INDUSTRY PRESSES PROGRAM TO BOOST OIL AND GAS PRODUCTION IN NIGERIA

Roger Vielvoye
International Editor

Nigeria, West Africa's biggest oil producer, has started a major spending program to boost its oil flow in the mid-1990s.

The goal is to take advantage of an expected increase in demand for oil from members of the Organization of Petroleum Exporting Countries.

Money also is being plowed into gas development. Nigeria's biggest single investment in the early 1990s aims to turn the country into West Africa's first gas exporter.

By yearend 1990 the final go-ahead is expected for a $2.5 billion liquefied natural gas project at Bonny, Rivers State, to ship gas to Europe and the U.S.

Nigerian productive capacity is 1.8-1.9 million b/d. Production, reined by an OPEC quota, averaged 1.601 million b/d during the first 11 months of last year, up 16% from the same period of 1988.

By the mid-1990s the government wants to raise sustainable capacity to 2.4-2.5 million b/d. Foreign operators, which run the Nigerian industry in partnership with Nigerian National Oil Corp. (NNPC), believe there are enough resources to meet that target.

With Nigeria's light, low sulfur crude highly prized by refiners in the U.S. -and to a lesser extent in Europe-operators are prepared to ensure that money is available for increased exploration and production.

BIGGEST PROGRAM

Nigeria's biggest producer, a combine made up largely of Shell Petroleum Development Co. of Nigeria Ltd. and NNPC, plans to more than double capital spending in 1988-93.

This will involve an increase of more than 150% in exploration and appraisal drilling, start of the country's first deep drilling program, upgrading current production facilities, placing more fields on stream, and Nigeria's first heavy oil production.

The combine, which made a major hike in spending last year, has budgeted $1 billion this year. Further increases are scheduled until spending reaches a peak of more than $1.2 billion in 1993.

Big investments also are under way by the Mobil Corp.-NNPC partnership. With three major offshore projects in progress, the combine plans an offshore wildcat program that will include evaluation of deeper plays.

Mobil produces about 200,000 b/d in Nigeria, mainly offshore.

Nigeria's other major producers are Chevron Nigeria, Texaco Nigeria, Elf, and Agip. Ashland Nigeria and Pan Ocean (Nigeria) have much smaller producing operations.

For all foreign operators, the big problem for the 1990s lies in the ability of NNPC to fund its majority interest in new investment programs. Even at the far lower investment levels of the late 1980s, NNPC usually met cash calls with crude oil rather than currency.

The government has reorganized NNPC to give the company a more commercial view of life. It also approved NNPC's sale of 20% of its interest in the Shell-NNPC partnership.

Shell took an additional 10%, increasing its interest to 30%. Units of Ste. Nationale Elf Aquitaine and Agip SpA took 5% each. The deal netted the state about $2 billion and reduced its commitment to fund new investment planned by the joint venture during the next 5 years.

RECOVERY PLANS

Nigeria probably felt the jolt more than any other OPEC member from the slump in oil demand in the 1980s, followed by the 1986 nosedive in oil prices.

Throughout the second part of the 1970s Nigerian production averaged more than 2 million b/d, peaking at 2.3 million b/d in 1979. Exports crumbled in the early 1980s to a low of a little more than 1.2 million b/d in 1983.

Nigeria's revenues from crude oil exports peaked at a little less than $25 million in 1980 and slumped to less than $7 billion/year between 1986 and the start of last year, when improved world prices boosted government take to about $8 billion/year.

As production collapsed in the 1980s, the Nigerian industry stagnated. With so many wells shut in, there was little requirement for exploration and development. Operators also were reluctant to invest under terms of an agreement for calculating profits.

Brian Lavers, chairman and managing director of Shell Nigeria, said the Shell combine's operation was mostly care and maintenance.

Nigeria is a land of small reservoirs. Productive capacity can decline very quickly. During this period of stagnation the combine's capacity dipped from its peak of 1.4 million b/d to well below 1 million b/d. Production fell to as low as 600,000-700,000 b/d.

