NIGER DELTA OIL PRODUCTION, RESERVES, FIELD SIZES ASSESSED

David Thomas
Thomas & Associates
Hastings England

The 252 fields in the Niger delta with published reserve estimates or production history can be categorized as shown in Table 1 (15395 bytes). Distribution of oil and gas fields in the delta is shown in Fig. 1 (201385 bytes).

In addition to the tabulated fields there are more than 200 reported discoveries in the Niger delta for which no reserve estimates are available to the author. It is however highly likely that the majority are in the lower quartile of field size range.

It is also obvious that Table 1(15395 bytes) is unrepresentative of the Niger delta as a whole. Field size distribution in the province will conform to the axiom that in any petroliferous basin the large discoveries are made in the early days of exploration (for a given structural play). This would suggest that field sizes likely to be found might be up to 40 million bbl for the onshore, with exceptional fields in the 60-80 million bbl range.

A frequency distribution of the 252 fields where reserve estimates are available has 169 fields below 100 million bbl recoverable with 69 accumulations at 5-20 million bbl. Normal expectations in a basin as mature as the onshore Niger delta would be that undeveloped accumulations are much smaller than producing fields.

However, in the past smaller fields in the onshore seem to have been brought on-stream to meet high production targets when there was favorable demand for oil. These fields were then often shut in when demand slackened and production controls were introduced. Further, many small fields were developed in the 1960s when the fiscal climate made producing them an economic proposition.

Therefore, a plausible estimate of the average field size for the other 200 plus discoveries in the delta may be 1-30 million bbl. This would suggest a resource base of up to 7 billion bbl. Most of these fields would be uneconomic under current fiscal terms.

Oil field size distribution in the under 50 m water depth offshore is beginning to take a shape very like that of the onshore, but in exploration terms the region is still immature.

On early and perhaps naive assessment it seems to have a higher proportion of giant fields compared to the onshore. This is probably a function of economics and exploration strategy. Large structures will be drilled first, given the exacting fiscal regime and the fact that isolated oil fields will require their own dedicated production platforms and therefore need to be large to justify development. Future potential is for field sizes of 50-100 million bbl, with exceptional field sizes of 100-200 million bbl.

In waters beyond 50 m depth, there exists excellent potential for large discoveries. With the possible exception of certain active regions (in the southeast and northwest of the offshore delta), the area is immaturely explored.

Based on statistical treatment, the likelihood of dis- coveries above a given size is shown in Table 2 (10845 bytes). There is nearly a one in three chance of a discovery over 100 million bbl of oil equivalent.

A recent example of the offshore potential is the Ash- land/Total discovery in permit OPL 90. Ashland Oil Inc. in 1994 drilled Okwori South-1 in 140 m (460 ft) of water, and it flowed 6,184 b/d from Agbada formation sands. Previous to Ashland's acquisition of the PSC permit, Occidental had made a series of significant discoveries on adjacent acreage, and on regional structural trend, in the 1970s (OGJ, Aug. 29, 1994, p. 28).

OIL RESERVES

Nigerian joint ventures (Nigerian National Petroleum Corp. and foreign oil companies) have embarked on huge capital investment programs to raise production capacity and recoverable reserves.

In 1989, Nigeria had booked recoverable oil reserves of 16 billion bbl. By 1991 this has risen to 18 billion bbl, and by the end of 1992 the target of 20 billion bbl previously set by the government had been achieved. This estimate implies a reserves to production ratio of 29 years at 1.95 million b/d.

In March 1992, Shell said that government targets of 20 billion bbl of recoverable oil reserves and 2.5 million b/d production by the mid 1990s from existing producing areas were entirely realistic. What were targets for recoverable oil reserves in early 1992 became achievements by the third quarter of the year.

During 1987-1992, 72 oil discoveries were announced. Of these, estimated recoverable reserves of 37 were publicly disclosed. If on a rule of thumb basis we assume a 50 million bbl field for each of the other 35 undisclosed discoveries, then the total would give a 5 year reserve discovery of nearly 4.6 billion bbl.

In this period Nigeria produced 3.7 billion bbl. This would leave 1992 reserves some 3 billion bbl short of the stated 20 billion bbl of recoverable reserves.

Without any assumptions for oil field recoverable oil revisions, Table 3 (16752 bytes) shows Nigerian reserves to be 17.4 billion bbl in 1992. The 1989 remaining reserve figure corresponds to the official reserves stated at the time. The Nigerian authorities reported that reserves found in 1991 were 2.5 billion bbl, which suggests another 1.3 billion of reserves from field revisions for that year. On this basis the official reserves (Table 4) (14724 bytes) can be justified.

This rationalizing suggests that at least 3 billion bbl of official reserves are the result of upward revisions of existing field reserves and not new field discoveries. This is probably consistent with activity in the delta.

