Abstract Sidetrack drilling in mature fractured carbonate reservoirs often encounters narrow-margin pressure windows because depleted intervals coexist with high-pressure gas zones. Conventional drilling methods in offset wells historically resulted in repeated total loss events and more than 10.5 days of non-productive time (NPT). This study demonstrates an integrated workflow combining managed pressure drilling (MPD) and active wellbore strengthening to safely navigate a 9 pcf (1.2 ppg) pressure window while maintaining well control and formation integrity. A low static mud weight of 75 pcf (10.0 ppg) polymer system was selected to minimize hydrostatic head. At the same time, dynamic surface backpressure was applied to achieve the equivalent mud weight (EMW) of 85 pcf (11.4 ppg) selected from the offset-well pressure response, where this value corresponded to the threshold above which losses initiated. Active wellbore strengthening was implemented through "stress caging" and controlled stress redistribution using sized graphite to seal microfractures and increase fracture initiation pressure. Equivalent circulating density (ECD) was continuously monitored by downhole sensors in the 6-1/8-inches bottom-hole-assembly (BHA) to enable closed-loop pressure control. Cementing parameters were engineered with a dual-slurry design (101 pcf / 13.5 ppg lead and 118 pcf / 15.8 ppg tail) to remain within the hydraulically constrained window established during drilling. The integrated approach enabled loss-free drilling of the lateral section to total depth (TD), maintaining precise pressure control within the 9 pcf (1.2 ppg) margin. By eliminating total losses, the operation saved more than 10.5 days of historical NPT. The primary cement job was completed in a single attempt with zero losses, and post-job evaluations confirmed effective zonal isolation. The results demonstrate that combining dynamic pressure control with geomechanical wellbore strengthening enables successful sidetrack drilling in conditions where conventional drilling methods had previously failed in offset wells of similar geomechanical characteristics. This work demonstrates that MPD can be applied beyond drilling as a means of supporting wellbore strengthening and primary cement placement within narrow operational margins. The combined approach of mechanical pressure control and physical fracture sealing expands the effective operating window and reduces cycle time relative to the conventional approach documented on the offset lateral. By preserving zonal isolation despite narrow geomechanical margins, this methodology offers a candidate framework for future sidetracks in mature, fractured carbonate assets, subject to further validation across additional wells.
Underbalanced drilling technology in a nutshell contrasts with conventional overbalance drilling due to fact that the bottom hole circulating pressure (BHCP) exerted by the drilling fluid is designed to be intentionally lower than the reservoir pressure. As a result of this pressure imbalance reservoir fluid oil, water or gas (contained within the pore space) is introduced into the wellbore and returns to surface along with the drilling fluid. Where upon the various different fluid streams are separated accordingly. Hydrocarbon gas may be flared off along with any nitrogen (the inert gas injected to lighten the fluid column and induce the underbalance condition). The produced liquid which may contain formation water along with oil will be separated using a 4-phase separator along with the drilled cutting. The cuttings may need to undergo further treatment to remove any residual oil in compliance with any environmental regulatory requirements before they can be adequately disposed of. The base fluid once treated can be reused. [1] Underbalance drilling was deployed across several geographies and interest in this methodology peaked during the 90s where it was combined with new drilling techniques and technologies in the form of horizontal drilling to mitigate common drilling problems such as lost circulation as well as observing productivity improvements. [2] Its use continued across brownfield developments and was deployed across unconventional reservoirs where conventional drilling techniques and reservoir evaluation methods were ineffective. Typical evaluation tools such as logging, coring and seismic that are instrumental across conventional reservoir development and characterization were inadequate in low permeability tight gas reservoirs. A shift to dynamic flow data was needed. Under Balanced Drilling (UBD) by its very essence eliminates any formation impairment uncertainty from the evaluation provided that underbalance condition is maintained throughout operations. [2]
Flow assurance remains a critical challenge in the oil and gas industry, particularly when handling emulsified injection fluids like foamy liquids (including power fluid and produce fluids). These fluids, characterized by dispersed gas bubbles, can significantly impact jet pump efficiency; widely used in artificial lift and enhanced oil recovery. This study examines the challenges associated with foamy reservoir return and injection fluids and presents strategies to optimize jet pump performance under such conditions. A series of laboratory experiments were conducted using various jet pump configurations with controlled foamy fluid injections, with chemical injection at 12 liters/day. Key parameters including providing ample residence time, gas-to-oil ratio (GOR) and injection conditions, were systematically varied to assess their impact on jet pump efficiency. Jet Evaluation and Modeling Software (JEMS) simulations were used to analyze pressure fluctuations, identify cavitation-prone zones, and refine the jet pump design. The optimized 13D Nozzle/Throat combination of jet pump configuration was selected for field implementation. Field tests revealed that increased gas production with increased production of oil posed significant challenges, including foam-induced damage to surface multiplex pump valves. Foam stability tests indicated that certain chemical injections further stabilized the foam, complicating flow assurance. JEMS simulations accurately predicted real-world performance, highlighting how foam-induced flow regime changes affected pressure profiles within the jet pump. These insights enabled targeted design modifications, leading to a significant improvement in performance. The optimized jet pump successfully restored production to 3,700 BPD at pump setting depth of 5,000 feet TVD and pump intake pressure of 1,290 psi; from a previously non-producing well and has operated efficiently for over sixteen months without issues. This study provides a comprehensive assessment of foamy injection fluids impact on jet pump performance, offering practical solutions to mitigate flow assurance challenges. The combination of anti-foaming chemicals, optimized injection parameters, and a refined jet pump design significantly reduced operational downtime and costs while maximizing production. These findings serve as a valuable reference for designing and operating jet pump systems in emulsified fluid environments.