The turnaround in the Nigerian industry started in 1986 when foreign companies and the government signed a new operating agreement. Operators were guaranteed a profit of $2/bbl in return for increased work programs to restore production levels.

The Shell partnership is working toward a target of 1. 1 million b/d productive capacity by 1993-94, which would enable production to rise to 1 million b/d by then. But the group also has contingency plans to boost capacity to 1.3 million b/d in response to any request for higher production levels from the government.

During second half 1989 Nigeria participated in the OPEC production free-for-all. Production was pushed close to its technical potential of 1.8-1.9 million b/d with the Shell combine producing as much as 980,000 b/d. Those levels could not be sustained very long.

SPENDING PLANS

The scale of the Shell combine's spending plans was outlined by David Thomson, Shell Nigeria's general manager, commercial.

Spending, which climbed to $924 million last year from slightly more than $550 million in 1988, is expected to be $1.012 billion this year.

The rise in spending will continue into the early 1990s.

New investment is centered on increased exploration and upgraded and new facilities to boost oil flow. But the group continues to make substantial payments to the government as part of the renegotiation of its leases, which run for a further 19-29 years.

E.M. Daukoru, Shell Nigeria's exploration manager, outlined the transformation of Nigeria's exploration scene.

In 1981-82 only two wildcats were drilled. In 1986, the year in which the new deal on profits and work programs was announced, the number rose to seven as part of a 20 well exploration and appraisal program.

The 1990 exploration and appraisal program is expected to include 40 wells. The high level of drilling will continue through the early 1990s with a peak of 50-55 wells in 1993 and 1994.

The number of rigs working for Shell has risen to 22 from 10 in 1988, and more will be added during the next few years.

The increase in drilling is yielding results. The company discovered 511 million bbl of oil in 1988 and 475 million bbl in 1989.

Daukoru said the biggest aid to Nigerian exploration has been wide scale introduction of three dimensional seismic. After several limited programs in the early and mid-1980s, 3D crews began to appear regularly in 1986.

Total 3D use by all operators was about 20 party months in 1986.

NNPC's leases cover a variety of conditions from land to seasonal swamp, swamplands in the Niger Delta, shallow estuaries, and deeper acreage offshore.

Daukoru said the delta is still the main area of interest, but there is potential offshore in 650-1,300 ft of water. He reckons there are 300 undrilled prospects on the Shell combine's acreage, including 50 undrilled very deep prospects.

The first deep well could be started later this year or in 1991 once rigs with enough depth capacity are available.

Most wildcats are drilled to about 14,000 ft. The exploration department plans to probe deep, high pressure prospects at or below 18,000 ft.

Initially Shell is acquiring a swamp barge with capacity to handle these depths and pressures but will need a large land rig and an offshore rig to complete the deep well program.

The current exploration program has produced finds of 10-100 million bbl, but Lavers said the deep prospects present the best chance of finding more substantial reservoirs.

Shell has formed divisions east and west of the Niger River, and both will undertake deep drilling.

PRODUCTION PLANS

The Shell combine has an extensive network of pipelines through the eastern and western divisions. Most of the spending in this sector is to tie in small fields.

Most of the new flow stations will handle 10,00030,000 b/d, but larger units will be built. For example, Tunu, to start up in 1992 in the western division, will have a capacity of 60,000 b/d.

Offshore, Shell's western division will develop EA field, expected to produce about 30,000 b/d of 30 gravity crude by 1993.

The combine is also introducing gas lift more widely and building more facilities to handle associated gas.

Improvements also will be made to terminal and transportation facilities, including a major extension of storage and treatment facilities at Forcados terminal that will involve jacking up existing tankage and installing new foundations.

The most ambitious production project the combine is undertaking is a condensate soak scheme designed to extract heavy, viscous crude from 700 million bbl Sapale field in the Niger Delta.

Shell plans to inject as much as 8,000 b/d of condensate into part of the heavy oil reservoir through four closely spaced wells. The condensate should mix with the heavy crude in the reservoir, reducing viscosity and making production possible for the first time.

