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Quantitative characterization of unconventional (tight) hydrocarbon reservoir by integrating rock physics analysis and seismic inversion: a case study from the Lower Indus Basin of Pakistan

Talib Maryam, Durrani Muhammad Zahid Afzal, Palekar Arshad Hussain, Sarosh Bakhtawer, Rahman Syed Atif

Acta Geophysica

2022

Vol. 70, no 6

2715--2731

The paper demonstrates a successful application of Bayesian classification method to accurately predict petrophysical properties and lithofacies classification in the deep unconventional (tight gas) hydrocarbon resource potential of early Cretaceous in the Lower Indus Basin of Pakistan. To explore the true potential for exploration and development phases, we quantitatively characterized the tight gas reservoir based on an integrated methodology using the Bayesian approach constraint with rock physics analysis which utilized deterministic petrophysical results from a well information to extract the desired lithofacies at seismic scale. The employed methodology relied on stepwise sequential integration of all available data through petrophysical, rock physics analysis and seismic inversion technique. Simultaneous inversion approach is used to invert elastic properties for reservoir interpretation. Seismic-based petrophysical properties are predicted using regression analysis by establishing a functional relationship between well logs for Sembar formation. The rock physics template (acoustic impedance versus Vs/ Vs ratio) model helped to differentiate lithological units of sand and shale in the well. Three lithofacies (HC sands, shale and shalier sand) are properly classified in rock physics template, and their probabilities are accurately defined using Bayes’ theorem. Finally, estimated lithofacies and hydrocarbon probability map from the Bayesian approach are meticulously validated from well data. The quantitative seismic reservoir characterization study provided important support for the unconventional prospect evaluation and hydrocarbon reserve estimations necessary to delineate unexplored parts which could prove helpful in effectively planning for the horizontal well placement and optimal reservoir development.

Displacement efficiency in tight sandstone based on fractional flow curve using relative permeability data

Khlaifat Abdelaziz Lafi

Journal of Geotechnology and Energy

2021

Vol. 38, no. 4

5--10

In tight gas sandstone, relative permeability is an essential special core analysis dynamic test that can be used to estimate injectivity, secondary recovery, production rate, reservoir simulation, residual gas saturation, and effective water management. Having about 65% of hydraulic fracturing fluid not to flow back and stay in the reservoir results in having the tight sandstone gas reservoir to involve multi-phase flow, namely water and gas. During the hydraulic fracturing job both imbibition and forcibly imbibition processes take place while during fracturing fluid cleanup and gas production drainage flow becomes dominant. The steady state flooding process was used to measure the relative permeability curves for a tight sandstone core sample collected from Travis Peak Formation at a depth of 8707 ft. The measurement process involved the performance of a series of steady state experiments with different gas-water injection ratios. The fractional flow curve has been plotted, based on the measured relative permeability, and used to calculate the displacement efficiency for flow through such tight porous media. The measurement showed relatively high irreducible water saturation (31%) and low residual gas saturation (6%). The measured gas relative permeability decreased slowly at a constant rate with increased wetting fluid saturation. The obtained fractional flow curve does not follow the s-shape behavior observed in a conventional reservoir. The results obtained showed that displacement efficiency can be enhanced by increasing water viscosity. Water viscosity can be increased by adding some polymer materials, however this is beyond the scope of this paper.