Land-Use/Land Cover Changes Contribute to Land Surface Temperature: A Case Study of the Upper Indus Basin of Pakistan

Land-use/land cover (LULC) changes have an impact on land surface temperature (LST) at the local, regional, and global scales. To simulate the LULC and LST changes of the environmentally important area of northern Pakistan, this research focused on spatio-temporal LULC and associated LST changes since 1987 and made predictions to 2047. We classified LULC from Landsat TM and ETM data, using the maximum probability supervised categorization approach. LST was retrieved using the Radiative Transfer Equation (RTE) methodology. Furthermore, we simulated LULC using the integrated approaches of Cellular Automata (CA) and Weighted Evidence (WE) and used a regression model to predict LST. The built-up areas and vegetation have increased by 2.1% and 11% due to a decline in the barren land by −8.5% during the last 30 years. The LULC is expected to increase, particularly the built-up and vegetation classes by 2.74% and 13.66%, respectively, and the barren land would decline by −4.2% by 2047. Consequently, the higher LST classes (i.e., 27 °C to <30 °C and ≥30 °C) soared up by about 25.18% and 34.26%, respectively, during the study period, which would further expand to 30.19% and 14.97% by 2047. The lower LST class (i.e., 12 °C to <21 °C) indicated a downtrend of about −41.29% and would further decrease to −3.13% in the next 30 years. The study findings are useful for planning and management, especially for climatologists, land-use planners, and researchers in sustainable land use with rapid urbanization.

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.

Optimization of hydraulic fracturing treatment in tight sand reservoir of lower indus basin: an integrated approach

An approach for post-frac production profiling has been presented in this study by integrating a fracture model with a reservoir simulation model for a well drilled in tight sand reservoir of Lower Indus Basin in Pakistan. The presented integrated approach couples the output from the fracture growth model with a reservoir simulation model to effectively predict the behavior of a fractured reservoir. Optimization of hydraulic fracturing was done efficiently through the work presented in this study. The integrated model was used to perform various sensitivities. The production profiles obtained for each case were subsequently used to determine the most profitable case, using an economic model.

Indus Water Treaty: Challenges and Prospects

The growing water scarcity in India and Pakistan and emerging climatic and environmental changes to the Indus basin rivers system are causing a great stress on smoothing working of Indus water treaty 1960. Pakistan Being a lower riparian, facing the issue as to how to reinterpret the Indus Waters Treaty without giving up its water rights. The paper discusses that following the inbuilt constraints of a lower riparian, Pakistan need to adopt a multi-pronged strategy following water rationale to secure its water rights within the scope of the treaty. For this; effective implementation and enhancement of Article VI, VII, constructive diplomatic and political strategy,efficient water uses and sustainable water resource management in Indus-Pakistan.

Gas-bearing sands appraisal for Zamzama Gas field in Pakistan through inverted elastic attributes assisted with PNN approximation of petrophysical properties

The Pab Formation of Zamzama block, lying in the Lower Indus Basin of Pakistan, is a prominent gas-producing sand reservoir. The optimized production is limited by water encroachment in producing wells, thus it is required to distinguish the gas-sand facies from the remainder of the wet sands and shales for additional drilling zones. An approach is adopted based on a relation between petrophysical and elastic properties to characterize the prospect locations. Petro-elastic models for the identified facies are generated to discriminate lithologies in their elastic ranges. Several elastic properties, including p-impedance (11,600-12,100 m/s*g/cc), s-impedance (7,000-7,330 m/s*g/cc), and Vp/Vs ratio (1.57-1.62), are calculated from the simultaneous prestack seismic inversion, allowing the identification of gas sands in the field. Furthermore, inverted elastic attributes and well-based lithologies are incorporated into the Bayesian framework to evaluate the probability of gas sands. To better determine reservoir quality, bulk volumes of PHIE and clay are estimated using elastic volumes trained on well logs employing Probabilistic Neural Networking (PNN), which effectively handles heterogeneity effects. The results showed that the channelized gas-sands passing through existing well locations exhibited reduced clay content and maximum effective porosities of 9%, confirming the reservoir's good quality. Such approaches can be widely implemented in producing fields to completely assess litho-facies and achieve maximum production with minimal risk.

Organic geochemistry and mineralogical characterization of the Paleocene Ranikot Formation shales in selected areas of Southern Indus Basin Pakistan.

Southern Indus Basin is one of the promising regions in Pakistan as a commercially producing oil and gas perspective. The current research presents the geochemical characterization of the Ranikot Formation shales from Southern Indus Basin based on total organic carbon (TOC), Rock-Eval (RE) pyrolysis, organic petrography, gas chromatography-mass spectrometry (GC-MS), and x-ray diffraction (XRD) analyses. The average TOC of Ranikot shale is 4.6 wt. %, indicating very good hydrocarbon potential. Types III/IV kerogens were identified in Ranikot shale. The maceral data also suggest that the Type of kerogen present in Ranikot shale is dominantly Types II-III, with the minor occurrence of Type IV. The vitrinite reflectance, pyrolysis Tmax and methylphenanthrene indices values specify immature levels of the shales. The normal alkane data reflect that marine macrophyte, algae, and land plants were contributed to the organic matter of Ranikot shales. Dibenzothiophene/phenanthrene ratio (0.11), phytane/n-C18 ratio (0.53), pyrite, and glauconite elucidate that the depositional environment of the Ranikot shale is marine. The XRD analysis of the shale from the Ranikot Formation revealed that it is brittle shale and dominated by 39.5 to 50.9 wt. % quartz. The present study, integration with the US EIA report demarcated the Ranikot Formation influential horizon as a shale gas resource.