Shaly Sand Reservoirs Research Articles

Identification of the low resistivity-low contrast (LRLC) gas-bearing pay zones in Shaly sand reservoirs using acoustic data: a case study from the Messinian Abu Madi formation, onshore Nile Delta, Egypt

Detection of the low resistivity-low contrast (LRLC) reservoirs is among the main challenges in the oil industry. In this concern, the LRLC pay zones of the Upper Messinian Abu Madi clastic reservoirs in the onshore Nile Delta Gas fields became a main challenge for significant exploration. This type of reservoirs, including low resistivity-low contrast zones and thin-bedded intervals, are often overlooked using the conventional petrophysical evaluation techniques, especially in the wildcat exploratory wells or highly agitated shoreline depositional environments like the Nile Delta of Egypt. These hidden low contrast reservoirs are generally challenging due to the presence of many shale intercalations/laminations and/or due to increasing the shale volume represented in the form of dispersed distribution, and the dominance of conductive clay minerals. Therefore, in this study, the expected high resistivity values of the gas-bearing reservoir intervals of the Abu Madi Formation in the onshore Begonia gas Field, as a typical case study of the LRLC reservoirs, are masked due to the relatively high shale conductivity, particularly when the thickness of these intervals is less than the vertical resolution of the utilized conventional resistivity log. To verify the LRLC phenomena of the Begonia gas Field, the obtained data was compared to the South Abu El Naga gas Field as a normal case study with a relatively high resistivity gas-bearing pay zone. To overcome the impact of the conductive clay mineral content and identify these hidden low resistivity reservoir intervals, it is necessary to integrate the conventional logging data (gamma-ray, shallow and deep resistivity, density, and neutron) with the acoustic log data including shear and compressional sonic data. In this way, a useful relationship can be established enabling the detection of these hidden LRLC reservoir intervals. This integration is based on the principle that shear waves are not influenced by the fluids types, whereas the compressional sonic waves are influenced by the reservoir fluids. However, to effectively investigate these concealed LRLC reservoir intervals, which can boost production and increase the potential reserves, it is essential to have a low water cut value. The present study represents introduces an efficient workflow, which can be extended to other similar LRLC pay zones in the Nile Delta and northeast Africa. It is also extendible to the LRLC reservoirs in similar deltaic systems having conductive minerals-bearing reservoirs or thin beds.

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

Assessing Cutoff Values and Evaluating Petrophysical Properties of a Shaly-Sand Reservoir with Heterogeneous Properties in a Southern Iraqi Oil Field

Spectral Gamma Ray Log-Based Shale Volume Estimation of a Gas Well, Bengal Basin

Background: Formation evaluation plays a pivotal role in identifying lithology and its depth of occurrence in gas fields. This study focuses on the Bengal Basin, aiming to achieve lithology identification and shale volume estimation in a gas well. Method: The gamma ray (GR) log is utilized to measure natural radioactivity, with spectral gamma ray (SGR) employed to capture concentrations of potassium, uranium, and thorium in clastic sedimentary formations. Lithology identification is conducted using resistivity, SGR, and GR logs, while shale volume estimation utilizes standard models including GR and true resistivity approaches. Results: The lithology of the studied well predominantly comprises clastic sedimentary rocks, specifically sand and shale. The reservoir rock type is primarily sandstone, with sand being the dominant fraction and shales appearing laminated. Concentrations of thorium, uranium, potassium, and gamma ray are approximately 12.46 ppm, 2.28 ppm, 1.73%, and 100 API, respectively. The shale volume of the gas reservoir ranges from 12% to 29%. Conclusion: The estimated shale volume provides valuable insights for assessing effective porosity and hydrocarbon saturation in shaly sand reservoirs, facilitating gas resource estimation and reservoir characterization in the sedimentary basin. This study underscores the significance of comprehensive formation evaluation techniques in optimizing reservoir management and resource extraction strategies.

