David Thomas
Thomas & Associates
Hastings, England
Nigeria is often referred to as a gas province with some oil in it.
Nigeria produces a very high quality, light, sweet crude oil but with a large percentage of associated gas derived from a high gas-to-oil ratio. Official proved gas reserves, both associated and nonassociated, are 120 tcf. Proved and probable reserves are estimated as high as 300 tcf. Main gas pipeline infrastructure in the delta is shown in Fig. 1 (144152 bytes).
The internal market for gas has only begun to develop since the 1980s, and as a result approximately 77% of associated gas production is flared.
Domestic gas consumption is currently approximately 700 MMcfd and is projected to have a medium term potential of 1.450 bcfd. The Bonny LNG export scheme would absorb another 750 MMcfd.
Lagos and nearby towns in western Nigeria have since 1988 been connected to a 220 mile gas pipeline from the main producing areas. This is expected to accelerate the per annum growth in gas consumption. A number of industries have converted to gas as an energy source since completion of the pipeline.
DEVELOPMENT OVERVIEW
As soon as the Niger delta was established as a hydrocarbon province, attention turned to what to do with the large volumes of discovered gas.
Canadian Industrial Gas Ltd. was commissioned in 1965 to report on this. Its main recommendation was to establish gas- based industries in the Port Harcourt area. It found that a pipeline from the Ughelli area to Lagos could be economic given appropriate circumstances.
The economics of the scheme depended predominantly on providing gas for a Lagos power station. It was believed that a pipeline spur could serve Benin City and Lagos and, by 1972, these cities could be taking 13 MMcfd and 32 MMcfd, respectively.
However, building a gas market took much longer than was ever envisaged by the planners. The first gas scheme involved a small pipeline from Imo River field, which supplied the nearby small industrial complex at Aba town in Imo State.
Subsequent developments before the 1980s involved state sponsored schemes that used gas for electricity generation or as feedstock to fertilizer plants.
GAS MARKETS
The domestic gas market in Nigeria was only created during the last decade.
A good gas pipeline infrastructure is now in place in the onshore delta region. With the completion of the gas pipeline to Egbin, just outside Lagos, the main future domestic market, the densely populated west of the country is in reach of the gas producer and the infrastructure is being expanded.
While the supply side of the market equation is rapidly being solved, market demand is distorted by subsidies on electricity tariffs and petroleum products. This has inevitably resulted in a reduced role for gas in Nigeria's energy mix.
GAS FLARING
Associated gas production during 1994 was 2.3-3.2 bcfd.
The cost of gathering, treating, and compressing associated gas at the wellhead or production platform is high, and as already briefly discussed the local gas market is immature. Consequently the major producing companies have been flaring the gas. The Nigerian government has eschewed market related measures to solve this problem and has favored fines and penalties for flaring.
In 1979, the federal government ordered the cessation of all gas flaring by Jan. 1, 1984. This decree was amended in 1985 to create a penalty of 50 kobos/Mcf (100 kobo = I naira, and 80 naira -$1 U.S.).
The percentage of flared gas has declined somewhat over time (Table 1)(13851 bytes). A rise in oil production from 1985-90 increased the volume flared.
Unlike many other petroleum provinces in the world, Nigerian nonassociated gas is potentially cheaper to develop than associated gas. Associated gas accumulations are widely spread throughout the delta. Gas is produced on land and offshore from nearly 170 fields, and the large capital expenditure required for exploitation is difficult to justify even with a realistic market price for gas.
There are few large accumulations of gas in the delta compared to major gas regions such as Iran, Saudi Arabia, or the Former Soviet Union.
Individual field statistics for gas reserves are highly unreliable, but the largest nonassociated field in the basin does not exceed 6 tcf, while associated gas accumulations are much smaller. This will mean that gas production costs will be compar- atively high. Further, as with oil fields, Niger delta gas wells are of low productivity.
Much of the associated gas occurs in the swamps of the delta, and this will increase development costs, especially for pipelaying (estimated to cost three to four times that for dry, fiat, savannah country).
GAS USE PROGRAMS
Following government directives, several gas utilization programs are being implemented.
An example is the NNPC/Chevron Escravos Gas Project. In Phase 1, approximately 165 MMcfd from existing production facilities in Okan and Mefa oil and gas fields off Escravos will be gathered and processed m a new onshore facility adjacent to the existing Escravos crude oil terminal. An estimated 6,000 b/d of LPG component (propane and butane); 12,000 b/d of oil from wells with high gas-oil ratios and condensates (pentanes-plus); and 130 MMcfd of lean dry gas (methane) will be marketed as offtake. Estimated cost of Phase 1 is $570 million with start-up planned for May 1997.
NNPC/Mobil is also planning to recover 350 million bbl of NGL from offshore Oso field in OML 70 (OGJ, Feb. 20, p. 30).
BONNY LNG SCHEME
The Bonny LNG scheme has a long history.
The idea of using Nigeria's large natural gas reserve base for export of LNG to Europe or the U.S. was first planned in 1966. British Gas Council (predecessor to British Gas plc) entered negotiations with Conch Methane Services Ltd., a Shell affiliate, to import 100 MMcfd of Nigerian natural gas into the U.K.
The discovery of gas in the U.K. North Sea southern gas basin led the Gas Council to withdraw from talks, which at the time were said to be deferred. Further discoveries in the U.K. continental shelf meant that talks never resumed.
Shell continued to be involved over the years, from just maintaining a watching brief to principal of proposed LNG capacity variation schemes. The Agip/Phillips/ Elf consortium began to develop competing plans based on gas discoveries they were making in the Niger delta. This scheme had an original planned location at Escravos but was changed to Bonny when feasibility studies concluded that construction costs at Escravos would be too high.
