytes]

• Mobile Bay Norphlet Wells Tested. 1995-97 [86,523 bytes]

• Unocal's and Chevron's Problem Wells [55,984 byes]

• Active Norphlet Fields - August 1997 [181,390 bytes]

• Mobile Bay Offshore Gas Production [199,534 bytes]

• Mobile Morphlet Production [193,222 bytes]

• Norphlet Wells Planned for Production End 1998 [64,881 bytes]

• Gas Processing Facilities in Mobile Bay Region 66,752 bytes]

This article was adapted from a report sponsored by the Gulf of Mexico office of the U.S. Minerals Management Service.

Recent production increases by operators in Mobile Bay off Alabama highlight their success in surmounting the challenges posed by sour, high-temperature, high-pressure deep Norphlet gas.

Production from the Mobile Bay offshore continental shelf (OCS) would have been greater sooner but for myriad problems keeping many Norphlet wells from producing at their high design rates. Most of those wells produce from reservoirs at 21,000-23,000 ft subsurface (see related story, p. 31).

Production status

Coastal Alabama natural gas production surpassed 1 bcfd early in 1997.

Production from state and federal offshore leases in the area-already one of the most important U.S. gas producing regions-will continue to increase this winter.

New production from deep Norphlet pay zones will boost annual 1997 output by 40% from the 1996 average of 864 MMcfd.

Norphlet gas production is expected to average 1.214 bcfd for 1997.

As of March 1997, a total of 74 Norphlet wells had been drilled in state and federal waters off coastal Alabama. Of these, 28 were exploratory wells, and the balance were delineation and development wells and expensive disappointments. The 28 exploration wells have discovered 19 gas fields-a 68% success ratio.

Mobil Exploration & Producing U.S. Inc. brought the most recent field, Aloe Bay, into production in July 1997. Production started at 22 MMcfd but had ramped up to 40 MMcfd by September.

All but three of the fields discovered in the area are producing gas. And production is planned from two of the remaining three:

• Chevron USA Production Co. and its partners Conoco Inc. and Murphy Exploration & Production Co. filed a development and production plan on Destin Dome in December 1996.
• Exxon Co. U.S.A. maintains its Mobile Block 867 lease and plans to start producing it in 1998.
• Only Mobil's West Dauphin Island field has been abandoned as uneconomic.
• As a result of recent developments, combined state and federal gas production in coastal Alabama is expected to surpass 1.4 bcfd by the end of this winter. Operators in the region can maintain this output through the middle of the next decade by starting production from the Destin Dome area, 22 miles south of Pensacola, Fla.

Production history, reserves

Norphlet gas production began in Alabama state waters when Mobil first produced gas from its Mary Ann field.

Shell Offshore Inc.'s Fairway field started up late in 1991, along with the first federal production from Mobil's 823 field. Production from 823 has dominated Mobile Bay OCS gas supplies.

BP Exploration Inc. brought its 821/109 field on line early in 1992, and Exxon started up its three fields late in 1993.

Until 1996, Miocene gas production accounted for nearly half of federal production in the region. That year, federal leaseholders began a substantial ramp-up of Norphlet production that will continue through 1998 and eclipse Miocene gas's importance to regional supplies.

Cumulative Norphlet production through yearend 1996 totaled 1.3 tcf: 900 bcf from state leases, 413 bcf from OCS. Miocene gas adds 256 bcf to the total.

State Norphlet production surpassed the 1 tcf benchmark in late February. Shell's Fairway field and Mobil's 823 are the biggest producers at more than 290 bcf each.

Fairway's cumulative production amounts to 38% of original gas in place (OGIP). The field has been in decline since mid-1994. By sizing the gas plant and equipment for peak production, Shell produced about 20% of OGIP on peak before natural decline set in.

Mobil and Exxon, by comparison, sized their plant and equipment to sustain a flat production rate for a longer period and have produced a substantially lower percentage of discovered reserves.

Combined state and federal discovered reserves are 10.5 tcf. Remaining recoverable reserves are 3-4.4 tcf in state leases and 1.4-2.1 tcf in federal.

Chevron's Destin Dome discoveries add potentially 1 tcf or more to discovered reserves.

If production averages 1.2 bcfd in 1997, this yields a reserves-to-production ratio (R/P) of 12-15 at yearend 1996.

Shell, having produced its field at the highest recovery rates, has the lowest R/P, 4-8, assuming production of 36.5 bcf in 1997.

Fairway production in 1997 will barely equal 55% of output in its peak year (1993).

Exploration, development

During the last 4 years, coastal Alabama drilling has been dominated by Chevron, Mobil, and Unocal Corp.