DEVELOPMENT PROGRAMS

Operators have been undertaking a substantial program of development drilling in existing fields. For example:

In 1990, Shell started development drilling in Agbada, Alakiri, Bomu, and Nembe Creek oil fields and concurrently a program to build 16 additional flow stations of 30,000 b/d average capacity to handle the additional expected production from development drilling.
Elf has also been engaged in extensive development drilling, and in April 1990 announced it has established a further 70 million bbl in onshore Obagi field. Other Elf operated fields that saw successful development drilling and reserves increase in 1990 were Aghigo, Okporo, and Upomani.
Mobil established an extra 100 million bbl in offshore Ubit field.

DRIFTING, 3D SEISMIC

Historically, the delta has only been explored and exploited to a depth of approximately 3,600 m (12,000 ft). Recent discoveries by Shell and Chevron at greater depths suggest the potential for oil discoveries below 3,600 m onshore Niger delta to be very good.

Further, the acquisition of 3D seismic is helping to delineate oil prospects previously not identified. Gbaran field, for example, is estimated to hold approximately 500 million bbl of oil. The structure was previously thought to be a predominantly gas accumulation when discovered in 1967 and is probably an example of reinterpretation with better seismic data.

An earlier general interpretation of the delta oil province concluded it had prolific oil accumulation belts or fairways (rationalized as a function of sand depocenters and geothermal hot spots) separated by zones of relatively lesser prospectivity. Recently, some of these low grade areas have proved to hold commercial oil and gas accumulations.

SECONDARY AND EOR

Nigeria's future as a significant oil producer is as much dependent on increased oil recovery from existing producing fields as it is from new successful exploration.

The potential of secondary and tertiary recovery is great. Secondary recovery techniques, such as gas reinjection or waterflooding, have been used since the early 1980s in many fields in the delta.

Shell estimates typical conventional recovery rates of 30% of oil in-situ could be raised to 40-60% with enhanced recovery. This additional recovery of reserves will require substantial capital expenditure, but economic considerations are likely to restrict tertiary recovery techniques to selected larger fields.

Of the 252 recognized fields, only 22 fields exceed 300 million bbl recoverable by conventional means. Table 5 (12991 bytes) illustrates a potential additional recovery of 2.4-7.7 billion bbl of reserves that may be recovered from these fields. Amenam, Gbaran, Omon, and Oso fields have been excluded from these cal- culations given that their reserve estimates and field characteristics are currently too tentative (to the author) to make reliable assumptions on additional oil recovery.

Both additional reserves from tertiary recovery in larger fields and the small accumulations are best viewed as reserves in the probable and possible categories. The 20 billion bbl recoverable estimate appears to include the likely additional reserves from increased recovery techniques combined with the much less likely prospect of short/ medium term exploitation of currently marginal commercial accumulations.

This assessment indicates the importance of the new deepwater Niger delta province to build up Nigeria's reserve base and is discussed in the fourth article of this five part series.

RESERVE INCENTIVES

In order to achieve its objectives to increase crude oil reserves to 25 billion bbl and production to 2.5 million b/d by 1997, the government formulated a Memorandum of Understanding (MOU) that was signed with the established oil companies operating in Nigeria. It provides guarantee for a profit margin of $2.30/bbl for companies that meet the set targets for reserve additions. Performance above these targets attracts a margin of $2.50/bbl. Differential tax credits are also introduced in the MOU, which has the flexibility to compensate companies for investment risks in the oil price market.

Nigeria's oil production is currently 1.84-1.9 million b/d, although its physical throughput capacity is much greater.

PRODUCTION FACILITIES

Nigerian production capacity has only recently been rebuilt by a combination of infrastructure construction, workovers, and development of existing and new fields. Throughout most of the 1980s investment was drastically reduced as a production quota of 1.3-1.4 million b/d made investment in increasing production or capacity nugatory.

Shell, which contributes roughly half of Nigerian pro- duction, was reckoned to have production capacity in 1986 of 900,000 b/d. By 1990 this had recovered to 1 million b/d. If programs agreed under the 1991 MOU take place then Shell infrastructure capacity should increase to 1.5 million b/d. Apart from the 30 flow stations it intends to build to meet this projection, Shell also intends to debottleneck pipelines and in the south Forcados area construct a new oil pipeline.

On completion of the $750 million south Forcados project, which involves the development of four new fields, Shell's production capacity was scheduled to rise to 1.3 million b/d by 1996 from 1 million b/d. This will require Shell to invest some $1.5 billion/year during 1992-96. However, due to NNPC budgetary cuts, Shell's budget has been decreased with concommitant slowdown in production building.

