Shale Gas Plays of Lower Indus Basin Pakistan: A New Play, Key Indicators and Triggers for Phased Derisking and Exploitation

Among multiple fine-grained organic-rich siliciclastic and carbonate formations across Pakistan, the pro-deltaic to and distal marine paralic shales with sparse sand stringers within the Lower Cretaceous Sembar and Lower Goru formations offer promising Shale Gas potential in the Lower & Middle Indus Basins. The Upper Indus and kirthar & Sulaiman Fold Belts’ stratigraphies are significantly folded, faulted and fractured, whereas a large acreage with stable and relatively less faulted Lower Cretaceous stratigraphy is available in the Lower & Middle Indus basins (LIB & MIB) foreland and platform regions. In the later, four sequences have been shown to possess organic-rich source rock sequences with over-pressures. Dark grey to black mudstone with subordinate interlayers of 5-30ft thin siltstone and silty sandstone exhibit above-normal pore pressure gradients of 0.5 to 0.7 as opposed to the normal of 0.47 for the Lower Goru. The depositional setting, sedimentological and petrophysical properties compare with a sections of the Marcellus Shale in the Appalachian foredeep with distinct clinormal foresets and toe sets evident on the seismic. Lower & Middle Indus platform regions have extensive drilling and production footprint which make the acreage exceptional for Shale Gas / Tight Gas marketing and monetization. The Shale Gas Sweet spots’ mapping and geological indicators delineation has been performed based on public domain data, published papers and own analysis. Key Lower Goru plays for production pilots are: (1) Lower Basal Prodeltaic to Distal Marine Organic-rich High-Pressure HP Shale-3 as being documented here for the first is rich in Type II/III Kerogen within the lower sequence set of the Lower Basal Lower Goru formation, and (2) Talhar Shale comprising the paralic shelfal marine shales with Type II Kerogen within the back-stepped upper sequence set of Lower Goru. Within each Highstand progradational wedge comprised of the LBS Sand-3 and HP Shale-3, the bottom-sets appear as dark grey to black shale with some fissility, whereas the clinormal thicker mudstones with subordinate silt to silty sand layers appear as light grey to dark grey in color. Higher TOC and Maturity correspond to the high resistivity zones of thick dark grey to black color mudstones with subordinate silty sand and siltstone layers. Minerals include quartz, calcite, clay and chamosite or iron chlorite. Free gas saturation of 40-60% has been calculated from the logs. Canister gas analysis has been used for free gas while the Adsorption isotherms are also given in Table 1. Long and then short list of source rock and tight rock properties vis-à-vis gas/oil richness, its Frac'ability and producibility have been prepared. Based on cause & effect and root cause analysis, key indicators or success factors have been defined to establish the viability of these Plays. Several wells have encountered 800-1,500 feet thick ‘high-pressure’ shales with subordinate sand stringers in the depth range of 12,000-14,000 ft within the Lower Basal pro-deltaic and distal shale intervals. Wells Kicked and gas flares of 7-15 ft height were encountered. HP LBS Shale-3 key indicators which also act as critical factors to assess, success or viability of the Shale Gas potential fall under three broad categories: i) Geological, ii) Completion & Well Testing, iii) Commercial (including infrastructure, Policy with fiscal frameworks, Sale agreements). The geological indicators and their implications for the Completion and Well Test designs are being discussed below: 1) Shale Gas Formation Play Concept and validity of Definition "Shale Gas" Reservoir. This geological and commercial framework is key to the assessment of pre-established ‘prize’ in terms of in-place, EUR and NPV for technology players to enter the Play Fairway, 2) Stratigraphic relationships of these Plays across the basin and burial/uplift history vis-à-vis source rock maturity and generation and expulsion, 3) Discriminating the regions of predominant Type-II/III vs. Type-III/IV kerogen and the sections of favorable suitable S1 & S2, and identifying analogues or a mechanism for Type-III shale gas play, 4) In the above backdrop, discriminating the regions and sections (thicknesses) of gas with liquid vs. dry gas within the identified play fairway/ trend to make economic cut. 5) Geomechanical stratigraphy of the interval for brittleness and favorable stress anisotropy, 6) Discrimination of normal pressures vs. high and very high over-pressure regions are two other key success factors. 7) Difference of geographic scale and the extent of prize where the entire Pakistan's onshore sedimentary area is equal to the size of Texas is also key to the large enough resource size for creating economies of scale. These indicators have been structured into TDBU "screening tool" in order to screen zones and opportunities for prioritizing to run production profiles.