The Secondary Recovery Project at Ogharefe Field, Nigeria
Authors: Aron David , Ashbourne Trevor John , Oloketuyi Doherty Olukayode 
Published: December 2007

Summary
A secondary recovery project involving water injection and gas-lift facilities was installed in the Ogharefe field in 1979 following detailed reservoir simulation studies. Two years' operation provides the opportunity to discuss the progress of project so far.

Introduction
The Ogharefe field is in the Bendel State of Nigeria near Benin City (Fig. 1) and is operated by Pan Ocean Oil Corp. (Nigeria), a Marathon subsidiary, with participation from the Nigerian Natl. Petroleum Corp. (NNPC). The field is an elongated anticline of approximately 2,000 acres [8.1 × 10 6 m2] with a northwest-southeast axis and is situated on the downthrown side of a major growth fault. Hydrocarbons were discovered in 1975 in the B, C1, and D1 sands. Additional oil, gas condensate, and gas reserves have been found subsequently in 15 other sands between 9,000 and 12,000 ft [2743 and 3658 m]. Production from the Ogharefe field began in June 1976, and 17.4 MMSTB [2.8 × 106 stock-tank m3] Oil had been produced by March 1982. Although production has been from seven zones, about 70 % of reserves are in the B production has been from seven zones, about 70 % of reserves are in the B and C1 zones. By March 1982 production reached 7.7 MMSTB [1.2 × 16 6 stock-tank m3] oil for the B zone and 5.5 MMSTB [0.9 × 10 6 stock-tank m3 ] for the C1 zone. This paper describes development of the secondary recovery project in the Ogharefe field together with the experience gained to date. Application of reservoir simulation and appropriate reservoir monitoring techniques are also discussed.
Geology The Ogharefe field is approximately 3 miles [4.8 km] long and 1.25 miles [2.0 km] wide and is an anticline with a limited amount of rollover into a growth fault. Stratigraphy has been determined by examination of cores from Well 12 together with the study of spontaneous potential (SP), gamma ray, resistivity, formation density, and caliper logs. A cycle of barrier/beach, barrier front, marine clay, and transgressive sand has been recognized. The B sand unit is a complete cycle of deposition beginning with a transgressive member and ending with a barrier bar. The cored section shows a coarsening upward with relatively sharp contacts between the clay/sandstones of the barrier foot facies. A net pay isopach map of the B zone is shown in Fig. 2. The C1 sand unit begins with a transgressive sand followed by a thin marine clay and then a succession of barrier foot and barrier/beach deposits. A cored section near the top of the unit exhibits limited coarsening upward, but contacts between the lithologies are sharp. A net pay isopach of the C1 zone is shown in Fig. 3. pay isopach of the C1 zone is shown in Fig. 3. Primary Production History Primary Production History B ZONE. Basic reservoir data for the B zone are presented in Table 1. The B zone reservoir was originally undersaturated with an initial average reservoir pressure of 4,325 psia [29.8 MPa] and a bubble point of 3,754 psia [25.9 MPa]. Reservoir production began in June 1976 from Wells 4, 5, 6, 7, and 9. Additional wells (12 and 13) were drilled and completed as B zone producers by Feb. 1977. A production history is shown in Fig. 4. producers by Feb. 1977. A production history is shown in Fig. 4. Preliminary reservoir simulations conducted in Oct. 1976 examined the possibility of aquifer support in maintaining reservoir pressure. Limited possibility of aquifer support in maintaining reservoir pressure. Limited well control outside the immediate reservoir area made estimating the extent of the aquifer difficult, as did the short production history. Although it was clear from log and test data that the reservoir had a water leg, the areal extent of the aquifer was uncertain. The reservoir simulation study indicated that pressure maintenance by water injection would increase ultimate recovery. It was apparent, however, that the optimal timing of the start of water injection was dependent on the degree of aquifer support. During 1977 four pressure surveys were made of the B zone wells. Because of the good reservoir permeability, individual well pressures were in close agreement. The pressure surveys indicated that average reservoir pressure fell below the bubble point in mid-1977. At that time it was not pressure fell below the bubble point in mid-1977. At that time it was not possible to monitor any increase in producing GOR's because of metering possible to monitor any increase in producing GOR's because of metering problems. However, consistent results from PVT analysis of reservoir problems. However, consistent results from PVT analysis of reservoir fluids indicated that the estimated bubble point pressure of 3,754 psia [25.9 MPa] was accurate, and it was therefore clear that a secondary gas cap was being formed in the reservoir. Detailed reservoir simulation studies begun in Aug. 1977 provided an optimum secondary recovery plan incorporating water injection and gas lift. This work was completed in Jan. 1978, and a detailed plan for the project was submitted to NNPC later that year.
JPT
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