Pakistan Petroleum Limited

Abstract Water production in mature, multilayered sandstone gas reservoirs remains a critical challenge, often severely limiting hydrocarbon recovery and operational efficiency. Conventional mechanical plugs and permanent cementing techniques frequently fail under depleted reservoir conditions due to narrow inter-perforation spacing, low formation strength, and uncontrolled fluid losses. This study presents a comprehensive approach combining acid-soluble cement plugs, calcite-based isolation systems, and coiled tubing deployment guided by reservoir diagnostics and laboratory-validated fluid designs. Two field cases from the Lower Indus Basin, Pakistan, are detailed. In the first well, an acid-soluble cement plug was deployed to isolate water-producing lower perforations while preserving upper gas-bearing intervals. In the second well, a dual-barrier strategy combining a calcite-based plug via coiled tubing and a cement plug via wireline dump bailer was used to hydraulically isolate a severely depleted lower interval. Post-job diagnostics, including production logs, pressure monitoring, and flowback evaluation, confirmed successful isolation, with water production reduced by more than 95% and gas deliverability restored up to fourfold. These results demonstrate the value of targeted, reservoir-specific design, integrated fluid and mechanical systems, and precise operational execution for achieving reliable zonal isolation and production enhancement in depleted multilayered sandstone reservoirs.

Abstract Exploratory Well-A, drilled in one of the blocks of Pakistan’s Lower Indus Basin, set new performance benchmarks in drilling efficiency, cost optimization, and well integrity. The primary objective was to deliver the well safely and economically in a challenging drilling environment by integrating slim-hole design, optimized mud formulation, advanced bit and BHA technology, and real-time drilling practices without compromising well integrity. The case study highlights a holistic approach that reduced well delivery time and costs while ensuring long-term wellbore stability and zonal isolation. The well was designed with a slim-hole two-string casing program (12-1/4″ → 8-1/2″), reducing drill cutting volume and cement requirements, which directly lowered consumable costs and improved hydraulic efficiency. Pre-drill planning included risk assessments, simulations, and contingency measures to minimize operational down time. XRD/CEC-based mineralogical analysis from an offset well guided the optimization of a polymer water-based mud system, reducing KCl concentration from 7% to 3% while maintaining wellbore stability. A tailored drilling assembly strategy employed high-performance PDC bits, specialized drilling motors, and a latest generation rotary steerable system (RSS) to maximize rate of penetration and trajectory control. Real-time data monitoring, hydraulic optimization, and proactive flat-time reduction measures, including reaming-while-casing, ensured efficient casing runs. Finally, 7" Expandable Casing Packers (ECPs) were installed for the first time in open hole environment in PPL operated well to achieve zonal isolation across stacked reservoirs. Well-A reached total depth in 10.2 days, achieving a 44% reduction in dry hole time and 41.7% cost savings compared with the Approved for Expenditure (AFE). The well-established new block-best record of 12.4 days/3000 m, outperforming the previous 22.4 days/3000 m benchmark. Mud optimization reduced chemical costs by 37% compared with the offset well, while advanced bit and BHA selection delivered superior ROP and durability in complex formations, comprising of heterogenous and abrasive lithologies. Flat-time minimization eliminated unnecessary condition trips and accelerated casing operations. Cementing execution provided effective zonal isolation, confirmed by cased-hole logs, while the open-hole ECP deployment successfully prevented crossflow between stacked reservoirs intervals. This case study documents the successful implementation of a slim-hole two-string architecture, mineralogy-informed mud optimization, and open-hole ECP deployment in a slim annulus environment. The integration of innovative drilling technologies with real-time operational optimization delivered step-change efficiency and cost savings while strengthening long-term well integrity. The experience of this well provides a replicable framework for operators seeking to maximize value in exploration and development campaigns under cost-sensitive and technically demanding conditions.

