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 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.

Abstract In a pop-up salt cored, thrusted regime with a vertical relief of more than 1000m having a complex Rich Gas Condensate reservoir fluid with an underlying oil rim requires best production optimization and reservoir management techniques. The problem exacerbated if wells have complex completions, exhibit high water cut (WCT) and low gas-oil ratio (GOR). This paper presents a strategic, multidisciplinary approach implemented in this mature declining field where conventional methods alone proved insufficient due to aforementioned challenges and limited infill opportunities. The first and foremost is the identification of the problem which not only lies on Productivity Index but sometimes on Vertical Lift Performance or combination of both is critical. The innovative combination of artificial lift systems, including gas lift, coiled tubing gas lift and jet pumps, were deployed with conventional workover techniques such as bypassing damaged zones and recompletions proved vital in sustaining the production. Nodal analysis guided the selection and optimization of lift methods, tailored to the constraints of diverse well completions and reservoir attributes helped in addressing the productivity issues. The integrated effort across surface and subsurface teams enabled the successful implementation of rig-less artificial lift system implementation across multiple wells. Moreover, workovers to address reservoir damage or targeting better reservoir facies. These combined efforts resulted in a 28% increase in production and a reduction in field decline rate from 25% to 5%. This outcome not only improved well productivity and extended asset life but also accelerated cash inflows and unlocked incremental reserves. This case study demonstrates how a technically sound, cost-effective, and organizationally aligned strategy can rejuvenate mature assets and deliver measurable performance gains in challenging reservoir and production environments.