Agwuble Christian Akpanke
Dulu Appah
Okoro Ejike Samuel
University of Port Harcourt
Nigeria
A new surface well-testing (SWT) method can help operators determine both a reservoir’s potential and when it will become uneconomical and require pressure maintenance.
Niger Delta geology
The Cenozoic Niger Delta complex developed as a regressive off lap sequence. The delta complex, which has been described as having arcuate-lobate shape, was built across the Anambra basin and the Cross River margins and eventually extended onto the Late Cretaceous continental margin. Geologists believe that these sediments were part of the West African miogeocline derived from adjoining older rocks transported and deposited with the help of the Niger and Benue Rivers onto the cooling and subsiding oceanic crust generated as the South American and African continents separated.
Niger Delta basin lies on the continental margin of the Gulf of Guinea in West Africa (Fig. 1). It ranks among the world’s most prolific petroleum producing tertiary deltas. It is one of the most prominent basins in West Africa with a drainage area of about 1.2-million sq km. It has produced a delta area of about 75,000 sq km with a clastic fill of about 12,000 m.
The sedimentary basin of the Niger Delta encompasses a much larger region than the geographical extent of the modern delta constructed by the Niger–Benue drainage system. It includes the Cross River delta and extends eastwards into the continental margins of neighboring Cameroon and Equatorial Guinea. Geoscientists have shown that Niger Delta basin has maintained a thick sedimentary apron and salient petroleum geological features favorable for petroleum generation, expulsion, and trapping from the onshore through the continental shelf and deeper.
Geological studies have shown that several depo belts are present in Niger Delta basin (Fig. 2). There are three categories of depo belts common in the Niger Delta onshore, continental shelf, and deepwater terrains:
• Extensional zones (growth faults).
• Translational zones (diapirs).
• Compressional zones (toe thrust).
Unlike the onshore Niger Delta, its continental shelf region has shale diapirs and growth faults. Shale diapirs have not been found in the onshore Niger Delta to date. The presence of growth faults and roll over anticlines in nearly all regions of the Niger Delta is a pointer that a structural trapping mechanism for petroleum is common. The geological age of the Niger Delta ranges from Paleocene to Present. Oil and gas have been found in reservoir rocks ranging from Oligocene to Miocene.
The Niger Delta continental shelf’s geosynclinal structure contains sediments of varying lithology, exceeding 40,000 ft near Warri. The depositional environments of these sedimentary accumulations vary from near-shore to deepwater deposits, non-marine, and marginal marine.
The Niger Delta includes two major sedimentary units:
• Massive coarse-grained sands and sandstones of non-marine and continental deposition. Inter-bedded sandstone and shale deposited in shallow marine environments and containing the major hydrocarbon accumulations of the Nigerian petroleum province.
• Deepwater deltaic clays. The northwest rim of the delta is flanked by the Benin flank, a subsurface continuation of the West African shield, and ends along a southwest trending flexure fault zone. The eastern side is bounded by the Calabar flank, a subsurface continuation of the massif. The Abakaliki uplift and post-Abakaliki Anambra basin lie to the north. These structural elements are believed to have remained stable throughout the Cenozoic.
Rollover anticlines
These anticlines develop by downward movement along the concave fault planes causing rotation of the down-thrown layer. Many fault planes may have break offs that make the rollover structure a bit complicated. Subsidiary growth faults sometimes develop on the flanks of the main rollover structure, accompanied by formation of satellite rollover structures.
In areas where a series of rollover structures occur along a fault path, the length and shape of the sedimentary cycle are indicated by possible correlation over long distances. Oil and gas reserves in Niger Delta basin mainly occur in sandstone reservoirs throughout the Agbada formation, usually trapped in (faulted) rollover anticlines associated with growth faults. In addition to growth fault-related structural traps, stratigraphic traps related to palace-channel fills, regional sand pinch-outs, and truncations occur. Most known traps in Niger Delta fields are structural, although stratigraphic traps are not uncommon (Fig. 3).
The structural traps developed during sedimentary deformation of the Agbada paralic sequence. As discussed earlier, structural complexity increases from the North (earlier formed depo belts) to the South (later formed depo belts) in response to increasing instability of the under-compacted, over-pressured shale. A variety of structural trapping elements, including those associated with multiple growth faults, structures with antithetic faults, and collapse crest structures, were described.5
Structure complexity depends on the overall sediment burden in the initial phases of growth faulting. Displacement only occurs along the major bounding faults. With increased overburden and increased horizontal displacement, accommodation becomes more complex and finally occurs along numerous small faults which form the typical collapsed crest structures. Gross reservoir properties are a function of depth, sand-shale ratio, and the sealing potential of faults. The transgressive marine shale forms important regional top seals, with faults often providing lateral seals. Due to stacked sand-shale alternations, most oil column heights average 15-50 m.