Abstract Maintaining wellbore stability and avoiding differential sticking in HPHT wells becomes increasingly challenging when narrow and conflicting pressure regimes coexist across the open hole. This challenge was encountered during the execution of a 7-in liner in a 35° inclination well drilled to 5,400 m MD under HPHT conditions, with bottomhole temperatures approaching 150 °C. The well penetrated highly permeable, unexpectedly low-pressure (1.33 SG) limestone sequences of Formation-C and Formation-S, followed by the high pressure (breakout pressure of 1.47 SG) shale-dominated Formation-N. The sharp pressure contrast, combined with differing formation characteristics, resulted in an effectively non-existent static pressure window. This environment had previously led to two incidents of BHA differential sticking during drilling operations. Running the liner posed a significantly higher sticking risk than drilling assemblies due to increased wall contact, extended stationary periods during connections, and slower pipe movement. Conventional mud weight selection, mud treatments, and operational practices were insufficient to simultaneously mitigate differential sticking in the highly fractured limestone while maintaining stability in the high-pressure shale formation beneath. To address these challenges, an unconventional MPD-assisted approach employing variable bottomhole pressure (BHP) was adopted, specifically tailored for liner deployment to manage the competing requirements of differential sticking mitigation and shale stability. Prior to entering open hole with the 7-in liner, a higher BHP equivalent to 1.47 SG was maintained throughout while running inside casing. Once in open hole, two distinct BHP setpoints were applied. A reduced BHP of 1.40 SG was maintained during stationary periods for connections, resulting in lower differential pressures than those derived from Formation-N and remaining below its optimal stability requirement for short durations. Formation fingerprinting data acquired during drilling confirmed limited flow potential from the shale interval Formation-N and a low risk of instability during brief exposure to reduced pressure, allowing controlled relaxation of annular pressure without compromising well integrity. During pipe movement, a higher BHP of 1.47 SG was then maintained, with continuous movement providing additional mitigation against differential sticking at elevated pressures. The liner was successfully run to bottom without sticking, and all liner hanger setting operations were performed under MPD with controlled annular pressure exposure. Cementing was executed at an elevated bottomhole equivalent circulating density to mitigate gas invasion risk, with liner rotation applied to improve displacement efficiency and circumferential cement coverage. Cement displacement, liner top packer setting, and subsequent operations were completed without incident. A successful negative pressure test was achieved, and cement bond evaluation confirmed acceptable zonal isolation.

Abstract The exploration and characterization of the Indus Offshore Basin, Pakistan's largest sedimentary basin, have been historically limited by sparse data and inconsistent stratigraphic definitions. The absence of an established single offshore stratigraphy poses a significant challenge in geological correlation and reservoir characterization. These constraints have hindered a comprehensive understanding of its petroleum geology, reservoir potential, and basinal architecture, despite its geological continuity with the Sindh Monocline (Thar Platform and Karachi Trough) and the Kutch Basin, which indicate substantial hydrocarbon prospects. To address these challenges, a comprehensive study of 24 wells: including well logs, biostratigraphy, mud logs, seismic profiles, and literature, was conducted under the supervision of PPL. A unified stratigraphic framework was developed, bridging onshore (Binari X-1) and offshore regions using key marker beds such as the Deccan Traps and a Cretaceous volcanic horizon, enabling consistent well to well correlations. Building on this framework, advanced petrophysical and rock physics analyses, both conventional and machine learning-based, were performed to validate lithologies, establish elastic properties, and compensate for missing or poor-quality logs, thereby enhancing seismic to well ties and reservoir characterization. The study further employed 1D basin modeling (PakCan-1) and 2D modeling along NS-trending geoseismic profiles, which identified the shallow shelf as the most prospective zone, with the Sembar and Goru Formations emerging as key source rocks based on geochemical maturity. This integrated approach reduces exploration uncertainty, optimizes well placement, supports basin modeling and geomechanical analysis, and updates economic assessments. Ultimately, the study transforms the Indus Offshore Basin from a fragmented dataset into a geologically coherent and commercially viable exploration potential, enhancing volumetric assessments and supporting Pakistan's long-term energy security goals.