Condensate will be delivered from a nearby gas plant that lacks a liquids transportation system. With condensate readily available, the injection process looked more viable than steam injection.

If the four well pilot is a success, condensate soak could be extended to the rest of the field.

Outside the delta, NNPC is investigating possible pilot steam injection projects on even more viscous crude deposits.

GAS DEVELOPMENTS

Shell describes Nigeria as a major gas province.

Official recoverable gas reserves are put at 87 tcf, but the potential is enormous. It should be possible to boost this figure to well over 100 tcf with relatively little additional drilling.

Most licensed acreage is gas prone. Even though companies have tended to avoid exploration in areas of known gas potential, they are still finding more natural gas than oil.

The domestic gas market has started to develop, and the LNG project's first phase has raised hopes that in the 1990s gas will displace a small percentage of oil products from the local market and a substantial export business will emerge.

Developing Nigeria's gas resources has been a long and frustrating business.

Shell started to develop a market in the delta, but prices were poor and did not cover costs. However, the opening of the 220 mile Escravos to Lagos pipeline has improved prospects for increasing gas sales.

David Balogan, who heads Shell's domestic gas unit, says there is a need for greater infrastructure.

Industry in the northern part of the country wants gas.

The cost of an 18-24 in. pipeline to the northern city of Kaduna would be about $500 million. Domestic gas prices could not justify investment on this scale, and there are doubts the government has the resources to subsidize the project.

Nigeria is also assessing gas exports to other West African countries. There are outline plans for a pipeline to Nigeria's western neighbors, where gas could play a part in slowing deforestation of West Africa for firewood. A shortage of funds ensures this will be a long term project.

LNG PROSPECTS

Nigeria has been trying to export gas to Europe since the 1960s. It wanted to be an LNG pioneer alongside Algeria.

Because previous projects have fallen victim to financing and political problems, the reality is that Nigeria will be an LNG latecomer.

The current project has gained more momentum than any of its predecessors and looks set to get the final financial go-ahead later this year.

Preliminary civil engineering work has started on a site adjoining the Bonny crude oil export terminal, and the population of a local village is about to be relocated.

Nigeria LNG Ltd.'s two train, 4.5 million metric ton/ year project, including six LNG tankers, will cost $2.5 billion, making it the cheapest LNG project anywhere in the world. Shareholders in the project are NNPC 60%, Shell Gas BY 20%, and Agip International BV and Cleag Ltd. (Elf) 10% each.

Shell, technical adviser to Nigeria LNG, said 20% has been saved on project costs.

The liquefaction trains, using the Technip-Snamprogetti Tealarc process, are expected to cost $1.56 billion. A major step forward in the design is the use of a single, large gas turbine driver for the main liquefaction cycle.

Preliminary sales agreements have been signed with Ruhrgas and Thyssengas of West Germany, Enagas of Spain, SNAM of Italy, and Gaz de France. Potential U.S. customers - Columbia Gas System Inc. and Distrigas - are expected to take 45% of the output.

Shell expects to reach sales agreements with U.S. customers in the first quarter and with the Europeans shortly afterwards.

U.S. buyers will need to sign first because more time is needed to push contracts through regulatory agencies. European partners have much more freedom of action over imports.

LNG ECONOMICS

Lavers expects 60-70% of the capital costs to be financed through loans to be negotiated in Europe and the U.S. by a team being set up in London.

If the financing package is in place by yearend 1990, Nigeria LNG will be able to award the main construction contract in 1991 and start deliveries in 1995.

The export project will require 707 MMcfd of feedstock gas, 53.33% of which will be supplied by the Shell combine from Soku and Bomu fields and the rest equally by Agip-Phillips-NNPC's Oshi and Idu fields and Elf-NNPC's Ubeta, Obagi, and Ibewa fields (see map, OGJ, Dec. 14, 1987, p. 28).

One project strength is access to cheap shipping. Before the present upturn in the LNG business Shell acquired options on five laid up LNG vessels around the world.

