New gulf pipeline begins feeds to Louisiana processing

Kevin C. Bodenhamer
Williams Cos.
Tulsa
John P. Laguens
Bridgeline Gas Distribution LLC
New Orleans

The Larose plant has two 300-MMcfd cryogenic turboexpander trains built by Black & Veatch-Pritichard, Kansas City (Fig. 4; photo by Debbie Crites).
The Paradis, La., fractionator (above at right) can produce 42,000 b/d of NGL. An ethane-treating facility appears in the foreground and fractionation towers in the background (Fig. 5; photo by Michael Hart). Photos courtesy of Discovery Producer Services [28,996 bytes]
McDermott's DB28 laybarge laid the 30-in. main line to a water depth of 785 ft (Fig. 7). Photograph by Michael Hart, courtesy of Discovery Producer Services. [34,892 bytes]
A $350 million gas gathering and processing system began its start-up sequence at the end of September, flowing wet gas from Gulf of Mexico producers offshore Louisiana to processing and marketing onshore.

The Discovery project marks the first major grassroots offshore gathering and processing system along the Louisiana Gulf Coast in more than a decade.

The system is fed by a new 105-mile, 30-in. main line that reaches the edge of the Outer Continental Shelf at Ewing Bank 873 and brings raw gas ashore to a cryogenic gas-processing plant near Larose, La., 35 miles south of New Orleans (Fig. 1 [183,570 bytes]).

With ultimate capacity of 900 MMcfd and a maximum water depth of 785 ft, Discovery's line ranks as the deepest 30-in. (or larger) line in the gulf.

An expansion scheduled for 1999 will extend the pipeline system farther offshore, accessing deepwater wells (3,200 ft deep) at Green Canyon 254.

Discovery's grassroots 600-MMcfd Larose plant performs condensate separation and gas processing. Larose also has the capacity to stabilize 7,500 b/d of condensate.

Recovered NGL can be fractionated about 20 miles farther north at Discovery's 42,000-b/d Paradis, La., fractionator.

Owners; development

Discovery consists of Discovery Producer Services LLC and its subsidiary, Discovery Gas Transmission LLC.

Discovery Producer Services is the gathering, processing, and fractionation company not regulated by the U.S. Federal Energy Regulatory Commission (FERC); Discovery Gas Transmission is an FERC-regulated gas-transmission company.

Discovery Producer Services, which owns 100% of the Discovery Gas Transmission subsidiary, is in turn owned by the Williams Cos. Inc., Tulsa (50%), Texaco Exploration & Production, Houston (33.3%), and British Borneo Exploration, Houston (16.7%). Texaco, through its subsidiary Bridgeline Gas Distribution LLC, operates the system.

Planning for Discovery started in early 1996 with the formation of a project team within Texaco. By late 1996, Mapco (which was acquired by Williams in March 1998) began negotiations with Texaco, resulting in the formation of the Discovery LLC on Feb. 1, 1997. The initial ownership was 50-50 between Mapco and Texaco. British Borneo joined the group in April 1998 by purchasing 33% of Texaco's interest.

Initial design of the system began in mid-1996 with Project Consulting Services, New Orleans, performing the engineering and design of the pipeline systems, and M&H Enterprises, Houston, handling the engineering and design of the slug catcher. Black & Veatch-Pritchard, Kansas City, began work on the processing and fractionation plants.

Initial agreements named Bridgeline as project manager with oversight and control from Discovery. The construction process involved representatives from owner companies throughout.

The entire Discovery project is a complex interaction of pipeline and facility assets (Fig. 2 [186,167 bytes]), taking raw gas and condensate from offshore platforms and redelivering specification residue gas, stabilized condensate, and specification NGL products.

System start-up has occurred in stages:

Gas began flowing in the main line from offshore producers in late December 1997.
NGL production from the Phase I system at Larose began in February 1998.
Stabilized condensate production began in April 1998.
NGL from the Phase II cryogenic train started in August 1998.
Specification products from the fractionator began in September.

The goal was to allow volumes to flow from offshore as they became available.

Pipeline

Discovery begins with gas flowing from offshore production through electronic flow measurement and into the 30-in. pipeline. Electronic flow measurement transmits real-time flow and pressure information to Bridgeline's supervisory control and data acquisition (scada) system in St. Rose, La.

Producers can access information about volumes flowing from their platforms via the Internet. Discovery operates and maintains all custody-transfer equipment.

Gas from the offshore platforms free-flows to the Larose processing plant along with any injected and retrograde condensate. The system is currently permitted for a 1,440 psig maximum allowable operation pressure with the FERC but has the ability to operate up to 1,850 psig.

There are two valve sites on the main line system, one at the shoreline 39 miles south of Larose and another 6 miles south of Larose. The first valve site also serves as the emergency shutdown valve to protect the onshore system from overpressure.

Five laterals deliver production into the 30-in. main line:

11 miles of 20 in. from Grand Isle South (GIS) 115
26 miles of 18 in. from South Timbalier (ST) 200
11 miles of 12 in. from South Timbalier 37
13 miles of 12 in. from Grand Isle South 104
20 miles of 8 in. from Ewing Bank (EB) 921 that is connected to the Grand Isle South 115 lateral.

