http://hdl.handle.net/123456789/16973 Sat, 04 Apr 2026 12:26:20 GMT 2026-04-04T12:26:20Z http://hdl.handle.net/123456789/19952 Unconventional Resource Potential Evaluation of Shale Facies of Sembar Formation, Lower Indus Basin, Pakistan Adeeb Ahmed, 01-286172-005 The escalating global energy demand has heightened interest in unconventional hydrocarbon resources, particularly shale gas and shale oil. This study evaluates 100 well cuttings and core samples of the Sembar shale facies from five exploratory wells in the Lower Indus Basin of Pakistan using novel multi-analytical techniques. While previous studies relied on screening analyses, which were insufficient to fully assess the unconventional hydrocarbon potential of the Sembar Formation, this study integrates organic and inorganic geochemistry, petrology, microscopy, vibrational spectroscopy, and basin modeling to provide a comprehensive evaluation. The aim is to extensively characterize the Sembar shale's unconventional properties, including hydrocarbon potential, paleoenvironmental conditions, mineralogy, porosity, and burial history modeling. The screening results identified 23 samples with TOC values above 2 wt.%, suggesting good unconventional potential. A total of 17 samples of the Sembar shale from Jumman Shah-1, Palari Sarki-1, and Baki Ilkin-1 were identified as EHOM deposits with TOC values exceeding 3 wt.%. The Sembar shale primarily comprises type III kerogen, with occasional occurrences of type II, type II/III, and type IV kerogen. The Sembar shale exhibits varying maturity levels (mainly late oil window), with vitrinite reflectance values ranging from 0.71 to 1.64%. Basin modeling results demonstrate significant variation in transformation ratio (TR) across wells, ranging from 11 to 80%, reflecting differences in thermal maturity and geological settings. Biomarker results indicate the higher maturity of Sembar shale and a mixture of facies with varying contributions from higher plants, algae, plankton, and bacteria deposited in marine depositional settings that were predominantly suboxic and intermittently anoxic. Microfossils such as Radiolaria, Biserial Foram, Globotruncana, and Textularia further support the marine environment. The Sembar shale is classified into aluminumrich siliceous and mixed siliceous mudrocks. It exhibits characteristics of a passive continental rift tectonic setting, primarily sourced from intermediate igneous rocks. Favorable organic matter accumulation in the Sembar shale was facilitated by warm, humid climates, along with a combination of moderate terrigenous influx, higher paleobathymetry, and increased hydrothermal activity. Bulk mineral analysis identified quartz, kaolinite, and illite as the main minerals, with other minerals including montmorillonite, calcite, dolomite, siderite, feldspar, muscovite, biotite, sericite, zeolite, gypsum, pyrite, glauconite, magnetite, hematite, rutile, zircon, and tourmaline. The Sembar shale, with a brittleness index exceeding 0.48, is suitable for fracking and contains both matrix pores (e.g., interparticle, intraparticle, and organic-matter pores) and non-matrix pores, such as natural fractures, which enhance hydrocarbon storage mechanisms. Additionally, nanopores and nanochannels are present. CT scans revealed interconnected pores with porosity ranging from 0.97 to 5.09%, further highlighting its potential for hydrocarbon extraction. Core intervals from Baki Ilkin-1 met all cut-off parameters except hydrogen index (HI). It is concluded that four sweet spots (3388- 3390 m, 3390-3392 m, 3428-3430 m, and 3464-3466 m) in Palari Sarki-1 and two sweet spots (3170-3175 m and 3410-3415 m) in Jumman Shah-1 are optimal for Sembar shale oil and shale gas extraction, respectively. This study addresses key research gaps in accurately evaluating Pakistan's unconventional hydrocarbon resources through a multi-analytical approach, providing insights that aid in devising exploration strategies for similar geological conditions in Pakistan and elsewhere. Supervised by Prof. Dr. Tahseenullah Khan Wed, 01 Jan 2025 00:00:00 GMT http://hdl.handle.net/123456789/19952 2025-01-01T00:00:00Z http://hdl.handle.net/123456789/19950 Reservoir Characterization of The Cretaceous Sandstones of Sembar Formation, Lower Indus Basin, Pakistan Furqan Aftab, 01-286172-003 The Lower Cretaceous sandstones of the Sembar Formation in the Lower Indus Basin, Pakistan, exhibit good hydrocarbon reservoir potential. However, a detailed understanding of the formation’s characteristics has been limited mainly due to insufficient critical data analysis. While studies have identified the shale gas potential of the Sembar Formation, no extensive research has been conducted to evaluate the reservoir potential of thick packages of sandstones encountered within it. This study was intended to fill this research gap for the first time by a comprehensive analysis of these sandstones. This study was important because it comprehensively integrated primary and secondary data analysis using classical and cutting-edge techniques, including machine learning and fluid inclusion studies, to reveal a range of reservoir properties from microscopic to seismic scale. Data available for this study included