NEW MOBILE BAY COMPLEX EXPLOITS MAJOR SOUR GAS RESERVE

May 23, 1994
Warren R. True Pipeline/Gas Processing Editor In March, Exxon Co. U.S.A. dedicated its natural gas treating plant near Mobile, Ala. From start up, the plant was handling its capacity of sour gas from leases in state and federal waters offshore in Mobile Bay. The company claims this is the world's largest sour gas development, with reserves estimated at more than 1 tcf (OGJ, Apr. 11, p. 24). Exxon further believes the wide swings in gas composition have led to a unique air emissions permit
Warren R. True
Pipeline/Gas Processing Editor

In March, Exxon Co. U.S.A. dedicated its natural gas treating plant near Mobile, Ala. From start up, the plant was handling its capacity of sour gas from leases in state and federal waters offshore in Mobile Bay.

The company claims this is the world's largest sour gas development, with reserves estimated at more than 1 tcf (OGJ, Apr. 11, p. 24).

Exxon further believes the wide swings in gas composition have led to a unique air emissions permit from the state of Alabama.

The complex, third in the area for handling the high sulfur gas being produced in the bay, began taking the full 300 MMcfd of gas in October 1993 when the overall project started up.

PRODUCING CONDITIONS

The project includes more than 61,000 acres spread over 17 leases with 11 wells.

Three fields comprise the production area (Fig. 1):

  • Northwest Gulf, south of Dauphin Island, contains four wells

  • North Central Gulf, south of Ft. Morgan, has four wells

  • Bon Secour Bay, northeast of Dauphin Island, has three wells.

In designing the plant, Exxon had to consider widely varying sour compositions from the three areas.

In the Northwest Gulf field, wells in Blocks 111 1 and 112 2 each produce gas with approximately 50 ppm H2S, while production from Block 112 1 has as much as 0.15% and Block 111 2, 3%.

In the North Central Gulf field, gas from Block 827 produces gas with 90 ppm H2S; Block 115, 100 ppm; Block 116, 120 ppm; and Block 114, 0.2%.

In the Bon Secour Bay field, however, the concentration is on average far greater. In Block 78, the gas contains as much as 1.4% H2S; in Block 63, 1.5%; and in Block 62, 9.7%.

Composition of CO2, for all wells is about 3.5%.

Fig. 2 presents production area flow patterns.

These wide swings in H2S COMPOSItion led to what Exxon feels is some unusual, perhaps unique features in the plant.

But offshore, the swings in H2S content and the high downhole and wellhead pressures and temperatures led to use of corrosion resistant alloy (CRA) material in all equipment upstream of each offshore separator on the production platforms.

Exxon says that the 4 in. flow lines, rated at full wellhead pressure, are insulated with polyisocynaturate to avoid cooling produced fluids to hydrate formation temperatures. This insulation is in turn protected by an outer steel jacket pipe.

Flowing temperatures are greater than 300 F. at the wellheads and up to 420 F. downhole. Shut in pressures can reach 10,600 psi. A high-pressure cooler on each well template cools a produced stream to nearly 180 F. en route to a platform.

Separation on each platform sends a dry sour gas stream and a liquids (mostly water) stream ashore for processing. The gas moves through a 24-in. carbon steel line protected with inhibitors.

UNIQUE PERMIT

Exxon's plant is the third gas processing complex to be built in recent years for Mobile Bay gas.

Mobil Exploration & Producing U.S. operates two plants side by side at a single site. The Mary Ann plant processes 80 90 MMcfd from Mary Ann field (OGJ, May 8, 1989, p. 36); expansion will be completed by yearend.

The second plant processes as much as 230 MMcfd from Mobil's Mobile Bay Block 823 (OGJ, Jan. 10, p. 22).

And Shell Offshore Inc., New Orleans, opened its Yellowhammer plant in late 1991 to process as much as 200 MMcfd of sour (0.15 0.8% H2S) gas from five producing wells of Shell Offshore's Fairway field 17 mile south (OGJ, Feb. 22, 1993, p. 58).

The plant uses Shell Sulfinol and Shell Claus Offgas Treating (SCOT) units along with a straight refrigeration process for liquids separation. It can produce up to 60 long tons/day (ltd) of sulfur, 190 MMscfd (at 1,000 psig) of pipeline quality natural gas, and as much as 2,300 b/d of mixed NGLs.

Fig. 3 shows the major plant units and sections at Exxon's new plant.

The varying compositions in the produced sour gas led to a plant design that incorporated two sulfur plants and what Exxon feels may be the first of a kind in air emissions permit from the state of Alabama.

