Middle Indus Basin Research Articles

Data-driven machine learning approaches for precise lithofacies identification in complex geological environments

ABSTRACT Reservoir characterization is a vital task within the oil and gas industry, with the identification of lithofacies in subsurface formations being a fundamental aspect of this process. However, lithofacies identification in complex geological environments with high dimensions, such as the Lower Indus Basin in Pakistan, poses a notable challenge, especially when dealing with limited data. To address this issue, we propose four common data-driven machine learning approaches: multi-resolution graph-based clustering (MRGC), artificial neural networks (ANN), K-nearest neighbors (KNN), and self-organizing map (SOM). We utilized these proposed approaches to assess their performance in scenarios with varying core sample availability, specifically evaluating their effectiveness in identifying lithofacies within the Lower Goru formation of the middle Indus Basin. The study reveals that in scenarios with a limited number of core samples, MRGC is the preferred choice, while KNN or MRGC is more suitable for larger datasets. The results demonstrate the superior performance of MRGC and KNN in lithofacies identification within the specified geological environment, with SOM following closely behind, and ANN exhibiting comparatively lower efficacy. The accurate identification of lithofacies from the selected model is complemented by the application of the truncated Gaussian simulation method for facies modeling. Comparative results confirm the excellent agreement between the model identification of lithofacies from well logs and electro-facies obtained from the truncated Gaussian simulation electro-facies volume. This study highlights the crucial role of selecting the right machine learning approach for precise lithofacies identification and modeling in complex geological environments. The comparative analysis provides practitioners in the petroleum industry with insights into the strengths and limitations of each method, enhancing existing knowledge. In conclusion, this research emphasizes the significance of comprehensive research and method selection for advancing lithofacies identification in diverse formations or study areas, ultimately benefiting the broader field of subsurface characterization in the petroleum industry.

Catchment-scale assessment of drought impact on environmental flow in the Indus Basin, Pakistan

Abstract. The impact of drought on environmental flow (EF) in 27 catchments of the Indus Basin is studied from 1980–2018 using indicators of hydrologic alterations (IHAs). The standardized precipitation evapotranspiration index (SPEI) was systematically propagated from one catchment to another using principal component analysis (PCA). Threshold regression is used to determine the severity of drought (scenario 1, drought severity that causes low flows) and the month (scenario 2, months where drought has resulted in low flows) that trigger low flows in the Indus Basin. The impact of drought on low EFs is quantified using range of variability analysis (RVA), which is an integrated component of the IHA used to study the hydrological alterations in environmental flow components (EFCs) by comparing the pre- and post-impact periods of human and/or climate interventions in EFCs. The hydrological alteration factor (HAF) is calculated for each catchment in the Indus Basin. The results show that most of the catchments were vulnerable to drought during the periods of 1984 to 1986, 1991/1992, 1997 to 2003, 2007 to 2008, 2012 to 2013, and 2017 to 2018. On a longer timescale (SPEI-12), drought is more severe in the lower Indus Basin (LIB) than in the upper Indus Basin (UIB). The IHA pointed out that drought significantly impacts the distribution of EFCs, particularly extremely low flow (ELF) and low flow (LF). The magnitude and frequency of the ELF and LF events increase as drought severity increases. The threshold regression provided useful insights, indicating that moderate drought can trigger ELF and LF at shorter timescales (SPEI-1 and SPEI-6) in the UIB and middle Indus Basin (MIB). Conversely, severe and extreme droughts trigger ELF and LF at longer timescales (SPEI-12) in the LIB. The threshold regression also divided the entire study period (1980–2018) into different time periods (scenario 2), which is useful for quantifying the impact of drought on low EFs using the SPEI coefficient. Higher SPEI coefficients are observed in the LIB, indicating high alterations in EF due to drought. HAF showed high alterations in EF in most of the catchments throughout the year except in August and September. Overall, this study provided useful insights for analysing the effects of drought on EF, especially during low flows.