Once the Algerian LNG scheme got under way other market opportunities did not arrive quickly and the Bonny scheme made little progress in the early and mid-1970s. Nevertheless, Shell/BP signed an agreement with the government in October 1976 covering the construction of an 800 MMcfd plant and set up a company, Bonny LNG, to manage the project. In 1977 the Nigerian government accelerated the pace of development and made the fateful decision to amalgamate the projects. This had the effect of increasing the scale of the scheme, which required a larger market opening for gas imports in Europe and the U.S. Shell initially was appointed operator but resigned when a Phillips patented liquefaction process was adopted and the latter company took over in mid 1978.
The new scheme was based on a single gas liquefaction plant with a capacity of 1.6 bcfd. By 1980 the estimated cost of the project had mushroomed to $12-14 billion, of which $4 billion was attributed to the liquefaction plant. The plant, to have six trains and an estimated 20 year life, was to require a fleet of 16 vessels to transport the gas to Europe and the U.S. BP was still a shareholder in Bonny LNG albeit its other interests in the country had been nationalized in 1979.
NNPC and Phillips resigned from the scheme in 1981 due to budgetary constraints. Shell was later appointed operator. The remaining partners were unwilling to increase their interests in such a massive and marginally economic project, and in February 1982 Bonny LNG Ltd. was placed in liquidation.
REVIVED BONNY PROJECT
The Nigerian LNG project was revived in 1986 when a framework agreement was executed between the participants. The newer scheme, a scaled down version of its predecessor, is designed to ship 3 million metric tons/year of LNG and cost $4.5 billion.
In 1988, however, Shell announced it believed that at then prevailing prices for LNG, a $2.5 billion project delivering 4 million metric tons/year to West European buyers would be viable. A start-up date for 1995 was planned. The scheme was part of the Memorandum of Understanding signed in January 1987, and in 1989 Nigeria LNG Ltd. (NLNG) was formed to implement the project.
The MOU sought to establish common rates of return for gas supply, liquefaction, and transport, thereby giving no consortium member an incentive to be part of one project and not another. The participants in the LNG project are NNPC 49%, World Bank (International Finance Corp.) 11%, Shell Gas BV 20%, and Agip and Elf each 10%.
Shell is technical advisor (effectively operator) to Nigeria LNG Ltd. The company controls all aspects of the project from wellhead to delivery to ports in Europe. The company has seconded staff from shareholder companies and has its own personnel.
GAS RESERVE BASE
The project's reserve base is 10.5 tcf (Soku being the largest field with 4.4 tcf reserves) from NNPC/Shell's Soku and Bomu fields, which will contribute 53.33% of the gas required, with 23.33% each from NNPC/ Agip Oshi and Idu fields and NNPC/Elf Ubeta, Obagi, and Ibewa fields (Fig. 2)(159325 bytes).
The reserves from these fields committed over the initial planned production period of 20 years will be 4.55 tcf. The reserves, however, are adequate for a 40 year production life. (The shareholders agreement has a 35 year term, and the plant's economic life is expected to be 30 years.) The initial gas supply will be NNPC/Agip 175 MMcfd, NNPC/Elf 175 MMcfd, and NNPC/Shell 400 MMcfd.
All these fields are in the general locality of Bonny, and all are undeveloped nonassociated gas accumulations. Associated gas use would entail additional processing plants and increase development costs. Production costs were further reduced by the shallow development drilling needed. The plant was to have two trains with a site large enough for expansion to five or even more, and would produce 4 million metric tons/year initially and up to 10 million metric tons/year on expansion to five trains.
LNG PROJECT STATUS
The preferred plant contractor has been selected. The consortium is made up of Technip, M.W. Kellogg, Snamprogetti, and Japan Gasoline Co. Discussions are quoted to be in the final stages of agreement, and construction is due to start shortly. Four LNG carriers have been bought, and purchase of two others is imminent. First lifting is scheduled for 1999.
However, NNPC funding of its equity share is still not fully resolved. Further, IFC withdrew from the project earlier this month amid a highly volatile political situation that seemed to place the fate of the long proposed scheme in further jeopardy.
BUYERS AND COMPETITION
The Bonny project is one of the best placed LNG schemes to supply Europe in the short/medium term and the U.S. in the future, especially with purchasers' strategic needs for diversification of supply.
The LNG project has major sales agreements totaling 5.7 bcm/year, with one American and four European companies, Enel (Italy), Enagas (Spain), Gaz de France, and Distrigas Corp. (U.S.). Botas of Turkey may also enter into an agreement to buy up to 1.5 bcm/year.
The project competes, however, with the Cristobal Colon scheme in Venezuela, scheduled for 1998 first delivery, the existing Algeria LNG plants at Arzew and Skikda, and the Trinidad LNG project. Qatar North field gas will also be available in 1997, followed by Norway in 2000.
Any one of these schemes can jeopardize the Bonny LNG position if it fails to meet short term market opportunity.
ENERGY OPPORTUNITIES
With about 95 million people, Nigeria has significant debt- service commitments, industry capacity under utilization, and huge development needs. The government is keen on private sector involvement in the petroleum industry.
The current petroleum policy is one of increasing the oil reserve base; achieving refining self-sufficiency; a gas exploitation program that acknowledges this substantial resource base; and expansion of its petrochemical capabilities.
Mareena Petroleum Ltd., Lagos, is a company that recognizes the potential and opportunities within the Nigerian energy sector. It holds exploration interests in the delta region and is committed to expand its activities into other selected areas of the petroleum industry.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.