Analysis of Petrophysical Parameter on Shaly Sand Reservoir by Comparing Conventional Method and Shaly Sand Method in Vulcan Subbasin, Northwest Australia

Vulcan Subbasin is an area with a lot of oil and gas exploration where is located in the Bonaparte Basin, Northwest Australia. There is some formation identified as sandstone reservoir with clay content which is usually called shaly sand based on the screening between resistivity log and density log. Clay content caused lower resistivity log readings so the shaly sand reservoir is considered as non-reservoir. To overcome this, a method besides the conventional method was applied to analyze the petrophysical parameters of shaly sand reservoir, it was shaly sand method. Petrophysical analysis is an analysis of rock physical parameters such as shale volume, porosity, and water saturation based on well log data. In this study, petrophysical analysis was carried out in the Vulcan Subbasin using 35 well log data, including gamma ray log, resistivity log, neutron log, and density log for the conventional method and shaly sand method involved Stieber equation and Thomas Stieber plot. The results obtained from this study are the comparison of petrophysical parameter values and pay summary between the conventional method and the shaly sand method, also its relation to the shale distribution type. By applying the shaly sand method, the average shale volume has decreased, the average porosity has increased, the average water saturation has increased, the average net to gross has increased, the average net thickness has increased, and the average net pay has increased. Changes in the average value were caused by laminated-dispersed shale distribution type which is influenced by diagenesis and the depositional environment of the formation.

Improved Petrophysical Property Evaluation of Shaly Sand Reservoirs Using Modified Grey Wolf Intelligence Algorithm

Improved Petrophysical Property Evaluation of Shaly Sand Reservoirs Using Modified Grey Wolf Intelligence Algorithm

3D Geological Model for Zubair Reservoir in Abu-Amood Oil Field

The Zubair reservoir in the Abu-Amood field is considered a shaly sand reservoir in the south of Iraq. The geological model is created for identifying the facies, distributing the petrophysical properties and estimating the volume of hydrocarbon in place. When the data processing by Interactive Petrophysics (IP) software is completed and estimated the permeability reservoir by using the hydraulic unit method then, three main steps are applied to build the geological model, begins with creating a structural, facies and property models. five zones the reservoirs were divided (three reservoir units and two cap rocks) depending on the variation of petrophysical properties (porosity and permeability) that results from IP software interpretation. Five wells that penetrate the lower Cretaceous Formation (Zubair reservoir) are used to construct the geological model. ZUB-1 unit considered as the most important zone which have a good petrophysical parameters about 24% for porosity, 800 md permeability, 38% water saturation and 85% net to gross. The initial oil in place is estimated to be about 1.7898*109 STB. Finally, 3D geological model support in improving and estimates the hydrocarbon potentialities in oil field and enhances the production of the field.

Petrophysical Characterization of Shaly Sand Reservoirs in Well UK-05 Eastern Niger Delta Basin, Nigeria

A petrophysical evaluation of Well UK-05 in the eastern Niger Delta Basin was carried out in order to determine reservoir zones, their porosity, permeability, fluid saturation and the effect of shaliness on the petrophysical parameters. Using interactive petrophysics software version 3.5, twenty five (25) reservoir zones were identified. The porosity values range from 15.77- 4.66% and permeability from 2.76-546.54 mD. The Archie’s, Simandoux, Dual-porosity, Waxman and Smith, and the Indonesian models were used to determine the fluid saturation. The water and hydrocarbon saturation values using the Indonesian model are 21.67-50.49% and 49.51-78.33% respectively. They slightly differ from the ones obtained using Simandoux, Dual Water and Waxman and Smith model (20.72-49.88% and 50.12- 9.22%, 18.26-50.49% and 49.51-81.74%, 14.67-48.26% and 51.74-5.33% for water and hydrocarbon saturation respectively). The interpreted lithology shows that the formation penetrated by the Well UK-05 is dominated by alternating sands and shales with the sand being the dominant lithology. These lithostratigraphic characteristics correspond to those of the parallic Agbada Formation. The effective porosity values obtained range from 14.93 to 34.66%, which are lower than 0.013% to 94.08% obtained by other authors since they did not take into consideration the effect of shaliness. This shows that the more the shale volume, the higher the uncertainty of actual porosity of the reservoir.

Gas detection technique in low resistivity pays of Lower Acacus reservoir, concession NC7A, Ghadames Basin, NW Libya

Lower Acacus Member is one of the main reservoirs in the Ghadames Basin and it is composed of alternation sandstone and shale facies. It is characterized by low resistivity multiple stacked pays, making the hydrocarbon detection task difficult. To date, no real procedure has been found to correctly define the hydrocarbon in low resistivity intervals. Gas layers as an example could be defined using density and neutron cross-over, but in shaly sand reservoirs as in this case, the shale effect on the neutron log measurement is opposite to the gas effect making the detection of the gas zone by cross-over not valid. On the other hand, the sonic log is affected by the gas by decreasing the rock density, which leads to overestimation of porosity. This phenomenon shall help diagnose the gas presence in low resistivity reservoir. Using color editor of petrophysical software enables the subdivision of log curves into horizontal intervals with specific color or shade based on certain values. Intervals with DT (90-100 msec/ft), which corresponding to 25-36% porosity unit, are shaded red. Comparing production test results with high porosity zones (red shaded on logs) proved that they are gas producers. The advantage of this procedure is that it does not need any extra measurement or calculation; it is only a way of displaying the logs. It has been applied to different gas wells in Ghadames Basin, and it shows a good result. However, this procedure is not applicable to oil pays.

