Nigeria's Escravos gas project starts up

Marizu Nwokoma
Chevron Nigeria Ltd.
Lekki, Nigeria

Nigeria's Escravos gas project, Delta state, officially began late last year. The project-6,650 b/d of LPG and 1,740 b/d of condensate from 165 MMscfd of gas-is the first attempt to rid Nigeria of incessant flares that have lit the Delta skies.

A joint venture of Chevron Nigeria Ltd. and Nigerian National Petroleum Corp. (NNPC), the project began processing gas in November 1997.

NNPC and Chevron are joint partners in the exploration of oil and utilization of the country's resources. NNPC owns 60% of the project, Chevron, the operator, 40%.

The Escravos gas project represents a milestone in the development of Nigeria's hydrocarbon resources, of which an estimated 110 tcf are natural gas and 17 tcf are in the NNPC/Chevron joint-venture acreage in the Escravos area.

Operator Chevron Nigeria Ltd. believes that the Escravos project will enable the joint venture to utilize a significant portion of the gas reserves, thus reducing gas flaring.

Chevron has been in Nigeria since December 1961 and has about 29 producing oil fields. Total oil-production rate is approximately 450,000 b/d.

Project roots

Often, the major stumbling block to gas utilization has been disposal of residue gas from processing: It makes no sense to build a gas plant and end up flaring much of the gas.

The problem has been that Nigeria is a growing nation that still presents opportunities for the utilization of gas. The major end user of the gas is the government-owned Nigerian National Electric Power Authority (NEPA).

As a result, about 75-80% of the associated gas is still flared, representing a loss of economic and environmental benefits, while only 25% is utilized as fuel gas in the field or re-injected.

In absolute terms, about 2 bcf of associated gas are estimated to be flared. Table 1 [39,626 bytes] shows Nigeria's utilization figures from 1989 to 1995.

The success of this project was based, in part, on the following:

Creation of incentives by the Nigerian government as set out in the Associated Gas Utilization Fiscal Incentives, under the umbrella of the Nigerian National Gas Policy of March 1995.
Establishment of an agreement with Nigerian Gas Co., the pipeline company, to receive and deliver to markets the residue or lean gas from the plant.

In anticipation of the gas policy and its incentives, Chevron Nigeria Ltd. management approved the project in January 1995 with a target start-up date of May 1997.

Okan, Mefa fields

The project consists of an offshore gas gathering and compression platform (GGCP), a gas plant onshore, and a floating storage and offloading vessel (FSO).

The primary source is associated gas from the Okan and Mefa fields in Oil Mining Lease 49, Delta region. Fig. 1 [128,378 bytes] shows Chevron Nigeria Ltd.'s full development plan for utilization of Nigeria's gas resources.

In many respects, the project differs from other oil and gas projects in Nigeria.

It is unique in that the project features an FSO, with a capacity of 54,000 cu m (340,000 bbl), that would not be dry-docked for the next 20 years. It will also be the world's first installation of a purpose-built, LPG-storage vessel, fabricated from steel.

The project is also unique in that the process features a highly integrated control system that is geared to maximize plant efficiency. What started as a 165-MMscfd project grew to include a Phase 2 which will see plant capacity up to 300 MMscfd.

Fig. 2 [117,191 bytes] shows Phase 1 development. Accompanying boxes (below) show the project schedule and a list of major contractors.

Process design

The GGCP is located about 8 km offshore Escravos in 6 m of water. It consists of gas/oil/water separation, gas compression, and glycol dehydration.

The GGCP performs initial liquid removal and compresses the gas for transmission to the gas plant onshore. There are three compressor trains consisting of 14,000-hp Kawasaki Heavy Industries compressors, each driven by Solar Mars 100 gas turbines.

The gas is compressed from about 4-11 barg to 66 barg in three stages of compression. The glycol dehydration system utilizes triethlyene glycol (TEG) to achieve dehydration of the gas to a dew point of 4° C.

Fig. 3 [81,761 bytes] shows the offshore complex; Fig. 4 [77,992 bytes], the simplified flow for the offshore platform.

The onshore gas plant is designed to recover 93% of the propane and 100% of the butanes in the feed, which results in a production of 42 cu m/hr of LPG that is sent through a 45-km, 8-in. pipeline to the FSO.

After LPG extraction, the remaining 3.67 MMscmd (130 MMscfd) of lean gas is compressed and delivered into the 16-in. gas pipeline to the Nigerian Gas Co. Condensate (C₅+) is sent through a 4-in. pipeline to be blended with oil production at the Escravos storage terminal.

Fig. 5 [100,186 bytes] and Fig. 6 [276,721 bytes]show the overall plant and simplified flow.