Rock physics modeling to evaluate clastic reservoirs: a case study from the Lower Goru Formation, Middle Indus Basin, Pakistan

Rock physics modeling to evaluate clastic reservoirs: a case study from the Lower Goru Formation, Middle Indus Basin, Pakistan

Role of depositional and diagenetic controls on reservoir quality of complex heterogenous tidal sandstone reservoirs: An example from the Lower Goru formation, Middle Indus Basin, Southwest Pakistan

The Lower Goru Formation, one of the key hydrocarbon development targets in Pakistan's Middle Indus Basin, offers a unique opportunity to investigate the role of depositional and diagenetic controls on reservoir quality in complex stratigraphic traps. An integrated approach, including thin-section petrography, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), helium porosity, and permeability measurements, was used to analyze the Lower Goru Formation in three gas-producing fields. Based on petrographic interpretation, the sandstones are quartzarenite, sublitharenite, subarkose, and less commonly, litharenite. High permeability and high porosity reservoirs are associated with well-sorted and medium-grained sandstones. Main diagenetic processes include compaction, carbonate cementation, authigenic chlorite and quartz overgrowth. Authigenic chlorite, and quartz cementation were the principal reservoir quality controlling factors. Well-developed chlorite coatings preserved porosity and inhibited quartz cementation. Good quality reservoirs (average porosity: 17%; average permeability: 96 mD) are restricted to tidal channels and tidal inlet in the prograding shoreface environments. Transgressive and tidally reworked deposits show moderate porosity and very low permeability (average porosity: 9.5%; average permeability: 0.07 mD). Middle shoreface and bioturbated storm sands have low porosity and very low permeability (average porosity: 8.7%; average permeability: 0.9 mD) and are considered tight reservoirs. The quality of the studied reservoirs depends on quartz overgrowth, chlorite coating, carbonate cementation and minor detrital clay. Secondary porosity is associated with partial to complete dissolution of feldspar, volcanic rock fragments (VRF), biotite, chamosite ooids, and bioclast grains. This integrated work would be helpful for exploration and field development plans in the stratigraphic traps of the Middle Indus Basin and would lead to new exploration targets, i.e., tight and low permeability reservoirs. The study provides insight into the complex interplay between depositional facies and diagenesis in controlling reservoir quality in the Lower Goru Formation and similar depositional conditions and trapping mechanisms elsewhere.

Catchment-Scale Drought Propagation Assessment in the Indus Basin of Pakistan Using a Combined Approach of Principal Components and Wavelet Analyses

Abstract This study aims to comprehend the propagation of meteorological drought [expressed by the standardized precipitation evapotranspiration index (SPEI)] into hydrological drought [expressed by the standardized runoff index (SRI)] using the combined application of principal component analysis (PCA) and wavelet analysis for a period of 39 years (1980–2018) in the Indus basin, Pakistan. PCA was used to calculate principal components of precipitation, temperature, and streamflow, which were used to systematically propagate drought from one catchment to another, resulting in a catchment-scale drought assessment. The systematic propagation of drought was useful in capturing the effects of local climate variability in the 27 catchments of the Indus basin. Wavelet analyses are used to calculate the variability of SPEI/SRI and propagation (analyzed with the wavelet coherence) from SPEI to SRI. The propagation time from SPEI to SRI was cross correlated. SPEI/SRI time series showed extreme/severe droughts in 16 out of the 39 years, where relatively weak apparent wet and drought events are observed at short periods (1 month) and apparent at longer periods (6 and 12 months). Propagation from SPEI to SRI is catchment specific, with most catchments showing transition in early years (1997–2003). Propagation rate is higher in the upper Indus basin (UIB) and lower Indus basin (LIB) than in the middle Indus basin (MIB), suggesting that climate plays an important role in drought development and propagation. Results also showed a shorter and longer propagation time in the UIB and LIB, respectively. This study has helped us understand the behavior of droughts at catchment scale and will therefore help in the development of drought mitigation plans in Pakistan and similar regions around the world.