Prediction of Cretaceous reservoir zone through petrophysical modeling: Insights from Kadanwari gas field, Middle Indus Basin

This study involved an interpretation of wire-line logs in assessing the hydrocarbon capacity of the sandstone reservoir within the gas fields of Kadanwari, Sindh, Pakistan. Wire-line logs from four wells (KD-01, KD-03, KD-10 and KD-11) were used in our research and provided interpretation for thirteen reservoir zones. Reservoir analyses were done for effective porosity (ϕeff), shale content (Vsh), net pay thickness variations, water saturation, and hydrocarbon (Sw and Shc). Hydrocarbon-bearing zones consist of high values of resistivity, permeability, porosity, low water saturation content, and less shale content, indicating the presence of clean sand. The Thomas Stieber model findings show that in lower Goru sand, the laminated form of shale distribution persists. Sub-reservoirs’ petrophysical parameters were analyzed and ranked into a good sand reservoir quality (having ϕeff ∼0.11-0.44%), permeability (∼10.539-477.76 mD), hydrocarbon saturation (having Shc ∼0.59-0.86%), and water saturation (having Sw ∼0.18-0.45%). In the current research Indonesian model has been used to test for water saturation over a shaly-sand reservoir situated in a heterogeneous zone. It was observed that each well exhibited Sw at values lesser than 60%. This is indicative the selected zone has a hydrocarbon potential, and the hydrocarbons are of good quality. Isoparametric maps and crossplots of litho-saturation results reveal variations in the horizontal and vertical petrophysical parameters of the reservoir. The subsurface reservoir geographical distribution is visualized employing isoparametric maps. The fuel treasure in the southwestern section of the study area is enormous, as revealed by the petrophysical investigations, suggesting more well-drilling prospects in the gas fields of the lower Goru Formation situated in Kadanwari. Our research identified a quality hydrocarbon hotspot zone of immense economic value in Southern Kadanwari. In contrast, more research is needed regarding the northeastern section though our present findings suggest the northeastern section should be avoided because of excess shale and high-water concentrations.

Formation evaluation in low resistivity low contrast (LRLC) shaly sand thin lamination; forward modeling and inversion optimization using genetic algorithm

Formation evaluation in thin bed lamination is challenging and classic petrophysical workflow would results in underestimation of true hydrocarbon pore thickness and consequently underestimation of hydrocarbon in place in oil and gas fields. Due to deficiency of conventional well logs to detect thin bed shale sand laminations, they appear as non- hydrocarbon bearing low resistivity interval on well logs. True log response cannot be recorded in thin bed shale sand lamination intervals since thickness of these layers is lower than logging tool resolution. Logging tools can only record the average log response of shale and sand together – rather than true response of sand - anywhere the thickness of each lamination falls below vertical resolution of logging tools. Forward modeling and inversion workflow was applied in a thinly laminated shaly sand reservoir to calculate true hydrocarbon pore thickness. The process of forward modeling and inversion was optimized by using Genetic Algorithm approach by developing a computer code. A new workflow for formation evaluation was proposed for formation evaluation in thin bed shale sand laminations and verified successfully. The result was fully integrated and verified with core, well log and production data. True hydrocarbon pore thickness was increased, and new perforation interval was suggested based on the findings.

Structural characterization and water saturation evaluation of a shaly-sand reservoir rocks in an onshore, Niger Delta, Nigeria

Structural characterization and water saturation evaluation of a shaly-sand reservoir rocks in an onshore, Niger Delta, Nigeria

A New Method To Estimate Resistivity Distribution Of Shaly Sand Reservoirs Using New Seismic Attributes