Chevron and Unocal are developing Mobile OCS Norphlet fields on the eastern and western edges of the area, and Mobil brought on two very large producing wells-95-5 in the Mary Ann field and 869-3, which started production from the federal 869 field.

Two fields have been discovered in the last 4 years-Chevron's 864 and 820-bringing the total to 19 Norphlet fields off the coast of Alabama.

Mobil's 95-5 well came on line in November 1996 and produced 72 MMcfd the following December. The well taps a reservoir that underlies Exxon's Tract 114, the southern portion of Mobil's Tracts 94 and 95, and the northwest corner of Exxon's Tract 113.

Mobil took the 869 lease over from Texaco and drilled well 869-2, which was tested in May 1994 at a rate of 60 MMcfd. It encountered a liner top problem during completion and was plugged and abandoned.

Mobil then spudded 869-3 in May 1996. This well started producing in February 1997 at 78 MMcfd. Production had increased to 85 MMcfd by March 1997 but backed off to 65 MMcfd during the summer because of heat limitations on a platform cooler.

In March 1997, Exxon started producing from the 111-3 well in the Northwest Gulf field at a rate of 79 MMcfd (above expectations). Also in March, Exxon spudded 114-3 in the North Central Gulf field to offset Mobil's 95-5 well.

Eastern Mobile OCS

The eastern area of the Mobile OCS includes Chevron's 100% owned 872 field and the 916 unit, consisting of 61/4 blocks: 871 S/4, 915, 916, 917, 918, 961, and 962.

Operators Unocal and Chevron each own 45.7% of the 916 unit; Bechtel Corp.'s Fremont Energy Corp. unit owns the rest.

The Mobile 916 area facilities, or Fort Morgan complex (the field is about 12 miles southeast of Fort Morgan), started production in April 1995.

Three bridge-connected platforms are capable of producing and treating 150 MMcfd of sour gas and 30 MMcfd of sweet Miocene gas on the 916 central platform. The Norphlet gas contains 60 ppm H2S. Commingled pipeline-quality gas is shipped in the 20-in. Dauphin Island Gathering System pipeline to the Mobile County interstate connection.

Unocal and Chevron were producing nearly 120 MMcfd of combined Norphlet and Miocene gas in April 1997. The gas was delivered to the 916 platform facilities from five Norphlet and two Miocene wells.

Unocal started producing from 916-A2 in April 1995 at 17 MMcfd; this ramped up to 32 MMcfd in June and averaged 25 MMcfd through yearend 1995. Well 916-B3 came on line in April 1995 and hit 15 MMcfd the following month, before encountering a water intrusion problem (OGJ, May 29, 1995, p. 24).

Chevron started up well 917-A2ST in April 1995; the well produced 40 MMcfd of gas containing 80 ppm H2S. Production had fallen to 11 MMcfd by April 1997. Unocal, which had a different view of the structure's geology, is not a partner in this well.

Chevron's 100%-owned 872-A1 well began producing in March 1996 and averaged 11 MMcfd by midyear. Well 961-A2 started production in July 1996 at 24 MMcfd and ramped up to 50 MMcfd in April 1997.

Unocal's two Miocene wells began production in April 1995.

Western Mobile OCS

Unocal and Chevron are developing discoveries on the 861, 904, 820, and 864 blocks on the Mississippi side of the Mobile OCS. This is the most dynamic area of the Norphlet this year.

Gas is processed on platforms on Tracts 864 and 904 and at the Yellowhammer plant. The platform facilities can process 230 MMcfd of Norphlet gas with an average 120 ppm H2S. Shell, with its Fairway field in decline, has capacity for about 100 MMcfd of sales gas.

Gas from Tracts 904 and 861 is processed on the 904 platform and flows to shore via a 10-in. connection to the Chandeleur pipeline. Chandeleur is connected to Chevron's Pascagoula refinery and from there to the Koch Gateway Interstate pipeline.

Chevron started production from 861-8 in June 1993. The gas flows to Unocal's 904 facility. The well began producing at 30 MMcfd but developed water problems and was off production from August 1994 until January 1995. Production has never returned to the high initial rates; the well is currently maintaining production of 10-12 MMcfd.

Unocal began production from its 904-1 well in December 1993. The well reached a peak production rate of 22.3 MMcfd-well below its record test rate-but was lost in August 1994.

Unocal brought 904-2 on line in December 1996 at 32 MMcfd. This well is expected to produce 50 MMcfd after stabilization. The ultimate production rate from the 904 field is yet unknown.

Chevron's 864-3 well started producing at 20 MMcfd in October 1996 but encountered a water production problem and was shut in. It was plugged and abandoned in April 1997.