Discrimination of lithofacies in tight gas reservoir using field-specific rock physics modeling scheme. A case study from a mature field of middle Indus Basin, Pakistan

Discrimination of lithofacies in tight gas reservoir using field-specific rock physics modeling scheme. A case study from a mature field of middle Indus Basin, Pakistan

Quantitative Characterization of Shallow Marine Sediments in Tight Gas Fields of Middle Indus Basin: A Rational Approach of Multiple Rock Physics Diagnostic Models

For the successful discovery and development of tight sand gas reserves, it is necessary to locate sand with certain features. These features must largely include a significant accumulation of hydrocarbons, rock physics models, and mechanical properties. However, the effective representation of such reservoir properties using applicable parameters is challenging due to the complicated heterogeneous structural characteristics of hydrocarbon sand. Rock physics modeling of sandstone reservoirs from the Lower Goru Basin gas fields represents the link between reservoir parameters and seismic properties. Rock physics diagnostic models have been utilized to describe the reservoir sands of two wells inside this Middle Indus Basin, including contact cement, constant cement, and friable sand. The results showed that sorting the grain and coating cement on the grain’s surface both affected the cementation process. According to the models, the cementation levels in the reservoir sands of the two wells ranged from 2% to more than 6%. The rock physics models established in the study would improve the understanding of characteristics for the relatively high Vp/Vs unconsolidated reservoir sands under study. Integrating rock physics models would improve the prediction of reservoir properties from the elastic properties estimated from seismic data. The velocity–porosity and elastic moduli-porosity patterns for the reservoir zones of the two wells are distinct. To generate a rock physics template (RPT) for the Lower Goru sand from the Early Cretaceous period, an approach based on fluid replacement modeling has been chosen. The ratio of P-wave velocity to S-wave velocity (Vp/Vs) and the P-impedance template can detect cap shale, brine sand, and gas-saturated sand with varying water saturation and porosity from wells in the Rehmat and Miano gas fields, both of which have the same shallow marine depositional characteristics. Conventional neutron-density cross-plot analysis matches up quite well with this RPT’s expected detection of water and gas sands.

Reservoir Characterization and an Integrated Approach of Reservoir Modeling for Miano Gas Field, Middle Indus Basin

The hydrocarbon-bearing formation of Miano gas field belongs to the Early Cretaceous and it is bounded by two shale intervals, which are considered as maximum flooding surfaces (MFS). The hydrocarbon-bearing interval includes two reservoir units: a tight gas reservoir and its overlying conventional reservoir. Core samples, borehole logs, and well production performance revealed that the two reservoirs present reversed trends in reservoir quality through the gas field without obvious barriers. The average shale volume of the tight gas reservoir changes from 24.3% to 12.2% and the average permeability changes from 32.65 mD to 0.02 mD from the south to north. However, the average effective porosity of the overlaying conventional reservoir increases from 20% to 26% and the average permeability increases from 10 mD to 300 mD. The reversed trends in the two reservoirs lead to challenges in production forecast and development well proposals in the tight gas reservoir. Therefore, reservoir characterization and a predictive reservoir model are essential for further exploitation of Miano gas field. The geological genesis analysis integrating cores, borehole logs, and three-dimensional (3D) seismic data reveals that the producing interval of the tight gas reservoir is tidal-influenced shore facies deposition with intergranular pore space reduced by mineral cementation during burial diagenesis, while the overlaying conventional reservoir is fluvial-influenced deltaic deposition with abundant, well-connected intergranular macropores, which leads to a better reservoir quality. A reservoir model containing both the tight gas reservoir and the conventional reservoir is constructed considering the reservoir nature understanding, and the accuracy of the model is confirmed by reservoir surveillance activities with the simulation model. The study will be critical to the further reservoir development and hydrocarbon production in Miano gas field.

Analyzing the seismic attributes, structural and petrophysical analyses of the Lower Goru Formation: A case study from Middle Indus Basin Pakistan