A subsurface resistivity model is important in hydrocarbon exploration primarily in the controlled-source electromagnetic (CSEM) method. CSEM forward modelling workflow uses resistivity model as the main input in feasibility studies and inversion process. The task of building a shaly sand resistivity model becomes more complex than clean sand due to the presence of a shale matrix. In this paper, a new approach is introduced to model a robust resistivity property of shaly sand reservoirs. A volume of seismic data and three wells located in the K-field of offshore Sarawak is provided for this study. Two new seismic attributes derived from seismic attenuation property called SQp and SQs are used as main inputs to predict the volume of shale, effective porosity, and water saturation before resistivity estimation. SQp attribute has a similar response to gamma-ray indicating the lithological variation and SQs attribute is identical to resistivity as an indicator to reservoir fluids. The petrophysical predictions are performed by solving the mathematical step-wise regression between the seismic multi-attributes and predicted petrophysical properties at the well locations. Subsequently, resistivity values are estimated using the Poupon-Leveaux (Indonesia) equation, an improvised model from Archie’s to derive the mathematical relationship of shaly sand’s resistivity to the volume and resistivity of clay matrix in shaly sand reservoirs. The resistivity modeled from the predicted petrophysical properties distributed consistently with sand distribution delineated from SQp attribute mainly in southeast, northeast, and west regions. The gas distribution of the net sand modeled by 5% and 90% of gas saturation scenarios also changed correspondingly to SQs attribute anomaly indicating the consistent fluid distribution between the modeled resistivity and SQs attribute.

Multiscale evaluation of a thin-bed reservoir

A thin-bed laminated shaly-sand reservoir of the Miocene formation was evaluated using two methods: high resolution microresistivity data from the XRMI tool and conventional well logs. Based on high resolution data, the Earth model of the reservoir was defined in a way that allowed the analyzed interval to be subdivided into thin layers of sandstones, mudstones, and claystones. Theoretical logs of gamma ray, bulk density, horizontal and vertical resistivity were calculated based on the forward modeling method to describe the petrophysical properties of individual beds and calculate the clay volume, porosity, and water saturation. The relationships amongst the contents of minerals were established based on the XRD data from the neighboring wells; hence, the high-resolution lithological model was evaluated. Predicted curves and estimated volumes of minerals were used as an input in multimineral solver and based on the assumed petrophysical model the input data were recalculated, reconstructed and compared with the predicted curves. The volumes of minerals and input curves were adjusted during several runs to minimalize the error between predicted and recalculated variables. Another approach was based on electrofacies modeling using unsupervised self-organizing maps. As an input, conventional well logs were used. Then, the evaluated facies model was used during forward modeling of the effective porosity, horizontal resistivity and water saturation. The obtained results were compared and, finally, the effective thickness of the reservoir was established based on the results from the two methods.

Comparison of modified Waxman-Smith algorithms and Archie models in prospectivity analysis of saturations in shaly-sand reservoirs. A case study of Pennay field, Niger-Delta

The presence of shales can cause severe problems for geoscientists in saturation analysis in reservoirs because of their conductivity nature. Shales are generally conductive, so as a result of this, they may consequently conceal the high resistivity distinctive of the presence of hydrocarbon in a reservoir. Shale crystals attract water that is absorbed onto the surface and some cations such as sodium Nat which are naturally surrounded by hydration water. This will result in an unexpected excessively high conductivity compared to rocks that the shale crystals are not present, and such available vacuum might else be occupied by hydrocarbon. This study evaluates a shaly-sand reservoir’s saturation properties using the Maxwan-Smith model and compares it with Archie models for shaly-sand reservoirs in the case study field. The models were coded in a MATLAB environment with users friendly graphic interface. The four shaly-sand reservoirs delineated in the Pennay field have computed net-to-gross ranges from 0.88 to 0.94. The average hydrocarbon saturation for the reservoirs is 0.60, 0.71, 0.62, and 0.59 for Archie models, while 0.64, 0.74, 0.67, and 0.62 were derived using Waxman-Smith models for reservoirs 1 to 4, respectively. A poroperm relationship of y = −0.0036 ln (x) + 0.335 was derived for delineated reservoirs. A mathematical relationship model of Swarchie = 0.88*Swmaxwan-smith + 7.7786 with R = 0.72 was developed to relate Archie to Waxman-Smith derived water saturation in the field. The inferences in this study were premised around the available data for validation of the models. Reservoir characterization using Archie’s equation in shaly-sands resulted in figures of water saturation that are spuriously high. However, the shaly-sand reservoirs delineated were significant in hydrocarbon prospecting. Application of Maxman-smith yields slightly more hydrocarbon saturation by 7% -9% more than Archie models.

