Building a rock physics model for the formation evaluation of the Lower Goru sand reservoir of the Southern Indus Basin in Pakistan

The sand intervals of the Lower Goru Formation of the Cretaceous age, widely distributed in the Middle and Lower Indus Basin of Pakistan, are proven reservoirs. However, in the Sawan gas field of the Middle Indus Basin, these sandstone intervals are very deep and extremely heterogeneous in character, which makes it difficult to discriminate lithologies and fluid saturation. Based on petrophysical analysis and rock physics modeling, an integrated approach is adopted to discriminate between lithologies and fluid saturation in the above-mentioned sand intervals. The seismic velocities are modeled using the Xu–White clay–sand mixing rock physics model. The calibrated rock physics model shows good consistency between measured and modeled velocities. The correlation between measured and modeled P and S wave velocities is 92.76% and 84.99%, respectively. This calibrated model has been successfully used to estimate other elastic parameters, even in those wells where both shear and sonic logs were missing. These estimated elastic parameters were cross-plotted to discriminate between the lithology and fluid content in the target zone. Cross plots clearly separate the shale, shaly sand, and gas-bearing sand clusters, which was not possible through conventional petrophysical analysis. These data clusters have been exported to the corresponding well for the purpose of interpolation between wells and to analyze the lateral and vertical variations in lithology and fluid content in the reservoir zone.

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An integrated petrophysical and rock physics analysis to improve reservoir characterization of Cretaceous sand intervals in Middle Indus Basin, Pakistan

Petrophysical well log data help to predict hydrocarbon reserves before field development which involves huge financial commitment. In this study, reservoir characterization was performed with a view to obtain information on the geological formation type and petrophysical parameters. Wireline log data obtained from five wells were used to develop a 3D model of X-field in the Baram Delta which was in turn evaluated using the PETREL software. Suites of gamma ray, sonic, density, resistivity and neutron logs aided the delineation and correlation of the sandstone formation. Fourteen hydrocarbon-bearing sands were defined from well log data and divided into two-reservoir zones, shallow and deep. Well correlation assisted in the delineation of the reservoir sands across the wells. The quality of the reservoir formation was evaluated from average petrophysical properties: with an average thickness of 62 m, an average porosity of 0.19, an average net-to-gross ratio of 0.068, an average V-shale of 0.45, and an average water saturation of 0.95. A rollover anticline structure was identified across the field using the fault as a description tool. Variation of petrophysical parameters and uncertainty in the reservoir properties were included to predict the effect on the volume of oil in place. This study revealed that the discovered hydrocarbon reserve resource accumulations in the Field X for the fourteen-mapped reservoir sands have a total proven reserve resource estimate of 740MMSTB at P90, 655MMSTB at P50 and 593MMSTB at P10. Reservoirs A and B are the only intervals with the highest recoverable oil, a volume of 256MMSTB at P90, 215MMSTB at P50 and 181MMSTB at P10, respectively. These analyses facilitated an improved reservoir description of shaly sandstone, which contributes to better planning of hydrocarbon re-development and future recovery, and thereby improving the energy supply security of the regions.

Petrophysical interpretations of subsurface stratigraphic correlations, Baram Delta, Sarawak, Malaysia

The Mezquital Valley (MV) hosts the largest unmanaged aquifer recharge scheme in the world. The metropolitan area of Mexico City discharges ~60 m3/s of raw wastewater into the valley, a substantial share of which infiltrates into the regional aquifer. In this work, we aim to develop a comprehensive approach, adapted from oil and gas reservoir modeling frameworks, to assess water supply sources located downgradient from unmanaged aquifer recharge zones. The methodology is demonstrated through its application to the Mezquital Valley region. Geological, geoelectrical, petrophysical and hydraulic information is combined into a 3D subsurface model and used to evaluate downgradient supply sources. Although hydrogeochemical variables are yet to be assessed, outcomes suggest that the newly-found groundwater sources may provide a long-term solution for water supply. Piezometric analyses based on 25-year records suggest that the MV is close to steady-state conditions. Thus, unmanaged recharge seems to have been regulating the groundwater balance for the last decades. The transition from unmanaged to managed recharge is expected to provide benefits to the MV inhabitants. It will also be likely to generate new uncertainties in relation to aquifer dynamics and downgradient systems.

Water Supply Source Evaluation in Unmanaged Aquifer Recharge Zones: The Mezquital Valley (Mexico) Case Study

The Meyal oil field (MOF) is among the most important contributors to Pakistan’s oil and gas industry. Northern Pakistan’s Potwar Basin is located in the foreland and thrust bands of the Himalayan mountains. The current research aims to delineate the hydrocarbon potential, reservoir zone evaluation, and lithofacies identification through the utilization of seven conventional well logs (M-01, M-08, M-10, M-12, M-13P, and M-17). We employed the advanced unsupervised machine-learning method of self-organizing maps for lithofacies identification and the novel Quanti Elan model technique for comprehensive multimineral evaluation. The shale volume, porosity, permeability, and water saturation (petrophysical parameters) of six wells were evaluated to identify the reservoir potential and prospective reservoir zones. Well-logging data and self-organizing maps were used in this study to provide a less costly method for the objective and systematic identification of lithofacies. According to the SOM and Pickett plot analyses, the zone of interest is mostly made up of pure limestone oil zone, whereas the sandy and dolomitic behavior with a mixture of shale content shows non-reservoir oil–water and water zones. The reservoir has good porosity values that range from 0 to 18%, but there is a high water saturation of up to 45% in reservoir production zones. The presence of shale in the entire reservoir interval has a negative effect on the permeability value, but the petrophysical properties of the Meyal oil reservoir are good enough to permit hydrocarbon production. According to the petrophysical estimates, the Meyal oil field′s Sakesar and Chorgali Formations are promising reservoirs, and new prospects for drilling wells in the southern and central portions of the eastern portion of the research area are recommended.

https://pubs.acs.org/doi/pdf/10.1021/acsomega.2c05759

Hydrocarbon Potential Assessment of Carbonate-Bearing Sediments in a Meyal Oil Field, Pakistan: Insights from Logging Data Using Machine Learning and Quanti Elan Modeling

Conventional departures from Archie conditions for petrophysical attribute delineation include shaliness, fresh formation waters, thin-bed reservoirs, and combinations of these cases. If these departures are unrecognized, water saturation can be overestimated, and this can result in loss of opportunity. Wireline logs of four (4) wells from Apete field were studied to delineate petrophysical attributes of shaly-sand reservoirs in the field. Shale volume and porosities were calculated, water saturations were determined by the dual water model, and net pay was estimated using field-specific pay criteria. Ten sand units within the Agbada formation penetrated by the wells were delineated and correlated and their continuity was observed across the studied wells. The reservoirs had high volume of shale (Vcl), high hydrocarbon saturation, low water saturation, and good effective porosity ranging 12.50–46.90%, 54.00–98.39%, 1.61–46.0%, and 10.40–26.80%, respectively. The pay zones are relatively inhomogeneous reservoirs as revealed from the buckle’s plot except in Apete 05. The direction of deposition of the sands was thus inferred to be east west. Empirical relationships apply with variable levels of accuracy with observation of the porosity-depth, water saturation-depth, and water saturation-porosity trends. Core data is recommended for better characterization of these reservoirs.

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C. E. Nwoke

Papers

Subsurface and Petrophysical Studies of Shaly-Sand Reservoir Targets in Apete Field, Niger Delta