These lines, along with a planned 31-mile, 16-in. lateral from Green Canyon 254 (3,200 ft water depth) to the end of the main line at Ewing Bank 873, complete Discovery's offshore pipeline network (Fig. 1).

The offshore pipeline network contains a variety of wall thicknesses based upon operating pressure and lay stress requirements. The 30-in. main line is all API 5L X-65 DSAW (double submerged-arc welded), 0.562-in. to 0.812-in. W.T., coated with 16 mils of fusion-bonded epoxy (FBE) and 2.25 in. to 3.25 in. of concrete coating.

The 20-in. lateral to GIS 115 is 0.428-in. W.T., API 5L X-65 ERW with FBE and 1.75-in. of concrete. The 18 in. to ST 200 is 0.406-in. W.T., API 5L X-65 ERW with FBE and 2 in. of concrete.

The 12-in. line from ST 37 is 0.625-in. W.T., API 5L X-52 ERW with FBE. The 12 in. from GIS 104 is 0.375-in. W.T., API 5L X-46 ERW with FBE and 1.25-in. concrete coating. And the 8 in. from EB 921 to GIS 115 is 0.406-in. W.T., API 5L X-52 ERW with FBE.

The onshore incoming main line is all 0.562-in. W.T., API 5L X-65 DSAW with FBE and 2.25 in. of concrete.

In water depths of 200 ft or less, the pipeline was buried with an hydraulic jetting machine. It was towed on the ocean floor along the pipeline route, removing soil and other material under the pipeline to obtain a minimum of 3 ft of cover over it.

In water depths greater than 200 ft, the pipeline was laid on the ocean floor, with no trenching or backfill required.

Pig-launching facilities are on all platforms with receipt into the main line. Pigs (30 in.) launched at Ewing Bank 873 arrive at Larose. External corrosion control for the offshore system derives from cast-in-place sacrificial magnesium anodes.

To accommodate future expansion, 15 joints of pipe (not concrete-coated) are at various locations offshore to allow for hot-tap connections. Also installed were 11 valved side taps to allow for future tie-ins.

Processing

A 7,500-bbl slug catcher at Larose separates condensate for stabilizing. The slug catcher consists of 48-in. OD, 1.08-in. W.T. pipe.

In addition, a 24-in. line parallels the final 6 miles of incoming 30-in. main line. When pigging operations bring in more condensate than the slug catcher can handle, gas can be diverted into the 24-in. line, leaving the last 6 miles of 30-in. line as temporary condensate storage.

The condensate stabilizer is a classic design of eight 48-in. OD, 460-ft tubes. Each tube is 1.06-in. W.T., API 5L X-65 DSAW pipe fabricated on site. External corrosion protection comes from a three-part, field-applied epoxy coating.

The condensate stabilizer at Larose can process 3,500 b/d. Condensate leaving Larose is measured in a U.S. Department of Interior Minerals Management Service-approved, accounting-grade measurement skid, then pumped into an 18-in. line to Equilon Pipeline Co. LLC.

Gas leaving the slug catcher can either enter the processing plant or be measured and bypassed directly to residue pipelines. Gas entering the plant is measured then dehydrated in a common four-tower system. Design inlet pressure at the plant is 1,000 psig (Fig. 3 [102,926 bytes]).

The Larose gas-processing plant consists of two parallel 300-MMcfd cryogenic turboexpander processing trains (Fig. 4). Designed for maximum flexibility, each train can recover ethane in a 0-90% range without significant loss in 99%+ propane recovery.

In full ethane-recovery mode, the 24-tray demethanizer is designed to operate at 310 psig with an overhead temperature of -150° F.

Each train has frontend refrigeration and was designed for 3-gpm inlet gas. Together, both trains can recover up to 42,000 b/d of NGL.

Offshore receipt specifications limit H2S to 0.25 gr/100 std. cu ft and CO₂ to 1 mole %, which eliminates the need for product treating.

Three 50% 1,200 hp Superior-driven, Cooper four-throw, single-stage reciprocating compressors provide refrigeration for the process. Mafi-Trench turboexpander/compressors are configured for post-boost operation.

The two demethanizer towers, erected by crane, were the heaviest items lifted during construction on the Discovery system. Each pressure vessel weighs 182,000 lb, including insulation, and is 77 ft in height. The diameter varies from 10 ft at the top to 7 ft at the bottom.

After liquid extraction, the residue gas commingles into three parallel 15,000-hp Solar Mars-driven Elliot centrifugal recompressors. Leaving the plant at a maximum pressure of 1,200 psig, residue gas flows to Texaco's Bridgeline System via 0.5 mile of 30-in. line or to Texas Eastern Transmission Co. through 5 miles of new 20-in. line.

To satisfy producer needs for early gas flow, one of the frontend refrigeration systems was modified to accommodate glycol injection and was brought online early as a standalone plant.

Along with the refrigeration system, all of the associated utility systems (fuel, flare, cooling water, instrument air, etc.) were placed into operation concurrently. Heat for mole-sieve regeneration is from a direct-fired heater.