The purpose of this research is to delineate the structures of the Lower Goru Formation, investigate fluid properties, and clarify the hydrocarbon-prone areas through seismic attributes analysis. First, the acquired data was matched by the interpretation datum. Structural analysis was done by performing horizon interpretation, fault interpretation, and contour mapping on the C-Interval of the Lower Goru Formation. Hydrocarbon zones were marked with the help of attribute analysis on seismic sections and were justified by petrophysical analysis. An integrated approach such as seismic structural interpretation, seismic attribute, spectral decomposition, and petrophysical analyses was used in current research to better understand geological structure and features. This research showed that normal faults are present in the area showing negative flower structure, horst and graben, and faults oriented north-west to south-east. The contour map shows structural inclination and faults bound closure near well locations. Variance attribute and spectral decomposition attribute were used to verify horizon lineation and fault behavior. Instantaneous amplitude and instantaneous phase attributes justify hydrocarbon bearing zones, and bright spots are present on seismic sections at C–Interval of Lower Goru Formation. Petrophysical analysis of the available wells showed a number of significant hydrocarbon zones having more than 55% of hydrocarbon saturation at the C-Interval of the Lower Goru Formation. The four possible reservoir zones in Sawan-02 well, two zones in Sawan-07 well, and three zones in Sawan-09 well are identified based on well data interpretation. Based on these analyses, the area of interest has a very good reservoir potential, structural closure, and visible bright spots. The current finding of this research will be helpful for future exploration and development of the Sawan area.

Reservoir quality and facies modeling of the early Eocene carbonate stratigraphic unit of the Middle Indus Basin, Pakistan

The early Eocene carbonate reservoir, Sui Main Limestone (SML), is the largest gas reservoir in Pakistan. In the Qadirpur area, more than 30 wells have been drilled, some of which have been declared dry or abandoned due to poor reservoir characteristics or facies variation. The aim of this work is to re-evaluate the reservoir characteristics and facies identification of Sui Main Limestone by using petrophysical analysis and rock physics modeling in the Qadirpur field in the Middle Indus Basin of Pakistan. The reservoir characterization of carbonate rocks is difficult because of their complex pore networking. The well data on five exploratory wells drilled in this gas field are used. The log-derived porosity varies in a very large range of 2%–36%, with an average of 14%–34%. The average porosity of the clean carbonate intervals is 10%–14% and thus has the capacity to accumulate hydrocarbon. The high porosity value indicates the presence of micro-fractures in Sui Main Limestone. These micro-fractures and secondary pores are well interconnected and allow the pore fluids to communicate. The secondary porosity is mainly due to the presence of vuggs and fractures in Sui Main Limestone. The volume of shale varies from 11%–38% in the wells. The net pay zones have hydrocarbon saturation in the range of 40%–70%, which is mainly gas. Using wireline log response, the formation is divided into three facies: limestone, shale, and shaly limestone. This comprehensive work may help improve the prediction of the reservoir quality in heterogeneous carbonate reservoirs and optimize field development.

Petrophysics based Reservoir Evaluation of the Cretaceous Lower Goru “C” Sands, Middle Indus Basin, Sindh, Pakistan

This study demonstrates the reservoir investigation of the Cretaceous Lower Goru “C” sand interval using exploratory well data from the middle Indus basin of Sindh. The petrophysical parameters including volume of shale, effective porosity, and water saturation of the investigated reservoir interval were calculated. The shale volume calculation results in 30–35% of non-clean (shale) lithology, which is high as compared to Sawan-01 and Sawan-08 wells. The effective porosity ranges from 12–16%, while the average value of water saturation in the complete interval of “C” sand falls in the range of 50–60%. However, certain zones with relatively lower water saturation values of around 30-50% are also observed. These zones are considered better pay zones in comparison to the other intervals. A “gas effect” phenomenon observed on cross plots represents the area of neutron-density cross-over indicating the presence of lighter hydrocarbons in this reservoir zone interval.

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.

Three-Dimensional Structural Modeling (3D SM) and Joint Geophysical Characterization (JGC) of Hydrocarbon Reservoir

