SPE Members Abstract Inflow performance of twenty-one theoretical solution-gas drive reservoirs was simulated using the Weller method. These reservoirs contained a wide range of rock properties, fluid properties, relative permeability characteristics and skin effects. Two permeability characteristics and skin effects. Two types of inflow performance relationships were developed from the 19,500 generated data points. For the first type, each curve represents dimensionless pressure versus the oil flow rate normalized to its pressure versus the oil flow rate normalized to its actual maximum, flow rate. The second relates dimensionless pressure to the ratio of flow rate to the theoretical maximum, undamaged flow rate. Results show that inflow performance is strongly dependent on bubble point pressure and reservoir depletion effects; while oil API gravity, residual oil saturation, critical gas saturation, absolute permeability and relative permeability have only a permeability and relative permeability have only a minor effect. Skin effect and reservoir extent have major effects only on the unnormalized curves. Nonlinear regression techniques were then used to develop empirical equations that fit dimensionless flow rate as a function of dimensionless pressure and skin. Equations were also developed that included the effects of depletion, bubble point pressure and ratio of reservoir extent to wellbore radius. The resulting equations proved to be statistically sound. In addition, several new reference curves that can be applied to solution-gas drive reservoirs in general are proposed. The new curves incorporate approximately 19,500 data points and a wide range of reservoir characteristics. Introduction One of the most important problems confronting a petroleum engineer is predicting pressure/production petroleum engineer is predicting pressure/production behavior in an oil and gas reservoir, given a host of possible operating schemes. By predicting the possible operating schemes. By predicting the response of an oil reservoir for various hardware and pressure scenarios, a first case estimate to maximize pressure scenarios, a first case estimate to maximize profitable reserves development can be achieved. profitable reserves development can be achieved. Computer solutions for the performance prediction of solution-gas drive reservoirs have evolved since the early 1-950's. However, most methods were algebraically intensive and required considerable computation time. In 1965. Weller devised improved method of calculating the performance depletion-type reservoirs. This method, with the help of a few simplifying assumptions, provided a fast and simple means of predicting pressure performance for gas-oil flow in a reservoir. By performance for gas-oil flow in a reservoir. By plotting flowing bottom-hole pressure versus flow plotting flowing bottom-hole pressure versus flow rate, a useful method of estimating oil well productivity, known as the performance productivity, known as the performance relationship (IPR), can be established. Vogel used the method of Weller to calculate IPR curves for wells producing from several depletion-drive reservoirs for a variety of PVT properties and relative permeability data. He introduced the notion of permeability data. He introduced the notion of dimensionless IPR curves. Vogel noticed that the dimensionless curves exhibited similar shape for various reservoir conditions. From this fact, he proposed a reference curve that could be used to estimate well productivity for most undamaged solution gas drive wells. productivity for most undamaged solution gas drive wells. Standings presented a companion set of curves to Vogel's curve that enabled the estimation of productivity for damaged or improved wells based on productivity for damaged or improved wells based on the flow efficiency. However, his curves do not hold for certain cases of low flowing pressure and high flow efficiencies. This study has tried to examine several factors that effect the calculation of IPR curves. Critical factors are reservoir rock properties, fluid properties, bubble point pressure and depletion. properties, bubble point pressure and depletion. Also, zonal damage around the wellbore, caused during drilling or completion, can dramatically decrease the productivity of a well. productivity of a well. P. 869

Traditional water-influx calculations rely on accurate values of the van Everdingen and Hurst dimensionless variables Po and qD· We have presented six sets of simple polynomials that provide a fast, simple method to determine PD' Po', and qD for finite or infinite radial aquifers. The results yield values as accurate as the original tables and are up to 15 times more efficient.

Real-gas pseudopressures allow rigorous analytical solutions to the nonlinear mass/momentum equations for gas flow in porous media. These solutions, however, are in terms of pseudopressure rather than reservoir pressure. To convert pseudopressures to their complementary reservoir pressures, one of three techniques is traditionally applied: numerical integration, table look-up, or curve-fit analysis. All three interject some numerical error into the m(p) calculations. This paper introduces a new, "exact" procedure for making the pseudopressure/pressure conversion. It is applicable to a wide range of reservoir properties including sour gases, temperatures up to 460°F [238°C], and pressures to 10,000 psia [70 MPa]. Sample calculations are shown and comparison with a number of other pseudopressure estimates is made.

As North American oilfield operations mature, there is a perceptible loosening of the autocratic ties between oil companies and contractors. They are being replaced by alliances or partnerships designed to minimize cost while improving profitability of the companies involved. This paper evaluates a mature alliance, its implementation, structure, and results.

The introduction of the notion of pseudo-pres-sures allows rigorous, analytical solutions to a wide range of gas flow problems. However, in order to apply pseudo-pressuro based solution techniques a num-ber of cumbersome procedures are invoked to take res-ervoir pressures and convert them into pseudo-pres-sures. These include dimensionless table look up, numerical integration and regression analysis. To then convert the corresponding pseudo-pressures back to their analagous reservoir pressures, graphical and/or regression techniques need to be employed. This paper, then, examines the use of a semi-analvtical approach to real gas pseudo-pressure/pres-sure conversion calculations and its application to well test analvsis. The semi-analytical approach to real gas pseudo-preseures allows, a simple, direct and exact solution for converting pseudo-pressure to pressures and vice Versa. No numerical integration, graphical or regression techniques are needed and the approach is well-suited for desktop or minicomputers. It is applicable to a Wide range of reservoir properties ties including sweet and sour gases, reservoir pres-sures up to 10,000 psia and reservoir temperatures up to 460'F.Well test ana]vees have then been carried out on a number of published buildup, drawdoun and deliver-ability tests using the semi-analytical approach. 227 Comparisons have been made between test interpreta-tion results using traditional pseudo-pressure calcu-lations and analyses from the semi-analytical ap-proach.