Plant cooling is provided by a 33,000 gpm once-through system with water being taken from the adjacent Grand Bayou Blue, filtered for solids, pumped through shell-and-tube exchangers, and returned to the Bayou.

Fire protection is provided by one 3,000-gpm, electric-driven pump with a parallel 3,000-gpm diesel-driven system.

Process control at Larose is by a Foxboro Distributed Control System. Over 700 loops control both processing trains and the common support systems.

Also of note, the Larose facility rests on more than 9,100 cu yd of concrete. More than 2,500 pilings, varying in size from 60 ft to 80 ft, were driven into the ground to strengthen the foundation.

The soil in this region is so unstable that test pilings sank into the ground more than 8 ft just from their own weight.

Fractionation

Demethanized NGL is pumped from Larose to Discovery's Paradis fractionator in 22 miles of 14 and 10-in. pipeline. Once the product arrives at Paradis, it commingles with liquids from Bridgeline's three on-site processing trains and enters a 30,000-gal front end surge tank before being pumped to the de-ethanizer.

The Paradis fractionator originally operated in conjunction with the former Bridgeline lean-oil plant on site (Fig. 5). The equipment was in use until the early 1990s when volumes had declined to less than the economical limit of operation.

After equipment ownership transferred to Discovery, extensive mechanical integrity tests on the equipment resulted in re-use of only the towers, storage tanks, and major pieces of nonrotating equipment.

Paradis fractionation is a standard four-tower train, producing purity ethane (18,000 b/d) along with specification propane (10,900 b/d), iso-butane (3,650 b/d), normal butane (4,350 b/d), and natural gasoline (5,100 b/d).

Amine treating of the ethane vapor controls CO₂. The amine off-gas passes through a Sulfatreet drum for removal of any trace H2S (Fig. 6 [154,607 bytes]).

The dual-diameter 78-in. (top)/156-in. (base) x 79-ft deethanizer, 114-in. x 93-ft depropanizer, 150-in. x 134-ft de-isobutanizer, and 72 in. x 95-ft debutanizer were existing from the original plant. The towers were thoroughly inspected, cleaned, and received new trays as part of the project.

Refrigeration for the process comes from three 50%, 1,650-hp Caterpillar-driven Cooper reciprocating compressors. Cooling is by a 21,500-gpm recirculating cooling-water tower system. The 166-MMBTU/hr heat medium system supplies all heat requirements for the fractionator.

The Discovery fractionator and Bridgeline's existing gas-processing trains share many of the support and utility systems at Paradis. Items such as fuel, electricity, instrument air, flare, firewater, and the distributed control system (nearly 500 loops) come under a master shared-services agreement.

Producers receiving products from the fractionator have a variety of transportation options. Ethane is limited to pipeline; propane, iso-butane, and normal butane can leave by pipeline, truck, or rail; and natural gasoline by pipeline and truck.

Producers can store on site approximately 2 days, except for ethane.

Construction

J. Ray McDermott, Houston, performed the offshore pipelay using its DB-28 S-lay barge (Fig. 7). Work on the offshore section began on Mar. 27, 1997, with receipt of the FERC permit. Overall good weather, except for Hurricane Danny, allowed for construction to be completed on July 26, 1997.

Global Industries, Houston, also was involved offshore with the lay of the South Timbalier 37 lateral by the Cherokee barge. Cal Dive, Houston, performed much of the platform riser installation with the Uncle John and Witch Queen dynamically positioned vessels.

Laine Construction Co., Lafayette, La., laid the onshore 30 and 24-in. lines from the 15-ft limit to Larose between Apr. 3 and Dec. 17, 1997. Completion of this portion allowed the initial gas flow on Dec. 25, 1997.

Additional onshore construction was awarded to Sunland Construction for the 20-in. residue line; to Texas Eastern and to IMTC, Westlake, La., for the 10-in. LPG line; and to Baker Pipeline, Houma, La., for rehabilitation of the existing 14-in. portion.

Installation of the slug catcher at Larose was by WHC, Lafayette, La.

Black & Veatch-Pritchard, Kansas City, built both the Larose and Paradis plants. Construction began on Feb. 23, 1997, at Larose and on Jan. 14, 1997, at Paradis. While Pritchard was the direct-hire general contractor, the company utilized subcontractors for selected portions of the construction.

Progress at Larose was affected by an on-site archeological find. After securing the area and receiving FERC approval of a mitigation plan, remains of approximately 30 Native Americans were discovered. These appear to be more than 400 years old and will be reburied near the site.

Construction of the office/shop/ control building was delayed and a separate motor-control center was erected to accommodate the archeological site.

The Authors

Kevin C. Bodenhamer is director of engineering and construction for Williams Cos.' energy services business, Tulsa. During the Discovery project, he served as general manager for Mapco. He holds a BS in civil engineering from the University of Missouri-Rolla and is a registered professional engineer in Alaska, Kansas, Oklahoma, and Texas.

John P. Laguens is Discovery project director for Bridgeline Gas Distribution LLC, New Orleans. He holds a BS in mechanical engineering from Louisiana State University, an MBA from Loyola University of New Orleans, and is a registered professional engineer in Louisiana.