A complex structural geology generally leads to significant consequences for hydrocarbon reservoir exploration. Despite many existing wells in the Kadanwari field, Middle Indus Basin (MIB), Pakistan, the depositional environment of the early Cretaceous stratigraphic sequence is still poorly understood, and this has implications for regional geology as well as economic significance. To improve our understanding of the depositional environment of complex heterogeneous reservoirs and their associated 3D stratigraphic architecture, the spatial distribution of facies and properties, and the hydrocarbon prospects, a new methodology of three-dimensional structural modeling (3D SM) and joint geophysical characterization (JGC) is introduced in this research using 3D seismic and well logs data. 3D SM reveals that the field in question experienced multiple stages of complex deformation dominated by an NW to SW normal fault system, high relief horsts, and half-graben and graben structures. Moreover, 3D SM and fault system models (FSMs) show that the middle part of the sequence underwent greater deformation compared to the areas surrounding the major faults, with predominant one oriented S30°–45° E and N25°–35° W; with the azimuth at 148°–170° and 318°–345°; and with the minimum (28°), mean (62°), and maximum (90°) dip angles. The applied variance edge attribute better portrays the inconsistencies in the seismic data associated with faulting, validating seismic interpretation. The high amplitude and loss of frequency anomalies of the sweetness and root mean square (RMS) attributes indicate gas-saturated sand. In contrast, the relatively low-amplitude and high-frequency anomalies indicate sandy shale, shale, and pro-delta facies. The petrophysical modeling results show that the E sand interval exhibits high effective porosity (∅eff) and hydrocarbon saturation (Shc) compared to the G sand interval. The average petrophysical properties we identified, such as volume of shale (Vshale), average porosity (∅avg), ∅eff, water saturation (SW), and the Shc of the E sand interval, were 30.5%, 17.4%, 12.2%, 33.2% and, 70.01%, respectively. The findings of this study can help better understand the reservoir’s structural and stratigraphic characteristics, the spatial distribution of associated facies, and petrophysical properties for reliable reservoir characterization.

Structural analysis and seismic stratigraphy for delineation of Neoproterozoic-Cambrian petroleum system in central and eastern part of Bikaner–Nagaur basin, India

Bikaner–Nagaur basin is located in the northwestern part of India and lies on the rising flank of Punjab platform of Middle Indus basin in Pakistan. Existence of Neoproterozoic-Cambrian petroleum system was confirmed by the exploration activities in the western periphery of the basin, whereas vast areas of central and eastern parts remain unexplored. Knowledge of petroleum system in this unexplored part of the basin is limited due to non-availability of data. Recently, 2525 line km of regional 2D seismic data acquired for the first time by Government of India under National Seismic Program (NSP) unlocks the opportunity for comprehensive understanding of subsurface geology in unexplored part of the basin. Present work aims to interpret recently acquired 2D seismic data and integrate with available surface (outcrop) data, gravity and well data (drilled in western part of basin) for unfolding the petroleum system elements, structural configurations and stratigraphic features in the hitherto central-eastern part of the basin. Two Neoproterozoic-Cambrian hydrocarbon plays: (1) Jodhpur and (2) overlying Bilara/Hanseran Evaporite Group (HEG) were envisaged. Both the plays depicted distinctive seismic characteristics, structural alignment and distribution of reservoir, source and seal. Fluvio-deltaic sandstone within Jodhpur group and shallow marine fractured dolomites within Bilara/HEG showed potential reservoir characteristics whereas organic rich laminated dolomites, stromatolites and argillaceous litho-units within Bilara/HEG group have been predicted as prospective source. The Halite layers within HEG group were considered as effective regional seals. Fault bounded anticlinal structures associated with Cambrian compression have been identified as the main entrapment for hydrocarbon accumulation. The basin witnessed long tectonostratigraphic history with two major compressional phases Structures formed by Cambrian compression are likely to be charged as the time of source maturity and peak expulsion was later, during early Mesozoic period. Overall, the study indicates new opportunities and potential accumulation of hydrocarbon in the unexplored part of the basin.

An integrated approach to evaluate the hydrocarbon potential of Jurassic Samana Suk Formation in Middle Indus Basin, Pakistan.

