Oil production from thin oil rim reservoirs with strong aquifers and large gas caps is challenging due to early gas and water breakthrough, movement of the fluid contacts and low oil recovery factor. One means of handling the problems associated with thin oil reservoirs is the use of horizontal wells which improves recovery factor. This work however proposes a measure through which gas injection into the reservoir is used to improve oil recovery factor and minimize water production using vertical wells. A simulation study was carried out using the data from a thin oil rim reservoir in the Niger Delta. The five cases studied are the base case (using conventional vertical wells), use of horizontal wells, water production and disposal, water production and re-injection into the oil zone to improve recovery, and gas injection at the oil water contact. The recovery factor and volume of produced water were compared for all five cases for a production period of 40years. An oil recovery factor of 25%, 29%, 40%, 33% and 44% were obtained for the base case, use of horizontal wells, water production and disposal, water production and re-injection to improve recovery, and gas injection at the oil water contact respectively. Volume of produced water was lowest while the GOR was highest for the proposed method than any other method. The main disadvantage using the approach of injecting gas at the water oil contacat is the high GOR however; recycling the gas by injecting the produced gas back into the gas cap is a viable solution. The relatively higher oil recovery factor and minimal volume of produced water which are highly desired for effective production from thin oil reservoirs makes the proposed technique worth investigating.

There are several proposed techniques that can improve oil recovery efficiency from thin oil rims with strong aquifers and large gas caps. These techniques include use of horizontal wells, water production from the underlying aquifer, edge water injection into the oil zone and gas injection at the oil water contact (OWC). Since all these methods improve oil recovery from thin oil rims, one of the objectives of this work is to investigate by simulation, the effect of combining two methods on recovery efficiency of the reservoir. The dynamics of the fluid contacts for all the techniques considered were also studied and it was observed that the most minimal shift occurred with the technique of gas injection at the OWC. Simulation results revealed that combining two techniques does not significantly improve oil recovery efficiency over one technique. When only a single technique was used, the oil recovery factors were 40%, 33% 44% and 42% for water production and disposal, edge water injection, gas injection at the OWC and water injection at the gas oil contact (GOC) respectively. But on combining two techniques of simultaneous water and gas injection at the GOC and OWC respectively and alternate water and gas injection at the GOC and OWC respectively, the oil recovery efficiency were 43% and 45% respectively. These results indicate that any increase that might occur may not be significant enough to justify the cost of implementing two or more techniques; thus, optimizing a single technique is recommended.

This paper discusses and evaluates a fast, reliable and conservative method of estimating the gas initially in place; reservoir properties—permeability, drainage area and skin for volumetric dry-gas reservoirs using a nonlinear flowing material balance and in the absence of a representative average reservoir pressure history. This approach uses reliable pseudopressure-normalized rate (PPNR) vs. pseudopressure-normalized cumulative production (PPNC) data. In theory, it considers a pseudopressure-normalized (PPNR) rate vs. pseudopressure-normalized pseudocumulative production (PPNPC). A modification to existing theory is to use a pseudocumulative production function, a polynomial which accounts for variations of the viscosity-compressibility product with fractional recovery. This function transforms the flowing material balance to a nonlinear equation. Pseudosteady-state data are used and matched by polynomial regression on spreadsheets to obtain the various coefficients of the nonlinear equation. The production characteristics are then inferred from the constant and the coefficient of the unit exponent. The 3rd and 4th degree nonlinear equations have shown to give excellent results based on the depletion characteristics of the reservoir. This theoretical-empirical approach can easily be adopted in production data analysis and will predict reliably whilst ensuring a reduction in production data noise and the rigours of digital type-curve matching. We demonstrate the application of this method using simulated and field production data.

This paper presents detailed theories and method of determining fault transmissibility and production history matching using the multi-tank material balance. This approach uses a two-step optimization process whose algorithm can be written as macros in spreadsheets. The upper-level (outer) stage optimizes the transmissibility and hydrocarbon initially-in-place while the lower-level (inner stage) optimizes the pressure of the support tank at each time step. This approach is validated using numerical simulation. This approach will be highly beneficial in effective reservoir management where little or no 3D seismic exists and for cases of sparse production data.

The increasing interest in production from liquid-rich reservoirs calls for an efficient method for estimating its fluid properties and more importantly, from production data. The gas material balance for liquid rich systems is largely dependent on several PVT parameters. One of such parameters is the vapourized oil-gas ratio, which defines the amount of stock tank condensate that drops from one standard cubic feet of produced well stream gas. The vapourized oil-gas ratio is usually obtained by Extended Black Oil simulation using an Equation of State (EOS) model well tuned to the PVT experimental data. This experimental data might not be readily available when needed for a quick analysis and even when available, the process of tuning requires great skill and experience of the reservoir engineer. An empirical correlation for the vapourized oil-gas ration is proposed based on a statistical evaluation of values obtained from several simulations (Extended Black Oil) using a tuned Equation of State Model. 14 representative gas-condensate samples from the Niger Delta were used to generate over 2000 lines of vapourized oil-gas ratio. The developed correlation have input parameters, which are readily obtained from field production data. This approach is easily applicable, and valid for a wide range of gas-condensate compositions. It predicts, to a good extent, the vapourized oil-gas ratio for a pressure depletion sequence without recourse to a rigorous EOS modelling.