Of the other major consortia, Mobil increased oil production to approximately 355,000 b/d in early 1994. This ability came primarily from two fields. Offshore Oso condensate field, which came on-stream in 1993, has achieved peak production of 100,000 b/d, and Edop field, which was discovered in 1988, was also planned to reach peak production around this time at 160,000 b/d.

Production from the Elf/NNPC joint venture could rise to 150,000-200,000 b/d by 2000 were offshore field Amenam (discovered in 1990) to be successfully appraised and reserves of 500-700 million bbl confirmed. Elf expects that capital expenditure for years 1992-97 could amount to $1.5 billion.

Chevron, the second largest producer in Nigeria, is similarly engaged in building its production to around 400,000 b/d from past levels of approximately 350,000 b/d. It intends to develop eight fields, including Abig-birodo, Belema, Idama, Inda, and Opuekeba which started in 1993. Ewan, Oghareki, and Bime will be developed in the next 5 years. Ewan, discovered in 1988, is scheduled to start production in 1996 and will be the largest field developed (+160 million bbl), and has a development cost of $250 million. Chevron has 23 fields on stream at this writing.

However, achieving the 2.5 million b/d production target is becoming less likely, especially with recent budgetary constraints imposed upon NNPC. For example, the company requested its six major partners to cut their 1993 budgets by up to 30%.

CAPITAL SPENDING NEED

To achieve its announced increased production and reserve targets, it has been estimated the Nigerian oil sector needs $15- 20 billion of capital expenditure.

If in 1993-97 Nigeria produces 1.95 million b/d on average, then it will need to replace 3.5 billion bbl from the 20 billion bbl reserve base. Therefore to increase reserves to 25 billion bbl, 8.5 billion bbl needs to be found in this period. Coupled to a finding and development cost of $1-5/bbl (onshore and sectors of the offshore - but not deepwater), the financial requirement to implement the plan is considerable.

NIGERIAN EXPORT BLENDS

The Niger delta basin has two characteristic types of crude, one light and another comparatively heavy. The lighter crude tends to be around 36 gravity with the heavier type being 20-25 gravity. Both crude types have low sulfur content and are paraffinic.

In volumetric terms the lighter crudes are by far the greatest proportion of overall reserves and production (Table 6 (14137 bytes)). The significant heavier crude oil fields are Forcados, Obagi, and Olomoro.

Both the lighter and heavier crudes tend on distillation to produce a product slate that is predominantly middle distillate (especially gas-oil) and fuel oil.

The crude oil export blends that are derived from these crudes are illustrated in Table 7 (17186 bytes). Quantitatively, the lighter blends are predominant. Forcados blend is unusual, in that many of the fields feeding into the system have much lighter oils than the blend gravity. Forcados field itself at 22 gravity, and Ughelli area fields are the main contributing factors in establishing the blend's relatively low gravity.

Nigeria has a multiplicity of export crudes that have arisen from oil company competition and an unwillingness to be tied in to another company's pipeline system. Elf reverted from Shell/BP infrastructure to Agip/Phillips's Brass River pipeline in 1973 after having previously had its production from Obagi field moved through the Trans Niger pipeline. The oil was moved under a term agreement with Shell/BP, but their own rapidly increasing produc- tion did not allow Elf to produce more than 40,000 b/d and the agreement might not have been renewed in 1973.

To this day, few fields move through a system where the operators of the pipeline are different from the field operators. Apart from Elf onshore fields which enter the Brass River system, there is Elf's Aghigo, Obodo, Jatumi, Okpoko, and Upomani fields which join the Forcados line, Dubri Oil's Gilli Gilli production which is barged to the Escravos terminal, and the Pan Ocean Ogharefe field that feeds into Forcados, as does NNPC's Abura field. Chevron's small Jiseke field supplies the Bonny system, and Ashland's two onshore fields, Izombe and Ossu, flow into the Brass River terminal.

Besides the blends tabled above, Ashland produces the Antan blend from a group of offshore fields in OPL 98, near the border with Cameroon. Elf began production in 1993 from tanker loaded Aria field, and this with nearby Edikan, Ime, and Odudu fields will see production peak at 60,000 b/d. Oso condensate field also came onstream in 1992-93. It has added to the liquids being exported from Qua Iboe terminal and achieved peak production of 100,000 b/d in summer 1993.

TRENDS IN THE MENDS

No significant changes in the gravity of the blends seems likely in the future. Chevron's Ewan field at 32 gravity will be the most likely field development to change a blend. The Escravos blend will, however, be at around 300,000 b/d in 1996 when the field comes on stream, and the expectation is that Ewan will produce more than 40,000 b/d at peak production.

It is assumed that offshore Amenam field (Elf, OPL 93) will feed into the Brass River system. It is noteworthy that currently the oil gravity and characteristics of this field are not known and this would have a material effect on any established blend, if field size proves to be as large as expected (700 million bbl recoverable).