Accurate differentiation of reservoir fluid and determination of elastic parameters when some logs are not available is a major challenge in the petroleum industry and this study explored the potential of rock physics modeling to resolve these challenges. Suite of logs from four wells were provided, but only three wells were used for the analysis because well 3 does not have density log. Petrophysical properties were calculated from the logs using the respective equations and pseudo shear wave velocity was estimated from the P-wave velocity. The result of the rock physics analysis carried out using crossplots of acoustic impedance against P-wave velocity coloured with gamma ray log was able to separate the lithology into sand and shale both within the wells and the reservoirs of interest with the aid of the relevant rock physics models. Vp/Vs against acoustic impedance crossplots coloured with density log indicated the pore fluid in the wells and mapped sand bodies to be water and oil. Two mathematical models for predicting elastic parameters in the absence of some necessary logs were developed and these models can be used in the Niger Delta and in other sedimentary basins of the world.
Seismic interpretation and petrophysical assessment of borehole logs from seven wells were integrated with the aim of establishing the hydrocarbon reserves prior to field development which will involve huge monetary obligation. Four hydrocarbonbearing sands, namely Pennay 1, 2, 3 and 4 were delineated from borehole log data. Four horizons corresponding to near top of mapped hydrocarbon-bearing sands were used to produce time maps and then depth structural maps using checkshot data. Three major structure-building faults (F2, F3 and F5 which are normal, listric concave in nature) and two antithetic (F1 and F4) were identified. Structural closures identified as rollover anticlines and displayed on the time/depth structure maps suggest probable hydrocarbon accumulation at the upthrown side of the fault F4. Petrophysical analysis of the mapped reservoirs showed that the reservoirs are of good quality and are characterized with hydrocarbon saturation ranging from 56 to 72%, volume of shale between 7 and 20% and porosity between 25 and 31%. Pennay 2 and 3 have a better relative petrophysical ranking compared to other mapped reservoirs in the study area. Dissimilarity in the petrophysical parameters and the uncertainty in the reservoir properties of the four reservoirs were considered in calculating range of values of gross rock volume (GRV) and oil in place volume. This research study revealed that the discovered hydrocarbon reserve resource accumulations in the Pennay field for the four-mapped reservoir sand bodies have a total proven (1P) reserve resource estimate of 53.005MMBO at P90, 59.013MMBO at 2P/P50 and 65.898MMBO at 3P/P10. Reservoir C, the only interval with a gas cap, has a volume of 7737MMscf of free gas at 1P, 8893.2MMscf at 2P and 10185.2MMscf at 3P. These oil and gas volumetric values yield at 1P/ P90 total of 137.30MMBOE, 154.9MMBOE at 2P and 171.515MMBOE at 3P. Reservoirs B and D have the highest recoverable oil at 1P, 2P, and 3P values of 5.265MMBO and 10.70MMBO, 12.053MMBO and 5.783MMBO, 13.557MMBO and 6.244MMBO, respectively.
Compartmentalization of reservoirs and technical failures experienced in data acquisition, processing and interpretation, without doubt, hinder the effective characterization of reservoirs. In this research, to ensure accuracy, three methods were integrated to characterize reservoirs in SOKAB field. Petrophysical analysis, seismic interpretation, and modeling, and rock physics analysis were utilized. Its objectives were: to develop a template to facilitate improvements in future reservoir characterization research works and producibility determination; to utilize rock physics models to quality check the seismic results and to properly define the pore connectivity of the reservoirs, and to locate the best productive zones for future wells in the field. Forty-three faults were mapped and this included five major faults. Two hydrocarbon bearing sand units (A & B) were correlated across five wells. Structural maps were generated for both reservoirs from which majorly fault assisted and dependent closures were observed. The petrophysical analysis indicated that the reservoirs have good pore interconnectivity (Average Ф effective = 23% & 22% and K average = 1754md & 2295md). The seismic interpretation and modeling alongside the petrophysical analysis were then quality checked via qualitative rock physics analysis. From the K dry /Porosity plot, the sands were generally observed to lie within the lower Reuss and upper Voigt bound which indicates a low level of compaction. From the velocity-porosity cross plot, it was revealed that the lower portions of the reservoirs were poorly cemented and this could hinder their producibility.
The study attempts to enhance the characterization of subsurface reservoirs by improving the spatial prediction of petrophysical properties through integration of petrophysical measurements and 3D seismic observations in a field in the Southern part of Nigeria. This goal is fulfilled by the use of a-priori multi-regression analysis on seismic simultaneous inversion properties, a functional relationship between measured porosity log and seismic inversion properties derived at the well location. Once derived, the relationship is applied to the inversion properties and a porosity cube is generated. Being constrained by physical properties and observations at the well, the resulting porosity estimates from inversion properties are appropriate for making reservoir management decisions. In addition, the result provides a geologically realistic spatial porosity distribution which helps to understand the subsurface reservoirs heterogeneities in the study area.
Structural interpretation and inversion analysis were used to characterize hard-to-image reservoirs, to predict subsurface interwell reservoir properties for optimum reservoir heterogeneity description, and to fine-tune drilling locations in 'DJ' Field, Niger Delta. Post-stacked 3D seismic data, composite well logs, and velocity checkshot data were used for the reservoir analysis. The study entailed mapping of structural framework, horizon picking, wavelet extraction, log editing and correlation, building of low-frequency model, acoustic impedance inversion and crossplot analysis of reservoir properties. Four major antithetic, three regional, and five minor faults were identified. The inversion results revealed an acoustic impedance range of 9700-25,000 ft/s g/cc and porosity range of 25-45% within the hydrocarbon-bearing sands. Crossplot analysis of Poisson and Vp/Vs ratio against acoustic impedance revealed Poisson ratio range of 0.30-0.45 and V p /V s ratio range of 1.3-2.50 within the delineated hydrocarbon-bearing sandstone interval. The overall correlation coefficient between the inverted and actual impedance was about 98% across the eight wells. Acoustic impedance slice at 2300 ms revealed low acoustic impedance sand within the range of 13,000-24,000 ft/s g/cc at the western and central part of the field. Comparing the acoustic impedance slice and seismic attribute maps at the target reservoir zones revealed high reflection amplitudes (bright Spots), indicative of hydrocarbon accumulation. The study predicts new and reliable drillable locations, by lithologic/fluid discrimination in the analysis of delineated reservoirs in the study area.
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