well cuttings, well logs, and seismic reflection data. The X-ray diffraction (XRD) analysis, petrography, scanning electron microscopy (SEM) analysis, X-ray fluorescence (XRF) analysis, inductively coupled plasma mass spectrometry (ICP-MS), inductively coupled plasma optical emission spectroscopy (ICP-OES) analyses, petrophysical modeling, rock physics analysis, seismic structural analysis, seismic inversion, multi-attribute transformation, artificial neural network (ANN) modeling and fluid inclusion studies were integrated for the assessment of reservoir quality. Five volume-based seismic attributes were sequentially calculated through forward stepwise regression. These seismic attributes were cross-validated when a Probabilistic Neural Network (PNN) was trained in a non-linear mode integrated with multi-attribute transformation, where correlation (r2) was improved from 72% to 88% between seismic attributes and porosity log. Viable prospective pay zones (up to a maximum of ~200m continuous thick sandstone package with good reservoir properties) were identified through petrophysics, rock physics, and seismic data coupled with ANN analyses. Petrographic analysis revealed that the sandstones were primarily quartz arenite, with fine to medium, subrounded to subangular grains and moderate sorting. Key diagenetic processes included quartz overgrowths and the presence of clay minerals (constituting less than 4 weight% of each sample), primarily illite-smectite and illite-mica with minor chlorite and kaolinite. Intergranular porosity was common due to the dissolution of feldspar, chert, and rock fragments, but intragranular porosity was sparse. Since sandstones of the Sembar Formation were encountered at a depth of around ~4000m, compaction and overburden pressure at such a great depth reduced its permeability. The PNN-derived porosity distribution was geologically more accurate and realistic compared with linear regression approaches and in excellent match with the porosity log, confirming the validity of the porosity model. Fluid inclusion studies have shown gas and condensate spectra in the studied wells and highlighted the temperature conditions and fluid sources associated with the development of quartz overgrowth. Fluid inclusion petrography confirmed the presence of yellow-fluorescent, moderate to upper-moderate gravity oil inclusions and non-fluorescent methane-rich gas inclusions in detrital quartz and along quartz dust rims, respectively. These findings challenged previous views of the formation as solely unconventional and offer valuable insights for geoscientists to explore both its conventional (newly recognized sandstone reservoir) and unconventional (shale gas) potential. Supervised by Dr. Mohammad Zafar Wed, 01 Jan 2025 00:00:00 GMT http://hdl.handle.net/123456789/19950 2025-01-01T00:00:00Z http://hdl.handle.net/123456789/19953 An Integrated Reservoir Characterization Study of The Cretaceous Lower Goru Tight Sands, Middle Indus Basin, Pakistan Muhammad Asif Khan, 01-286172-007 Due to the depletion of conventional reserves, understanding the unconventional resource potential of tight sands is significantly important. The successful exploitation of this resource in the Middle Indus Basin, Pakistan, has the potential to alleviate the energy crises. Characterizing the tight reservoir potential of the Lower Goru Formation in the Middle Indus Basin is challenging due to its heterogeneous nature. This study employs an integrated approach, utilizing well and seismic data, to characterize the tight sands in the Lower Goru Formation. Lab techniques, including thin-section petrography, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), and porosity and permeability measurements, were employed to understand the depositional and diagenetic processes. Permeability prediction, log-based sequence stratigraphy, heterogeneity assessment, diagenetic facies identification, and porosity and saturation evaluation in these siliciclastic reservoirs were conducted through integrated core-log petrophysical analysis. Elastic properties were computed from well logs using a rock physics approach. Porosity and permeability distribution across the reservoir were assessed using Sequential Gaussian Simulation and Gaussian Random Function Simulation algorithms. Seismic volumes were inverted into an acoustic impedance volume using Simultaneous Seismic Inversion. Authigenic chlorite and quartz cementation primarily control reservoir quality. Well-developed chlorite coatings preserved porosity and inhibited quartz cementation. In the Sawan gas field, sand-dominated delta plain/ marginal marine embayment and the middle shoreface facies exhibit tight reservoir characteristics. Tide-influenced channels, mouth bar sands, delta fringe deposits, offshore to shoreface and tide-influenced delta front facies demonstrate tight reservoir characteristics in the Kadanwari gas field. In the Miano gas field, bioturbated storm sand facies show characteristics of tight reservoirs. Core-log integration suggests that the reservoirs are deposited in the highstand system tract, and cross-plotting response of different logs leads to the identification of diagenetic facies. The Flow Zone Indicator method provides more