The plant is rated to handle 300 MMcfd of gas and produce up to 150 ltd of sulfur. But, Exxon says, if the sulfur production is turned down because of lower sulfur content in the gas, the plant's inlet capacity exceeds 300 MMcfd.

The company obtained an air emissions permit that recognized fluctuations in the streams and sulfur production. The permit incorporates a formula that calculates allowable emissions based on a sliding scale of sulfur production and plant inlet gas volumes.

PLANT FLOWS

At the plant's inlet separation area, two fines a 24 in. gas and 8 in. liquids line move streams from offshore to the plant. Three lines a 6 in. dilution water line, a 6 in. fuel gas line, and a 4 in. diesel transfer line carry water, fuel gas, and diesel offshore (Fig. 4).

The dilution line is for future contingency. Exxon says that later in the fields' lives, produced streams could bring in as much as 400,000 ppm of total dissolved solids that could lead to deposition in flow lines and equipment of carbonate, berium sulfate, or sodium chloride.

Should this change be realized, Exxon will inject fresh water carried offshore through the 6 in. water line at the wellhead to dilute the production stream. Currently, however, Exxon is not injecting any water.

The fuel gas line powers the offshore equipment.

To absorb diamondoids and prevent crystallization and plugging in the flow lines, Exxon purchases and pumps offshore some 800 b/d of fresh diesel for injection into the well streams. The diesel returns mixed with produced water, is separated, stabilized, and vacuum fractionated to marine grade fuel, then sold.

The 1,350 bbl inlet slug catcher receives large volumes of liquids when the 24 in. pipeline delivers ashore pigs for various duties: cleaning or inspection, for example.

Prime contractor for the plant was H.B. Zachry, San Antonio. Engineering subcontractor was Raytheon Engineers & Constructors, Denver.

Design rates at the separation area are 300 MMcfd of sour gas and, to the liquids separator, 5,000 b/d of water and 2,000 b/d of diesel. The fuel gas line to offshore can move as much as 7 MMcfd.

The sour gas moves to two sweetening trains (150 MMcfd each) that use 50% weight methyldiethanolamine (MDEA) solvent in high pressure contactor towers to remove H2S and CO2. Inlet gas filters remove any solids.

The MDEA moves through a solvent stripper and is regenerated; the stripper rejects H2S and CO2 to the acid gas enrichment (AGE) unit. Two electrically driven and one steam driven pumps circulate solvent back to the high pressure contactor.

Two 150 MMcfd dehydration trains follow the MDEA sweetening units and use triethylene glycol (TEG) to dry the gas to "pipeline sales gas specification (

SULFUR RECOVERY

As stated, the varying inlet compositions led to a split sulfur plant design (Fig. 4).

Sour gas from the MDEA regeneration unit moves to the AGE unit which uses Flexsorb SE+ to enrich acid gas that has an H2S concentration of 20 80%. The unit absorbs the H2S and rejects the CO2 to a thermal oxidizer.

Flexsorb is regenerated in the Flexsorb stripper which rejects the H2S gas to the sulfur plant.

The sulfur plant consists of two straight through Claus plants. The 40-ltd plant can tolerate turndown rates of 8 10 ltd; the 110 ltd plant, 20 30 ltd. Each is designed to achieve 96% recovery.

The system generates 450 and 50 psig steam from the waste heat reclaimer units and has two sulfur tanks, each designed for 4 1/2 day storage capacity.

Urea is injected into the molten sulfur to release H2S; the eductor system recovers the H2S and sends it to the thermal oxidizer.

Two tail gas clean up units, one for each plant, convert the remaining 4% sulfur in the tail gas back into H2S to be reprocessed through the sulfur plants. This allows the plant to achieve a total system recovery of 99.8%. The process uses Flexsorb SE + from the Flexsorb stripper.

In liquid form, sulfur is sold on the local and regional fertilizer markets.

The thermal oxidizer consists of two gas fired furnaces to burn vapors at 1,500 F. to oxidize reduced sulfur compounds and generate 450 psig steam from the waste heat reclaimers. Two 250 ft towers vent compounds to the atmosphere.

Total power used and produced at Exxon's plant is 33,840 hp. Plant electrical generation equipment provides 12 mw of power from three 5,300 hp Allison KB 5 turbines with synchronous generators that provide 3,400 kw, 4,160 v (ac), of electrical power each, and one 1,247 hp steam turbine with an induction generator providing 930 kw, 4,160 v (ac), electrical power.

The plant consumes approximately 5.5 mw, selling the excess to Alabama Power Co. for local distribution.

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