TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDirect calculations of petrophysical properties from micro-CT imaging have been reported in the literature to accurately predict single phase and multiphase flow transport properties respectively. These predictions are usually validated with experimental data available in the literature. The properties of rocks that are usually used (Berea, Benthiemer and Fontainbleau), even though have been assumed to be homogenous but vary in terms of pore pattern. Data from the literature which were obtained from different rock samples may introduce an error if the same rock sample is not used in the micro-CT imaging for direct computations or network model simulations. For proper validation of predictive capability of CT-imaging and its computational techniques with negligible variation, there is need to use porous media with same pore patterns in both CT-imaging and laboratory measurements. This paper presents laboratory measurements made on synthetic model rock (ROBU) with uniform pore patterns. The result from these measurements will be handy for validation of micro-CT based direct computation of petrophysical properties. Petrophysical properties measured in this paper include porosity, permeability and calculated formation resisitivity factors.Four different samples with BET surface area range 0.015m 2 /g to 0.5m 2 /g. were used. The experiments were repeated thrice for reproducibility check.The results from the measurements show the porosity and permeability are in the range of 0.3 to 0.4 and 2.5 to 300 Darcy, respectively for all samples (0, 1, 3 and 4). Formation resistivity factors are in the range of 4.5 to 8.5 for the four samples. The porosity values of all the samples are considered moderate but the permeability values of samples 3 and 4 are comparable to some homogenous model rocks (Kirby and Briarhill sandstones). The results from the measurements show that more reliable and consistent data can be obtained from the synthetic model rocks used. In general, the samples used are said to be homogenous within the limit of experimental error and the data obtained can be used for validation of both direct computations and network model predictions. The use of this synthetic model rock for initial model calibration in studies related to multiphase flow transport properties will give a more realistic, accurate and representative results than the presently used natural occurring model rock.
Determining the performance and behavior of horizontal well subjected by double-edge water drive reservoir at a late time period has been a concern to many researchers. Wellbore pressure losses during production in horizontal well increase conning propensity at late period thus rendering some part of the horizontal well unproductive. This restricts the effectiveness of increasing the horizontal well length due to wellbore pressure losses along the horizontal well. This study was carried out by using source function and Newman rule to develop models to predict the performance and behavior of a horizontal well which was subjected by double Edgewater and numerical method was used for the computation and Sensitivity analysis of parameters was performed. The results show that the performance and behavior of the reservoir for this study were found to be when the well is position at well length (XWD: YWD: ZWD), in the ratio of 12:7:15 respectively. Keywords: Double edged, Performance, Reservoir, Water Drive, Late Period.
When a reservoir is bounded, well productivity is affected in the long time according to the nature of the boundary. The length of time for oil production is strongly affected by well location with respect to the boundary, whether the boundaries are single, paired and vertical or paired and inclined. It therefore becomes important that well location is guided to achieve prolong oil production. The guide may be achieved from solution to a specific flow equation describing pressure distribution. The solution prescribes rates and well location for available reservoir system properties. In this paper, dimensionless pressure derivatives of a vertical oil well are studied to search for optium well location that can guarantee satisfactory oil production without premature influence of the external boundaries. The external boundaries are sealing and are considered to be inclined. The solution to this dimensionless diffusivity equation is utilized. The derivatives are computed from the total dimensionless pressure expression summing all the image wells by superposition principle. The Python and Excel softwares were deployed to compute all the dimensionless pressures for the different well designs. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the sealing faults. The optimum well location from the sealing faults is inversely proportional to the inclined angles. This implies that nearer wells to faults produce optimally at a given time of production. Furthermore, the relationship between well distance and productivity has no maximum or minimum points. Therefore there is no particular optimum location distance from the faults for optimum productivity. Optimum well location for sealing boundaries depends on many factors, such as production profile, well design, faults angle, fluid type and lease size. Furthermore, it was also observed that the wellbore radius has no significant effect on the dimensionless pressure derivative, optimum well location and the optimum time of production.
Pressure transient analysis has been used to evaluate performance of a vertical well located within two intersecting sealing faults. The nature and types of boundary affect productivity in bounded reservoirs. Well performance is strongly affected by well location with respect to the boundary, be it single, paired and parallel or paired and inclined. The goal of this research was to study pressure behavior as well as performance of a vertical well located within two intersecting sealing faults inclined at various angles θ and at unequal distances to faults. Unlike similar works previously carried out, this work can be used to study or predict pressure distribution of a well in a wedge system located at unequal distances to faults. Using the concept of images, the study proposed new models for estimating distances between image well(s) and active well. These models were applied in the solution to the dimensionless diffusivity equation to characterize pressure transient behavior of a well located at unequal distances to the inclined faults. These pressures and pressure derivatives were computed from the total pressure drop expression summing all the image wells by the principle of superposition. The MATLAB, Python and Excel software were deployed to compute all the dimensionless pressures for the different well designs. The results obtained show that 1) the proposed models give accurate estimation of active well distances to image wells; 2) the models show that the distance between the active and image wells d0,i increases for the range of values of angles 0°< θ0,i ≤ 180° and decreases for the range 180° < θ0,i < 360°; 3) the relationship between unequal well distances and productivity has a maximum point; 4) beyond this point, the well ceases to be productive and; 5) this maximum point is at equal distances of the well from both faults, in this case, 15 ft. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the boundaries. Worthy of future works are similar studies on 1) horizontal wells and 2) mixed boundaries, that is, one sealing fault and one constant pressure boundary.
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