accurate prediction of permeability in these heterogenous reservoirs. The challenges associated with the tight reservoir petrophysics can be minimized through integration of log-core, lab-based and cross-validation using rock physics approach. Rock physics indicates that the acoutic impedance of the gas sands is below 11000 kPa.s/m. The sweet spots are identified in regions where the acoustic impedance is less than 11,000 kPa.s/m. Integrated petrophysics and rock physics diagnostics indicated the tight gas sand hydrocarbon potential in the Sawan and Miano gas fields. The G sand and B sand intervals of the Kadanwari gas field, along with the B hot sands of the Miano gas field, exhibit excellent potential as tight gas reservoirs. The integration of acoustic impedance with petrophysics and rock physics identifies the C sand of the Sawan gas field as a potential sweet spot for tight gas. Similarly, in the Kadanwari gas field, the G sand and B sand intervals exhibit tight gas sweet spots. The integrated results are highly encouraging for the Miano C and B hot sands as candidates for unconventional tight gas sands. Based on the integrated reservoir characterization approach, it is concluded that the Lower Goru Formation within the Middle Indus Basin holds significant potential for tight sands exploration and development. Supervised by Prof. Dr. Tahseenullah Khan Wed, 01 Jan 2025 00:00:00 GMT http://hdl.handle.net/123456789/19953 2025-01-01T00:00:00Z http://hdl.handle.net/123456789/19951 Reservoir Diagenesis and Quality Prediction of Late Cretaceous PAB Sandstone, Lower Indus Basin, Pakistan Muhammad Nofal Munir, 01-286172-001 The recognition of intervals having promising reservoir quality in a heterogeneous reservoir from well logs is important as coring program is always not feasible as it is time-consuming and expensive. Inaccuracies can be reduced by incorporating the standardized results obtained from the well-core information for continuous and precise estimates. The goal of the study is to identify diagenetic events resulting in reduction of porosity and determining a procedure for rock type identification. In present study, inquiry regarding diagenetic controls of Pab Sandstone is carried out by the help of unified methodology, which includes thin section study, scanning electron microscopy, helium porosity and permeability, which is key hydrocarbon target in Pakistan’s Lower Indus Basin. The sandstones are quartz arenite, deduced from interpretation done through petrography and XRD analysis of core samples have shown abundance of quartz and kaolinite as the major authigenic clay mineral, cross plot analysis also showed the presence of these clay minerals. Permeability exhibited a positive correlation with increasing grain size, in the quartzose sandstones. Porosity showed a reduction with poorer sorting. Main diagenetic processes included compaction, carbonate cementation, quartz overgrowth and kaolinite. Core-derived average porosity and permeability are found to be 6.34% and 69.9 md respectively. For integration between well and core data, core-calibrated petrophysical techniques had been employed for estimation of different reservoir parameters. Characterization of porosity carried out using statistical techniques including root mean squared error and coefficient of variation. Total porosity (NDS ) has minimum root mean squared error and coefficient of variation as compared to other porosity estimates. Therefore, the computed NDS provided more accurate results of different reservoir parameters including effective porosity, water saturation, and hydrocarbon saturation compared to porosities derived from conventional petrophysics. These core-calibrated reservoir parameters are employed in cluster analysis for rock type identification defining reservoir based on quality. Rock types are described by specific log responses, which are ultimately distinguished with the help of electrofacies. The current study used cluster analysis technique for the evaluation of reservoir rock types in the identified sand units. K-means cluster analysis used to define electrofacies, which are ultimately classified into four rock types based on reservoir quality, from bad to excellent. Rock typing using cluster analysis has been done for four wells, and a correlation has been made to depict changes in electrofacies. The applied prediction technique to the studied field provides continuous rock type identification for the entire reservoir. The greater value of Young Modulus shows formation is hard rock and should respond to water frac with high injection rates. Using this methodology in defining rock type is cost-effective, requires less time in the demarcation of zones of interest, and is more accurate than manual analysis of the heterogeneous and thick Pab Formation. This assimilated work would be supportive for investigation and testing of abundant wells where core samples are not readily available. The studied approach is not only useful in the exploitation of the heterogeneous Pab Formation, but it can also be applied to other heterogeneous sandstone reservoirs elsewhere. Supervised by Dr. Mohammad Zafar Wed, 01 Jan 2025 00:00:00 GMT http://hdl.handle.net/123456789/19951 2025-01-01T00:00:00Z