Well 864-4 was spudded in May 1997 to replace 864-3. Ultimately, the well is expected to produce about 30 MMcfd.

Chevron's 863-3 well cut more than 250 ft of net pay at a depth of more than 21,700 ft in September 1994 (OGJ, Oct. 10, 1994, p. 36). On test, the well revealed an unexpectedly high H2S content for the field-1.7%-requiring installation of a pipeline to Shell's Fairway field so that 863-3 gas could be processed in the Yellowhammer plant.

Production from 863-3 started in February 1997 at 18 MMcfd and ramped up to 47 MMcfd in April. The well was shut in during the summer because of a mechanical problem with the surface-controlled subsurface safety valve (Scssv). It is now back on line. Its peak production rate is as yet unknown.

Chevron spudded well 819-1 in September 1996 and reached TD of 22,042 ft in December. Well logs confirm a gas discovery, and completion equipment is on order.

The drilling time of the well shows that Chevron achieved a new level of productivity with the well. Drilling took 31/2 months, compared with the previous standard of 5-6 months. (Mobil's first two Norphlet wells each took 1 year to drill.) Chevron attributes the short drilling time to its bit selection and casing program.

Planned production from these western Mobile OCS fields will exceed 200 MMcfd by early 1998, assuming 863-3 is restored to its high production rate. The gas is processed at Yellowhammer and in platform facilities.

Production will increase beyond 200 MMcfd in 1998, when production is slated to begin from wells that are either drilling or to be spudded.

Problem wells

Keeping Norphlet wells producing at design rates is as difficult as finding the reservoirs below 20,000 ft.

In addition to diamonoid plugging, which was recognized early by Mobil and must be managed by most Norphlet operators, scaling problems related to calcium fluoride and calcium carbonate plague the operators.

Exxon completed a workover of its 112-1 well in September. The well had been shut in since June 1996. A workover of 112-2, shut in since March 1997, was completed in August.

Development of Unocal's and Chevron's Norphlet discoveries in western Mobile Bay OCS overcame superpressurized reservoirs (15,000 psi) and the other hostile downhole challenges encountered in Norphlet reservoirs: H2S, CO2, water, and temperatures of 420° F. Several gas wells have been damaged or lost during either completion or start up.

Chevron's 861-1 well blew out underground in 1985 after discovering Norphlet gas. Norphlet wells that are completed too close to the water contact at the bottom of the reservoir can develop a water coning problem because of the tight rock.

Three wells have produced water problems (so much water has intruded that the wells are either plugged and abandoned or can produce at only reduced rates). This is the same problem that Shell has with the BP-completed well 821-1.

Assuming a cost of close to $30 million to drill and complete a Norphlet well, the six troublesome wells represent a $180 million problem with a lot of lost production.

Sour gas processing

Norphlet gas is a hot, sour, high-pressure, corrosive mixture of methane, H2S, CO2, and free water. Handling it is difficult, dangerous, and expensive.

Development requires an integrated system involving specialized technologies for production, dehydration, pipeline shipment, and processing. More than $3.5 billion has been spent since the early 1980s to install these systems and drill wells. These expenditures are in addition to $1.4 billion in bonus payments to acquire the leases.

Mobil, Exxon, and Shell all have constructed sour-gas processing plants in Mobile County. First BP, and subsequently Unocal and Chevron, decided to process Norphlet gas at the platform and ship market-quality gas to shore.

Mobil's Mary Ann plant is the most recent capacity debottlenecking. Sulfur recovery at the plant was increased this year to 470 tons/day from 285 tons/day, to enable the plant to handle the 8% H2S Aloe Bay gas.

The start-up of Mobil's Aloe Bay field, expansion of Chevron's 820 and 864 fields by three producing wells, the workovers on Exxon's 112 wells, and Exxon's 114-3 offset to Mobil's 95-5 are likely to increase production from coastal Alabama fields to fill the capacity of existing gas treating facilities by winter 1998.

Production from Mobil's Aloe Bay field will more than fill Mary Ann plant. Exxon's return to service of its two 112 workover wells, plus the completion of the 114-3 well will exceed the 400 MMcfd nameplate capacity of the processing plant dedicated to those wells.

Chevron's development plans are matched by their existing spare processing capacity. And Shell has merchant space available to take in moderate-sulfur Norphlet gas. In view of the production forecast exceeding 1.6 bcfd in the coming years, further debottlenecking of plants can be expected.

Forecast

There are 38 producing wells in the 18 active Norphlet fields. Twelve wells may be added to production in these fields, as are five in the Destin Dome development.