Prediction of Porosity and Water Saturation Using Neural Networks in Shaly Sand Reservoirs, Western Deseret, Egypt

Petrophysical properties evaluation of shaly sandstone reservoirs is a challenging task in comparison to clean sand reservoirs. Logging derived porosity in shaly sands requires shale correction and Archie’s formula cannot be used in shaly sands for the determination of water saturation, therefore many water saturation models were proposed to get accurate water saturation of shaly sand reservoirs. In this paper, three water saturation models were used; two empirical models (Simandoux and total shale) and one theoretical model (effective medium model). Shale corrected density log was used in all models. The use of computer-generated algorithm, fuzzy log neural network is of increasing interest in the petroleum industry. This paper presents artificial neural network (ANN) as an effective tool for determining porosity and water saturation in shaly sand reservoir using well logging data. ANN technique utilizes the prevailing unknown nonlinear relationship in data between input logging data and output petrophysical parameters. Results of this work showed that ANN can be supplement or replacement of the existing conventional techniques to determine porosity and water saturation using empirical or theoretical water saturation models. Two neural networks were presented to determine porosity and water saturation using GR, resistivity and density logging data and adapted cut off for porosity and water saturation. Water saturation and porosity were determined using conventional techniques and neural network approach for two wells in a shaly sand reservoir. Neural network approach was trained for porosity and water saturation using the available well logging data. The predicted porosity and water saturation values have shown good matching with the core data in the two wells in comparison to the porosity and water saturation derived from the conventional techniques. This work showed that developed neural network (ANN) could provide an accurate porosity and water saturation in shaly sands reservoirs, it is subject to volume of available well logging data.

Modern Analogue of Shaly Sand Reservoir on Coastal Plain in Selat Baru, Bengkalis Island, Indonesia

Coastal environment is one of main reservoir depositional system in the oil industry and becomes the main challenges in defining its characteristic, especially in lateral correlation. Research conducted in Bengkalis Island which has a unique characteristic of coastal depositional environment that affected by a tidal system related to modern analogue for reservoir characterization. The method used for this research is analysing lithofacies from drilled core data, surface sampling, and lateral measurement from foreshore to the tidal limit. It is confirmed from core data that research area consists of sand, shale, and peat with lamination, cross laminations sedimentary structure and also filled with organism activity, which clustered into eight lithofacies. By integrating the core data with surface sampling and lateral measurement, it is interpreted that facies is changing only in near distance (about 30 – 40 m) with sloping 1 – 2 degrees in the surface, so by defining the same characteristic on lithofacies, correlation can clearly define on a shaly sand reservoir in the tidal coastal environment.

Plausibility of Hydrocarbon Potential Analytics of Archie’s Model by Cementation Factor Pliability in Shaly Sand Reservoir

Comprehensive comparative analyses of 18 shaly sandstone zones in four wells of an Oil Field in the Niger Delta were carried using only the Archie Model with the appropriate cementation factor from a range of 1.3 to 2.0 This was done to comprehensively analyze and statistically validate the need for the applicability of m = 1.3. Detailed statistical analysis of water saturation results of lower and upper 95% confidence intervals for the standard deviations gave the least range of 0.00415 to 0.00724 (m=1.3), 0.00660 to 0.1151 (m=1.65) and maximum of 0.00996 to 0.01747 (m=2.0). This was however validated by the bias results of the standard deviation with -0.00025 for m=1.3, -0.00040 for m=1.65 and -0.00060 for m=2. Hydrocarbon saturation results of lower and upper 95% confidence intervals for the standard also gave the least values of 0.00427 to 0.00740 (m=1.3), 0.00680 to 0.01171 (m=1.65) and 0.01031 to 0.01773 (m=2.0). The bias results of the standard deviation gave the least for m=1.3 as -0.0002, -0.00032 for m=1.65 and -0.00048 for m=2.0. Hydrocarbon movability index results of lower and upper 95% confidence intervals for standard deviation gave the least range for m=1.3 of 0.00521 to 0.00934, 0.00793 to 0.01415 for m=1.65 and 0.01155 to 0.02049 for m=2.0. The bias results of the standard deviation gave also the least for m=1.3 as -0.00031, -0.00047 for m=1.65 and -0.00068 for m=2. The study reveals that the Archie Model predictions was improved with cementation factor of 1.3 and has favourable petrophysical parameters indicating higher hydrocarbon potential than the Simandoux  and when m=1.65 and 2.0. This model is a valuable tool in a shaly sand environment after thorough validation using the pickett plot.