The Indus Basin is considered as prolific hydrocarbon-bearing province of Pakistan. The study area is located in the Middle Indus Basin. Two wells (Bagh-X-01 and Budhuana-01) were drilled in the vicinity of the study area to determine the hydrocarbon potential of the area. Both wells show no hydrocarbon reserves and are thus abandoned. The present study emphasizes two-dimensional subsurface seismic interpretation and rock physics evaluation to estimate reservoir properties of the Jurassic Samana Suk Formation. Data from nine 2-D seismic lines and two wells have been utilized to evaluate the potential. The time contour maps indicate the existence of subsurface structural features in the study area. With the help of the 3-D geological model, the faults are marked in the Samana Suk Formation and the structure is identified as a monocline. The 3-D geological modeling results also reveal that Samana Suk Formation tends to become thin in the northeast, and thick in the southwest. The petrophysical interpretation was performed to find the hydrocarbon potential of the Formation. The cross plot between P-impedance and Vp/Vs ratio shows that the lithology cannot be differentiated by the logs. Rock physics parameters such as Poisson’s ratio, bulk modulus, shear modulus, shear wave velocity, primary wave velocity, Vp/Vs ratio, and density indicate that there are no considerable hydrocarbon reserves in the Samana Suk Formation.

Characterization of carbonate reservoir using post-stack global geostatistical acoustic inversion approach: A case study from a mature gas field, onshore Pakistan

Seismic characterization of carbonate reservoir is a challenging undertaking for geo-scientists due to their complex depositional settings, internal structure, and pervasive diagenetic history. Results from post-stack deterministic inversion are band limited due to missing low and high frequencies in the wavelet, which generally poorly resolve thin beds which are of prime interest in reservoir characterization of a mature gas field and help locate prolific infill drilling locations. In this paper, we employed and compare performance of Post-stack Global Geostatistical Acoustic Inversion (PGGAI) with the Post-stack deterministic inversion to better characterize thin beds and maximize reservoir potential of Eocene (S1) carbonate reservoir from a mature gas field lying in the Middle Indus Basin, onshore Pakistan. We discovered that both the inversion methods derive a broad-band acoustic impedance from the band-limited post-stack seismic data. The results show that PGGAI produced high resolution (thin bedding) p-impedance attribute and mapped spatial distribution variations along with uncertainty quantification hitherto not possible from standard deterministic inversion approach and therefore result in possible increasing confidence in the interpretation. Furthermore, high resolution p-impedance attribute from PGGAI served as input for porosity prediction using probabilistic neural networking (PNN). Stepwise validation of PNN provided high precision porosity estimation which showed significant amount of correlation between the input attribute property. In addition, high resolution volumes offered optimistic scenarios of the distribution of impedance and porosity lateral extent and helpful in determining perspective zones and proved useful in designing the subsequent reservoir management plan and proposing future infill drilling locations.

Source Rock Potential of Chichali and Samana Suk Formations Deposits in Panjpir Oilfield Subsurface, Punjab Platform, Pakistan

By using total organic carbon (TOC) and Rock-Eval pyrolysis analysis measurements, the hydrocarbon source rock potential of Chichali and Samana Suk formations found in the subsurface of Panjpir oilfield in Punjab platform located in the eastern part of the middle Indus Basin was investigated. Twenty two core samples were collected from producing well. The analysed samples of Chichali formation contains TOC ranging between 0.99-4.61 wt.% having average TOC of 1.51 wt.% and the S2 values of Rock-Eval show the poor to fair generative potential with values ranging from 0.99-3.08 mg HC/g rock. The samples have low hydrogen index values ranging from 21-302 mg HC/g TOC and also most of the samples have low T_(max ) values ranging from 422-432 °C and have OI values ranging from 15-82 mg CO2/g TOC. Samana Suk formation samples have TOC ranging between 0.28-1.38 wt.% having average TOC of 0.84 wt.%. S2 values of Rock-Eval shows poor generative potential with values ranging from 0.05-2.99 mg HC/g rock. The samples have low hydrogen index values ranging from 13-322 mg HC/g TOC and T_(max) values ranging from 423-435 °C, and have OI values ranging from 41-182 mg CO2/g TOC. On the basis of analysis performed only one sample from Chichali and five samples of Samana Suk formations have entered early maturity zone, while all remaining samples lie in immature zone as indicated by HI vs T_(max) plot. HI vs OI plot and HI vs T_ (max) indicates the presence of kerogen Type III. All of the samples from Samana Suk formation shows poor generative potential as compared to Chichali formation having fair generative potential as indicated by S2 vs TOC plot. Hence, from the results some minor gas could be expected to have been generated from Chichali formation in Panjpir oilfield subsurface.