Methodology
A decrease in pressure and production rate prompted an SWT, carried out by producing the well at a continuous rate for a stipulated time. The well was next shut-in for a pressure build up.
Well-test analysis showed the field production rate having dropped drastically over a 1-month period. To determine the potential of the field the exponential decline model was used.
Production history makes production rate and time data available. The daily, monthly, and annual production decline rates can be determined using the exponential decline model.
Results
Analysis of well-test results revealed that the production rate had dropped from 427.6 stb/d to 386 stb/d, over a 1-month period. By substituting 427.6 stb/d as the value of r0m and 386 stb/d as the value of r1m into Equation 1, the oil production rate after 1 year was 125.99 stb/d, a 29.5% decrease.
Production prediction
Fig. 4 shows that after the first year, oil production rate will drop to 125.99 stb/d while the amount of oil produced that year would be 90,094 stb. At the end of the second year the oil production rate is estimated to drop further to 91.66 stb/d for an annual production total of 26,545 stb. The third year would see a further decrease of production to 13.10 stb/d and 7,821 stb total. The projection for the fourth year revealed that oil production would drop to as low as 3.22 stb/d (2,760 stb total). Pressure maintenance or tubing optimization should be deployed immediately to maintain reservoir pressure and increase production.
Model validation
Fig. 5 is a semi-log plot of oil flow rate against time showing a linear relationship which corroborates the exponential decline model. The relationship between oil produced and oil production rate is also linear, further authenticating use of the exponential model for field-potential evaluation.
Equation 2 depicts the linear relationship between oil flow rate and time.
Field application
The model was applied to a field with 98-million stb initial oil reserve that had recorded 15.23-million stb gross production after 12 years but because of decreased oil production needed an SWT to determine reservoir potential.
The well-test result showed that oil production dropped from 427.6 stb/d to 386 stb/d during a 1-month period.
Semi-log plot of oil flow rate against time revealed that the relationship between log of oil flow rate and time is linear and that the plot of oil produced and production rate was also linear. The exponential decline model was therefore used to predict future performance of the field.
A mathematical model for the linear relationship between oil production rate and time for the field determined the rate of oil production.
Analysis of the result showed that the field would soon be uneconomical and reinforced the need to deploy a method for pressure maintenance or tubing optimization immediately to maintain reservoir pressure and increase oil production rate.
Acknowledgment
The authors wish to show their gratitude to the Petroleum Technology Development Fund Gas Research Group, University of Port Harcourt, and Centre for Petroleum Geosciences School of Graduate Studies, University of Port Harcourt, for their unconditional support for this research work.
Bibliography
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Doust, H., and Omatsola, E., “Niger Delta,” Divergent-Passive Margin Basins, AAPG Memoir 48, AAPG, Tulsa, 1990, pp. 239-248.
Ejedawe, J. E., “Patterns of Incidence of Oil Reserves in Niger Delta Basin,” AAPG Bulletin, Vol. 65, 1981, pp.1574-1585.
Evamy, B.D., Haremboure, J., Kamerling, P., Knaap, W.A., Molly, F.A., and Rowlands, P.H., “Hydrocarbon habitat of Tertiary Niger Delta,” AAPG Bulletin, Vol. 62, 1978, p. 277-298.
Weber, K. J., “Hydrocarbon Distribution Patterns in Nigerian Growth Fault Structures Controlled by Structural Style Stratigraphy,” Nigerian Association of Petroleum Explorationists Bulletin, Vol. 87, No. 1, 1987, pp. 7-30.
Stacher, P., “Present Understanding of the Niger Delta Hydrocarbon Habitat,” Geology of Deltas, A.A. Balkema, Rotterdam, 1995, pp. 257-267.
The authors
Agwuble Christian Akpanke ([email protected]) is chief executive officer of Royal Chegg Nigeria Ltd. He holds an MSc (2016) in petroleum geoscience from University of Port Harcourt, Nigeria, and a BSc (2004) in geoscience from the University of Calabar, Nigeria.
Dulu Appah ([email protected]) is a professor of petroleum and gas engineering and director of the Institute of Petroleum Studies, Total E&P–IPS research chair. He is also Petroleum Technology Development Fund professorial chair in gas engineering, University of Port Harcourt, Nigeria. He earned his PhD (1996) in petroleum and gas engineering from the University of Port Harcourt and an MSc (1985) with distinction in petroleum engineering from Azerbaijan Institute of Petroleum and Chemistry, Baku, USSR.
Okoro Ejike Samuel ([email protected]) is a research associate at Petroleum Technology Development Fund, University of Port Harcourt. He holds an MSc (2013) in petroleum and gas engineering from the University of Salford, Manchester, UK, and a B.Tech (2006) in chemical-petrochemical engineering from Rivers State University of Science and Technology, Port Harcourt. He is a member of the Society of Petroleum Engineers and the Association for Project Management.