Abstract Non-Productive Time (NPT) continues to be one of the most significant drivers of operational inefficiency in oilfield operations, directly affecting cost, service quality, and customer satisfaction. The ability to track and trend NPT has become increasingly critical, as rising NPT events and inconsistent Service Quality Incident Rates (SQIR) were observed during peak operational periods in the analyzed operating district. These fluctuations contributed to performance variability and unplanned operational costs. Any disruption in work due to NPT results in substantial financial impact, necessitating a structured analytical approach to identify root causes and implement effective mitigation strategies. A comprehensive review of operational data was conducted, including monthly job counts, SQIR, operating hours, and recorded NPT events. Statistical trend analysis, cross-correlation, and NPT track-and-trend monitoring were applied to understand the relationship between activity levels and service quality deviations. Field feedback, failure reports, and operational logs were also incorporated to identify systemic contributors such as equipment readiness, planning gaps, and procedural non-compliance. Based on these insights, targeted corrective actions were deployed, including enhanced job-preparation workflows, improved equipment inspection protocols, and reinforcement of execution discipline. Post-implementation results showed a significant reduction in both NPT% and SQIR variability across all operational quarters. NPT peaks—previously exceeding 1.49% during high-activity months—were reduced to near-zero levels in several months following the corrective actions. Notably, November demonstrated 0.00% NPT despite high operating hours, reflecting improved operational stability. SQIR also became more predictable, with fewer spikes during periods of elevated job count. These efficiency gains translated into measurable financial savings, as reduced downtime directly decreased avoidable expenditure associated with the $500-per-hour cost of NPT. The results confirm that a data-driven approach to operational diagnostics, supported by rigorous NPT tracking and trending, can materially improve service quality performance and significantly reduce customer complaints. By stabilizing SQIR and minimizing operational disruptions, the district achieved higher reliability and more consistent service delivery, even during demanding periods. These findings highlight the value of proactive analytics and process discipline in driving continuous improvement and provide a scalable framework that can be applied across similar operational environments to reduce NPT-related costs and enhance overall efficiency.
Abstract The oil industry has a variety of requirements for Oriented Perforation however the solutions are elaborated as per wellbore design and desired objectives. The oriented perforating can have simple methodology however it can also demand a sophisticated approach considering wellbore complexity and intended outcome. Indeed, having a Fiber Optic on the wellbore demands the best attention for the engineering technical solution approach. A simple oriented perforation is shown on Figure 1. In this case it is a Thru Tubing perforating with an expendable-retrievable carrier with explosives charges at zero phasing. In this case, the objective is to get maximum wellbore penetration. This is achieved only when the face of the loaded charges is adjacent to the internal diameter of the casing. There are a few options that can meet the objective. One is installing oriented magnets or position special oriented single spring- loaded arm above and below the carrier. This will work quite well in vertical wells but for highly deviated wells another more confident technique is required by using ex-centered weight bars. The phase of the oriented magnet and heaviest section of the ex-centered weight bar will have to be aligned with the face of the charge. With the single spring-loaded arm, the face of the charge should be opposite to the single arm. A top view is also displayed.