Here are the key sections in the plant:

Separation, filtration, and dehydration. This unit consists of a slug catcher, filter separator, two gas molecular-sieve vessels, and a solids filter. Initial plant separation is achieved in the slug catcher and filter separator. The mole sieves dry the gas to a water-content of <1 ppm and have a nonrecovery regeneration gas-fired heater. The second phase of the project would include in this section another filter separator and mole sieve, and there is also provision for the installation of an H₂S-removal package and mercury-removal unit.

Cooling and turboexpansion. This unit consists of a feed cooler, turboexpander, and a Joule Thomson (JT) valve. The gas from the mole-sieve bed is cooled through the feed cooler to -35° C. and further to -85° C. by the turboexpander to ensure good recovery rates.
The JT valve is used during start-up and turboexpander shutdown. The reduction in gas pressure in the turboexpander provides the power that drives a recompressor on the opposite end of the drive shaft.

LPG processing. This consists of a de-ethanizer and a debutanizer. The de-ethanizer is a 30-tray distillation column where the sales gas (C₁ and C₂) is separated and the heavier hydrocarbons, in liquid form, flow to the debutanizer.
The debutanizer is a 34-tray distillation column, and the vaporized hydrocarbon (LPG) is pumped at 47 cu m/hr from a reflux accumulator (after cooling) to four storage spheres of 1,130 cu m capacity each. LPG is pumped from the spheres to the FSO at 140 cu m/hr.

Sales-gas compression, transfer, and metering. The overhead gas from the de-ethanizer flows to the recompressor which utilizes the power generated by the turboexpander to compress the gas before dividing into two trains and going through two stages of compression.
The product is raised from 22 barg to 90 barg through two KHI compressors each driven by Solar Mars 100 turbines. The compressed gas is supplied at 85 barg through a 16-in. pipeline to NGC after metering in the plant.

Condensate stabilization and transfer. The gas plant has a condensate-stabilization unit consisting of two separators and a heater. Here entrained hydrocarbons separated in the slug catcher's filter separator are stabilized to recover all the light hydrocarbons (C₅+) that would be blended with the crude.

The overall plant (Fig. 7 [105,432 bytes]) is controlled by a Honeywell TDC 3000 distributed control system (DCS).

The FSO is positioned about 45 km offshore Escravos in about 30 m of water and will receive all LPG from the onshore gas plant. Export vessels will receive cargo from the FSO.

The vessel has a capacity of 54,000 cu m (340,000 bbl) and uses a single mooring system. Designed for 20 years without dry-docking, it has refrigeration units and a reclamation unit to liquefy LPG vapors.

Construction; start-up

Construction began in first quarter 1995 with a target completion date of February 1997 and then precommissioning.

To achieve this, field man-hours were aligned with the Escravos terminal work hours to accommodate the expected project commissioning date of May 1997. Construction of the onshore gas plant was completed with no lost-time accidents, an effort that exceeded 2.4 million man-hr.

Gas was introduced into the plant as scheduled, and the plant split into 17 systems for purging and commissioning and to ascertain that all the facilities were working properly. Shift operations started that day to make a 24-hr watch over the plant possible.

Challenges that have come with start-up have included cold-section flange leaks, electric-motor failures, logic reconfiguration as the mole-sieve regeneration and drying logic had to be changed after the first trial run.

A major retrofitting occurred with the hot oil and regeneration fired heaters. When it was discovered that they were oversized for the service, the regulators were resized to limit the heater duties. The ground flare burner tips were changed because they were providing a mix for the air and the waste gas.

On the compression platform, the dry gas seals in one of the compressors was changed because of damage that occurred during shipment of the modules.

The process engineers have remained informed of all the numerous changes that have occurred in the plant with the help of the Management of Change procedure of Chevron Nigeria Ltd. This has helped us not only to document our changes, but also to verify their engineering soundness with safety considerations.

LPG and condensate are now being made in the plant and stored in the storage spheres. This mode of production, the NGL mode, is being driven by its economic advantages for the simplified flow diagram).

The plant makes a profit of about $3 more per metric ton on NGL, compared to LPG delivery to Houston. On Sept. 30, 1997, the plant had its first shipment of NGL from the FSO to an export tanker on its way to Warren Petroleum's Galena Park, Tex., terminal.

The gas plant was commissioned Nov. 5, 1997.

Safety has been of paramount consideration during all the start-up processes and retrofitting and trouble solving.

Operations personnel have learned several start-up lessons while at the same time having to learn the idiosyncrasies and limitations of the plant equipment and control system.

Topmost on this list of lessons includes the proper use of a regeneration heater, and problems of contraction and expansion of pipe joints in cold services.

CORRECTION

An error appeared in the article, "UPGRADING BOTTOMS-1: Cleaner fuels shift refineries to increased resid hydroprocessing," by Lawrence Wisdom, Eric Peer, and Pierre Bonnifay (OGJ, Feb. 9, 1998, p. 58).

In Fig. 4 [61,362 bytes], the Asia and U.S. graphs should be reversed. The corrected figure is shown here.