Exxon's 112-2 workover returned to production at 30-40 MMcfd.

Foster Associates' forecast assumes that Chevron's 819-1 well will be added to production this winter. The forecast also assumes that Exxon's 114-3 and Chevron's 864-4 and 819-2 wells will begin producing next year. (Exxon's well was below 18,000 ft in mid-August.)

The other wells are considered too uncertain to be included in the forecast.

Miocene production averaged 125 MMcfd in 1996, down from a peak of 150 MMcfd in 1995. The decline in both state and federal Miocene fields is assumed to continue at 10%/year.

No significant new Miocene production has been announced to come on line after 1996, although Exxon plans to spud a Miocene well on Tract 827 this year.

State Norphlet production rose to nearly 550 MMcfd during first quarter 1997 with the addition of Mobil's 95-5 well and Exxon's 111-3. Production stepped up this summer with the addition of Aloe Bay Well 75-1 and the return to production of Exxon's 112-1 after workover. State Norphlet production could reach 650 MMcfd by this winter.

Federal production will increase by more than 75% in 1997 from 1996 and average about 578 MMcfd for the year. Mobil's very productive 869-3 well, and large production increases from Chevron's and Unocal's separate and jointly owned wells 820-1, 904-2, and 863-3, account for the 1997 production increase to date.

Federal production could reach 630 MMcfd by this winter. The forthcoming 1997 start-up of Chevron's well 819-1 and next year's 819-2 and 864-4 wells will support continued growth in federal production.

Coastal Alabama Norphlet production will average 1.2 bcfd in 1997 and 1.4 bcfd in 1998. The region's gas treatment capacity of about 1.5 bcfd could be utilized at near capacity during peak-demand months.

Destin Dome

Having successfully probed the DD56 geologic structure with two wells in 1988 and 1990, Chevron spudded an exploration well on Tract DD97 in March 1994. This well was unsuccessful. Chevron subsequently hit pay with another gas well in October 1996 on Tract DD57-three successes out of four wells-and filed a development plan in December 1996.

Production could begin in 2000, marking the first natural gas production from the Destin Dome area in the eastern Gulf of Mexico. Estimated production in 2000 will be 115 MMcfd.

Production is expected to peak at 300 MMcfd in 2003 and remain on peak for 7 years. By 2003, Coastal Alabama production (excluding Destin Dome) will have declined to 1.15 bcfd from its 1999 production rate of more than 1.4 bcfd.

Destin Dome production will account for a quarter of total regional Norphlet production at peak, utilizing pipeline capacity that would otherwise have been idled by declines in Mobile Bay production.

The addition of Chevron's Destin Dome production in 2000 will sustain peak regional production levels of more than 1.4 bcfd for 5 years. After 2005, existing Norphlet production will begin a slow decline, falling below 1 bcfd by 2010 if no other discoveries are brought on line.

Foster Associates predicts cumulative production of Norphlet and Miocene gas to be 8 tcf by 2010.

The use of 3D seismic and computer-aided exploration (CAEX) workstations-as it has elsewhere in the oil and gas exploration industry-has transformed the way Mobile Bay operators explore for hydrocarbons and select bottomhole production locations.

Although the largest Norphlet reservoirs were discovered before 3D was widely used, Mobil's 1995 well, 95-5, and its final bottomhole location-with a sidetrack 700 ft east of the initial location-illustrate how 3D and CAEX are improving Norphlet results.

Mobil's 95-5 well illustrates the effects of 3D seismic data on well placement. Mobil spudded the well in July 1994, deviated 7,400 ft east from a rig located outside the Mobile Bay shipping fairway on Tract 94. The initial well was tested in May 1995 and judged capable of producing 50 MMcfd.

Three-dimensional seismic data were used to clarify the top and base of Norphlet and show the geologic depth cross section of the well. Conventional 2D seismic could be relied on only to supply information on structural position. Using the extremely fast computing power of the CAEX workstation allowed integration of the 3D data with geologic data to pinpoint a bottomhole location.

The well was sidetracked to a location 8,100 ft east of the rig to maximize both structural height and stratigraphic thickness. It reached TD in October 1995.

Moving the well 700 ft east of its original bottomhole location improved the porosity from 11.7% to 12.8% and markedly improved the well's productivity. The sidetracked well tested at 77.3 MMcfd. Production averaged 70 MMcfd during the 2 months following start-up in November 1996.

The increased productivity improves the economics dramatically. The added 20 MMcfd boosts cash flow by $20,000/day at a wellhead netback price of $1/Mcf. An incremental $6 million/month will pay for a substantial amount of 3D seismic data and drilling rig time.

The Authors