Log dependent approach to predict reservoir facies and permeability in a complicated shaly sand reservoir

The prediction of facies and permeability in complicated reservoirs represents a major challenge that necessitates the usage of advanced statistical techniques. A new approach is presented in this ...

A novel method to improve water saturation in shaly sand reservoirs using wireline logs

Water saturation in shaly reservoirs is a difficult task due to the heterogeneity nature of shale and the way the shale distributed in the reservoirs. So, many scientists proposed several models for water saturation in shaly sandstone reservoirs. So far, the most reliable techniques depend on identification of shale habitat qualitatively to apply suitable water saturation model, these techniques can lead to inaccurate identification of shale habitat, especially when dealing with a mixture of different shale modes and massive superimpose well logging data, and hence drastically erroneous values of water saturation and hydrocarbon reserves. Well logs and routine core analysis from two main fields in Egypt. The North Sinai and the Gulf of Suez fields are used for this study to evaluate the novel proposed method. Unlike other qualitative methods, a new robust method has been introduced to determine accurate volumes of shale distribution types. This volumetric method checked for validation and accuracy using Thomas-Stieber crossplot, the results show good and a reliable degree of accuracy. Consequently, appropriate water saturation models can apply accurately. While the dispersed shale model is adequate to estimate water saturation in dispersed shale reservoirs, water saturations for laminated shaly sand reservoirs are more complicated. So, a new approach and algorithms have been introduced to evaluate water saturation in these complex problematic reservoirs specifically in the absence of triaxial induction resistivity measurements. Furthermore, to prove the superiority of this novel method over traditional techniques, a comparative study and statistical analysis performed between the new water saturation method and conventional techniques by using InetillLog software © 2015. These comparisons and statistics show a remarkable discrepancy and variance in values between conventional methods and the new method, where water saturation values obtained from conventional methods for two fields are drastically lower than the new method. This can lead to erroneous water saturation and hydrocarbon estimations. Water saturations derived from the new method were in perfect agreement with the corresponding water saturations from cores data. Moreover, scatter diagrams between water saturation from novel method and that from core analysis obtained correlation coefficient (R2) values of 0.82, 0.85, for the North Sinai and the Gulf of Suez fields, respectively, indicating strong linear relationships. Furthermore, this new method is taken care of one of several pitfalls of LSSA interpretation method. So, this novel method adds a valuable improvement in water saturation, the assessment of hydrocarbon saturation in shaly reservoirs, continuous Net To Gross (NTG) calculations, net pay detection, reservoir simulation, and reserve estimation.

Petrophysical analysis of well logs for reservoir evaluation: a case study of “Kadanwari” gas field, middle Indus basin, Pakistan

Our study focuses on the interpretation of wire-line logs to evaluate the hydrocarbons potential of sandstone reservoir in the Kadanwari gas field, Sindh, Pakistan. We have considered wire-line logs of four drilled wells (K-01, K-03, K-10, and K-11) in the research area and interpreted 13 reservoir zones. Analytical reservoir analysis includes the shale content (Vsh), effective porosity (Oeff), hydrocarbon and water saturation (Shc and Sw), and net pay thickness variations. Hydrocarbon-bearing zone characterized by high resistivity values, porosity high, permeability high, saturation of water low, and less Vsh suggest clean sand. The petrophysical analysis revealed the hydrocarbon potential of lower Goru sandstone packages at different levels (2886–3797 m). The petrophysical parameters of sub-reservoirs were carefully analyzed which are ranked as good quality sand reservoirs with average effective porosities ranging from 0.11–0.44%, average water saturation ranging from 0.18–0.45%, hydrocarbon saturation averaging between 0.59–0.86%, and permeability ranging from 10.539 to 477.76 m Darcy. Water saturation for heterogeneous shaly sand reservoirs was successfully tested by Indonesian model which suggests that Sw in each well is fewer than 60% therefore over all the region bearing good quality of hydrocarbon potential of the targeted formation and selected zones. The vertical and horizontal variations of reservoir parameters are studied through constructing the litho-saturation cross-plots and isoparametric maps of the petrophysical parameters, respectively. The isoparametric maps help to visualize the geographical distribution of reservoir configuration in the subsurface. The petrophysical estimates of this study appraise the national conventional fuel treasure of lower Goru formation in Kadanwari gas fields and suggest new prospects to drill more wells on the central portion of the southwestern part of the study area. The neighboring area to the south of Kadanwari-01 is economically viable for hydrocarbon exploration. The northeastern side of the study area is avoided due to the high concentration of water and excessive shale content.