One of the vessels, Gamma, was one of three on time charter to Shell from the U.S. company Argent, which had acquired them from the U.S. Maritime Administration.

Attempts are being made in the U.S. courts to block the sale of the three vessels to Argent. Shell said loss of one of the vessels would not destroy project economics.

Through Shell, the five vessel fleet has been acquired at a cost of about $200 million, the equivalent of one newly built vessel at present costs. Shell says the transportation economics are robust enough to withstand construction of two new vessels rather than just one.

MOBIL PROJECTS

Mobil Producing Nigeria, which has liquids capacity of about 250,000 b/d from its offshore concessions, is involved in three development projects.

The first platform on the 850 million bbl Edop field, installed in 1987, holds five wells producing about 40,000 b/d.

Mobil has let construction contracts for a production platform with a capacity of as much as 250,000 b/d and a 24 in. pipeline to the shore to start up in 1991.

Full field development will require 36 wells from six platforms. More wells will be drilled and platforms installed as needed, depending on oil demand.

Mobil also is responsible for Nigeria's biggest offshore gas/condensate project. Oso field, in 50 ft of water 35 miles southwest of the company's onshore terminal, holds reserves of 3 tcf of gas and 445 million bbl of condensate.

Development requires 21 wells, eight offshore platforms, and 120 miles of pipelines for condensate transportation and low pressure gas gathering.

An offshore terminal will be required to export 100,000 b/d of condensate expected from the project. Upon completion, Oso also will produce about 300 MMcfd of high pressure gas, which will be combined with 200 MMcfd of low pressure gas from Mobil's other fields and reinjected into the Oso reservoir. The project aims to ensure 100% utilization of Mobil's associated gas.

The third project will produce about 52,000 b/d from Iyak field in 1993. Mobil will drill 14 wells and install two platforms in the 146 million bbl field. First liquids are expected in 1991.

Mobil plans to increase its Nigerian productive capacity by an additional 100,000 b/d during the next 5 years.

Last year the company almost trebled its seismic activity, shooting 6,289 line-miles of 2D and 3D surveys. it drilled three successful wildcats. It currently has two active rigs on its concession.

Mobil also plans a wildcat drilling program for the next 3 years, a substantial part of which will target deeper plays at 10,000-15,000 ft.

CHEVRON PROGRAM

The biggest of the other operators in Nigeria is the Chevron-NNPC joint venture. Chevron inherited a 3.5 million acre concession through its acquisition of Gulf Oil Corp.

The joint venture, with a productive capacity of about 300,000 b/d, produces about 270,000 b/d onshore and offshore.

Chevron, saluting the changed investment climate, is looking at expansion projects that would sustain production.

Since the increase in operators' margins in 1986, Chevron's exploration activity has averaged seven to nine wells/ year and 10-19 seismic crew months/year.

Activity will remain at 1990 levels.

Moves also are under way to sell associated gas used for fuel. Chevron is studying a project to gather flared gas for LPG extraction and deliver the residue into the domestic distribution network.

TEXACO, ELF

Chevron also is a partner with Texaco in two offshore concessions that produce about 60,000 b/d.

Texaco Chairman Alfred DeCrane Jr. said exploration is at a relatively low level. Texaco drilled a dry hole in the outer offshore trend last December and plans to spud another offshore wildcat before yearend.

Elf Nigeria, a major West African operator, has placed great emphasis on exploration and development in Nigeria.

The company acquired new acreage offshore, became a partner in the LNG operation, and finally bought a 5% stake in the Shell combine's concession.

The company's onshore fields produce about 95,000 b/d. Basic engineering has started for development of four fields - Afia, Odudu, Ime, and Edikan - on offshore permit OPL95.

Onshore, Elf is developing Olo field and connecting facilities to the transportation network.

It continues a drilling program on its OML 57 and 58 permits.

Gas for the Bonny LNG project will not be required for several years, but preliminary studies have started on developing Ibewa field, which will supply Elf's initial share of the feedstock.

Elf's exploration program is aimed at maintaining production levels. The company requires two rigs/year offshore and about 1.5 rigs/year onshore.