A mechanical earth model was constructed for an oilfield in Kuwait that has a history of borehole related problems and prone to significant non-productive time in the highly deviated wells, the typical sidetrack wells took more than 100% of the time compared to the low deviated wells. The field is geologically complex, tectonically stressed with faults, fractures, unstable shales and anomalous pore pressures. Wells drilled within the structure are highly deviated with trajectories that almost parallel reservoir bedding planes, and that are aligned with the direction of minimum geomechanical stress. A comprehensive study was conducted to better understand the stability issues and to investigate the feasibility of drilling numerous additional high deviation wells. Data from selected offset wells was collated, analyzed and combined with field and regional information to construct a geological model which could then be used to predict and mitigate drilling related problems. The equivalent mud weight is arguably the most critical drilling variable and an element of the new plan would take account of stress dynamics and formation strengths to develop a mud program for vertical and horizontal sections. A geological model was developed using data from offset wells combined with field and regional knowledge. Well logs, mud logs and operational reports were analyzed, while unstable zones and failure mechanisms identified and incorporated into the earth model. A well plan was developed which included a comprehensive mud program and operational contingency actions for unplanned events. The planned well was drilled and monitored in real time, with emphasis on mud weight and mud rheology through the unstable and reactive shales. Multiple failure mechanisms such as stress induced wellbore instability, invasion of drilling fluids into weak bedding / micro-fractures and osmotic sensitivity, were found to be the root cause of wellbore instability across reactive shale formations especially during drilling of highly deviated wells. Correct mud weight and type prediction was one key factor during the drilling stage to keep the wellbore stable and deliver good borehole geometry, including the water phase salinity and fluid properties. The key objectives of the study were to define a safe MW program for the vertical and deviated sections of the planned well by conducting a wellbore stability study and to determine a real-time strategy to mitigate or manage wellbore instability problems as they arise. The paper describes the process of optimizing drilling practices and the application of real-time geomechanical monitoring for successful drilling. This application promises to open the prospect of drilling additional complex trajectory well while mitigating against non-productive time.
An operators renewed focus on horizontal well drilling and open hole completions, using Inflow Control Device (ICD) screens, necessitated the use of oil-based drill-in fluids (DIF) to drill and complete their reservoir. The challenges were increased by low reservoir pressure conditions, increasing the risk of drilling fluid invasion and possible reservoir damage. Comprehensive laboratory studies were carried out to evaluate DIF performance and ensure understanding of the possible damage mechanisms produced while drilling, considering the reservoir characteristics and drilling conditions.The customized near-wellbore damage remediation system, with a delay-reaction, was designed based on Mesophase technology. This paper discusses detailed laboratory analysis for the clean-up system and its field applications in Kuwait horizontal wells. The applications included drilling carbonate and sandstone reservoirs, open hole ICD completion, and performing effective cleanup required for maximum production.The effectiveness of the Mesophase clean-up system to remediate reservoir damage and improve producibility was evaluated immediately after well kick off and again after steady production levels were reached. This paper shows the results obtained after the application of the near-wellbore remediation technology.The lessons learnt during the Mesophase application were incorporated on upcoming wells to standardize the operating procedures and improve field performance.
This paper will discuss the deployment of the concentric dual-diameter fixed-cutter bit technology, which was introduced in January 2015. The bit was deployed and tested twice in a vertical application in Burgan Field south of Kuwait and achieved the fastest penetration rate in the application.The concentric dual-diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed-cutter bits take very little advantage of stress-relieving the rock, as it only affects the borehole wall. Concentric dual-diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress-relieved rock with lower mechanical specific energy compared to regular fixed-cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual-diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling.The 12 ¼ in. concentric dual-diameter technology bit in conjunction with a packed rotary BHA was tested in a vertical application in the Burgan Field south of Kuwait. The bit was able to deliver improved performance, achieving the fastest penetration rate of 152.4 ft/hr. The section drilled was 762 ft in length and consisted of shale and sandstone.The performance capability was confirmed when the same bit was reused again in a similar application subsequently and was able to deliver the same consistent record penetration rate of 152.5 ft/hr. The section length in this second run was 610 ft. and consisted of similar lithology of shale and sandstone.The 12 ¼ in. concentric dual-diameter bit was able to surpass the average rate of penetration for the same application in the Burgan Field by 35%, saving the operator drilling time and making the concentric dual-diameter bit design the top performing drill bit in the field.