Predicting the gas resource potential in reservoir C-sand interval of Lower Goru Formation, Middle Indus Basin, Pakistan

Abstract The integrated study of seismic attributes and inversion analysis can provide a better understanding for predicting the hydrocarbon-bearing zones even in extreme heterogeneous reservoirs. This study aims to delineate and characterize the gas saturated zone within the reservoir (Cretaceous C-sand) interval of Sawan gas field, Middle Indus Basin, Pakistan. The hydrocarbon bearing zone is well identified through the seismic attribute analysis along a sand channel. The sparse-spike inversion analysis has efficiently captured the variations in reservoir parameter (P-impedance) for gas prospect. Inversion results indicated that the relatively lower P-impedance values are encountered along the predicted sand channel. To further characterize the reservoir, geostatistical techniques comprising multiattribute regression and probabilistic neural network (PNN) analysis are applied to predict the effective porosity of reservoir. Comparatively, the PNN analysis predicted the targeted property more efficiently and applied its estimations on entire seismic volume. Furthermore, the geostatistical estimations of PNN analysis significantly predicted the gas-bearing zones and confirmed the sand channel as a major contributor of gas accumulation in the area. These estimates are in appropriate agreement with each other, and the workflow adopted here can be applied to various South Asian regions and in other parts of the world for improved characterization of gas reservoirs.

Experimental study and modeling of water-based fluid imbibition process in Middle and Lower Indus Basin Formations of Pakistan

Wellbore instability is one of the major problems that arise in drilling shale formations. Drilling in these formations may lead to breakouts and induce fractures. In Pakistan, drilling companies face quiet a number of formations that are shaly in nature and are candidates for wellbore instability issues. To counter these issues, it is required to have good understanding about the composition of the shale and its chemical reactivity with drilling fluids. Shale samples of three different formations have been obtained. These samples belong to two different regions of Indus Basin of Pakistan and were subjected to cation exchange capacity test and X-rays diffraction analysis to determine the reactivity and mineralogy, respectively. The samples were then tested for swelling properties using linear dynamic swell meter. The testing was done in two different water-based drilling fluids. The increase in height and swelling percentage for each sample was then recorded against each type of drilling fluid. A comparative analysis was done as to what type of drilling fluid systems out of the two used in the swelling test would best inhibit the swelling nature of shale for each formation in these regions of Pakistan. Finally, analytical and numerical modeling was performed on each shale sample. It was observed that the swelling parameter A (total swelling) increases significantly for Middle Indus Basin Shale Formation, and on the contrary, the filtration term (C) becomes independent of time after certain period of testing.

Characterization and probabilistic estimation of tight carbonate reservoir properties using quantitative geophysical approach: a case study from a mature gas field in the Middle Indus Basin of Pakistan

In this study a tight carbonate gas reservoir of early Eocene (S1 formation) is studiedfor litho-facies estimation and probabilistic estimation of reservoir properties predictionusing quantitative geophysical approach from a mature gas field in the Middle IndusBasin, onshore Pakistan. Quantitative seismic reservoir characterization approachrelied on well based litho-facies re-classification, Amplitude Variation with Offset (AVO)attributes analysis and Pre-Stack simultaneous inversion attributes constrained withcustomized well-log and seismic data (gathers) conditioning. Three main litho-facies(hydrocarbon bearing limestone, tight limestone and shale) are classified estimatedbased on the precise analysis of well data using petrophysical properties. AVOattributes (intercept and gradient) conveniently inspection for amplitude behavior(reflection coefficients) of the possible AVO (class I), fluids and lithologycharacteristics. Probable litho-facies (tight limestone and shale) are estimated usingwell based litho-facies classification and inverted seismic attributes (p-impedance anddensity) from pre-stack simultaneous inversion in a Bayesian framework. Additionally,petrophysical properties (clay volume and porosity) are derived from probabilisticneural network approach using well logs and pre-stack inverted attributes (pimpedanceand density) constrained with sample-based seismic attributes(instantaneous, windowed frequency, filters, derivatives, integrated and time).