This paper will discuss the deployment of the concentric dual diameter fixed cutter bit technology which was introduced in January 2015. The bit was deployed and tested four times in a vertical application and S-shape wells in Burgan Field, South of Kuwait and achieved the fastest penetration rate in the application. The concentric dual diameter bit is composed of a smaller pilot and a larger reamer section, where the reamer section dictates the final drill size. Conventional fixed cutter bits take very little advantage of stress relieving the rock, as it only affects the borehole wall. Concentric dual diameter technology bits are able to initially drill with a leading smaller pilot section efficiently to relieve the stress of the rocks. Subsequently, the reamer section removes the stress relieved rock with lower mechanical specific energy compared to regular fixed cutter bits, giving it the advantage to generate higher penetration rates. Another advantage of the concentric dual diameter technology bits is the stability of the bit, since two gauge sections are available to be in constant contact with the borehole while drilling. The first 12 ¼ in. concentric dual diameter technology bit in conjunction with a packed rotary BHA was tested in a vertical application in the Burgan Field, South of Kuwait. The bit was able to deliver improved performance by drilling two wells from shoe-to-shoe to section TD of 1372 ft with an ROP of 152.4 ft/hr where the lithology consisted of shale and sandstone. The performance capability was confirmed when the second bit drilled two wells shoe-to-shoe to sections to a TD of 2263 ft with ROP of 161.6 ft/hr. and achieved top record runs in south Kuwait for vertical applications and S-shape wells and consisted of similar lithology of shale and sandstone. The 12 ¼ in. concentric dual diameter was able to surpass the average rate of penetration for the same application in the Burgan Field by 100% saving the operator drilling time and making the concentric dual diameter bit design the top performing drill bit in the field.
Challenges of oil recovery in mature assets continue to increase, requiring horizontal wells to be drilled for longer intervals. To improve the overall production in Kuwait, horizontal injector wells are required in some carbonate reservoirs in north Kuwait fields with the main objective of driving reservoir pressure in cases where aquifers cannot contribute to sustained oil recovery. Drilling several injector wells with long lateral sections was found to be the best approach to improve reservoir sweeping efficiency and drive the pressure regime for sustaining higher production levels. Historically, all horizontal wells drilled in similar reservoirs utilized oil-based mud (OBM), which was instrumental in reducing torque and friction along the lateral sections. Recently, all injector wells in the area were switched to water-based mud (WBM) systems in the lateral to reduce reservoir damage and improve injectivity and to enable the use of microimaging logging tools while drilling. This switch, together with limited drilling rig capability and geological uncertainty, posed major challenges on the deliverability of the horizontal section to planned total depth (TD). The operator, in collaboration with the drilling services provider and other service providers, completed a substantial planning phase to optimize the well design and make it achievable using current resources. The bottomhole assembly (BHA) was modeled, with iterations made to enhance the capability of drilling long laterals with proper weight transfer without sacrificing well stability or directional control. To overcome the challenge of drilling the long lateral section without the need for intermediate trips, the tool string design was customized for additional robustness and durability. Completed in two runs, the 6979 ft section was considered to be the longest lateral in north Kuwait ever achieved at the time. Maintaining the well in the desired trajectory, the motorized rotary steerable system was used to achieve a rate of penetration (ROP) improvement above the field average and within the allowable torque limit permitted, reaching the required total depth successfully. The bit and BHA selection and design were both critical to success. The subject reservoir known for high rock stresses and varying local formation dip angles posed a challenge to maintain the well on the desired trajectory due to unpredictable changes in the BHA tendency. Rotary steerable system (RSS) automation through the use of closed loop and cruise control features helped minimize human intervention. These features enable the RSS to automatically react and change downhole settings to track target inclination. This paper discusses the planning, design and execution of the subject well, in addition to the added value and resulting improvement in reservoir sweeping efficiency.
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