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Maley, Iain (Baker Hughes Incorporated) | Jadhav, Prakash (Baker Hughes Incorporated) | Everhard, Ian L. (Baker Hughes Incorporated) | Addagalla, Ajay (Baker Hughes Incorporated) | Hassan, Mohammad Omran (Baker Hughes Incorporated) | Kosandar, Balraj (Baker Hughes Incorporated)
Abstract Drilling lateral re-entry gas wells in the Eastern Province of Saudi Arabia has become a serious challenge with casing string design limitations leading to excessive overbalance pressures of over 5,450 psi across highly permeable Carbonate (Limestone and Dolomite) formations. The challenges associated with drilling these re-entry build up sections are as below - Salt water influxes through the Jilh formations Expected severe losses across Khuff A and B formations High density fluid management issues with losses and influx situations Differential sticking across low pressure formations Wellbore instability across the overlying Sudhair reactive shale High angle section profiles (> 60° inclination). A customized fluid system was designed to overcome the above challenges associated with high overbalance pressure, targeting improved bridging, minimizing pore pressure transmission and increasing wellbore strengthening with increased hoop stress techniques. Software modelling and permeability plugging tests were performed to evaluate the fluid behavior under downhole conditions and to simulate the characteristics of induced micro fractures. Porosity, permeability and the likelihood of micro fracturing were considered to optimize the bridging mechanism and materials. These results identified a synthetic deformable sealing polymer combined with sized synthetic graphite and ground marble which showed considerable improvement in minimizing spurt and overall filtrate loss with minimum effect on the rheological parameters and stability of the fluid system. This paper describes the customized drilling fluids performance in two study wells as compared to offset wells. A comprehensive engineered approach addressed the challenges of drilling in such extreme overbalance conditions by using a revolutionary bridging technology. The lessons learned on these wells have been incorporated while drilling subsequent wells to continue to improve performance.
Abstract A 6-1/8 in. sidetrack was planned for well-M as a result of water coning where the water cut climbed to as high as 35% in this old well. Drilling a pilot hole preceded the sidetrack operation in order to assess the surrounding reservoirs in the target area and most prolific candidate. Local geomechanical analysis was carried out in order to establish a mud window and ensure quality drilling with minimal wellbore instability, thus save rig time and operational cost. Cutting flow meters were deployed to monitor the hole cleaning performance and raise any red flags for immediate reactions to any abnormal wellbore behavior that may indicate wellbore instability. A drillmap was constructed highlighting the different hazard categories that could be encountered throughout the job and the proper solution that needs to be implemented. Tripping and hole cleaning best practices were also established to further increase the operational awareness and alertness throughout the job. Sweep pills, reaming and short trips were optimized to keep a clean hole and avoid disturbing the borehole. Two different BHA's were utilized to complete this borehole: steerable mud motor to drill the curved section, and rotary steerable system to drill the horizontal section. Well-X witnessed the deployment of the world's longest 4-1/2 in. partially cemented system with ICD screens, 7,389 ft. The competent drilling efforts enabled running this stiff assembly all the way across this extended reach lateral. The off-bottom liner system was hydraulically set and cemented in place where the reservoir was compartmentalized across the section with 48 ICD screens and five non-inflatable mechanical isolation openhole packers. This paper will focus on the drilling design and operational practices that enabled the achievement and deployment of this record system.
Abstract As operators reduce spending on exploration, more wells with increasing complexity are being drilled in mature fields. As the well complexity increases, a dilemma often occurs over how to address borehole stability requirements while mitigating the risks of shale instability, differential sticking or mud losses due to high differential pressures. These wells may have little or no operating margin between the pore pressure and formation breakdown. High mud weight may be required to prevent shale collapse. Options tend to be limited to accepting the drilling risks or setting a contingency casing string—both very expensive choices in terms of equipment and lost time. Downhole losses and differential sticking occur because the drilling fluid hydrostatic pressure is higher than the formation pressure, a situation referred to as ‘overbalanced pressure’ while drilling through formations that are fractured, under pressured, cavernous or highly permeable. Traditionally, the wells in these types of fields experience some or all of these drilling problems. Wells drilled through the interbedded shale and sandstone Barik formation usually encounter severe wellbore stability issues that result in increased drilling time and the possibility of side tracks. Wellbore instability occurs because the Barik formation requires a high fluid density to stabilize the shale sections due to the depleted, low-pressure sandstone sections. Wells drilled in the Barik formation have been drilled with an advanced invert emulsion fluid. These wells experienced wellbore instability and differential sticking, resulting in significant non-productive time (NPT). One of the limitations of bridging wells with traditional materials is the impact these materials may have on rheological properties and the generally poor performance they demonstrate with respect to wellbore stability at overbalance pressures greater than 2,000 psi. A water-based fluid with an optimized bridging and sealing system was custom-designed using proprietary software and based on deformable nanotechnology material with synthetic carbon-based additives. This combination of additives provides a wide particle size distribution range to cover the micro-fractures (< 200 nanometers) and the macro-fractures (>10 microns). This bridging system comes in a single sack, which helps reduce transportation costs, logistics, rigsite footprint and minimises manual handling. This was the first application of water-based mud to drill in the field, and the customized bridging and sealing package was successful in sealing the Barik sandstone, allowing the horizontal well to be drilled to planned depth without NPT, despite the formation being subjected to high overbalance pressures greater than 5,600psi. The bridging and wellbore strengthening properties of the custom-designed water-based fluid prevented instability of the shale by sealing the formation, delivering excellent wellbore stability while simultaneously sealing the sandstone and preventing differential sticking. This approach resulted in a significant reduction in NPT compared to the previous attempts.
Abstract With the continued growth of drilling activities and the cost of performing them in depleted sands, loss of productive time is more important than ever. For years the use of LCM has been the preferred way for treating lost-circulation problems (Messenger 1981). However, the lost circulation problem was not totally resolved. Recent studies have shed much light on its cause and potential solutions. However, wellbore strengthening or stress cage implementation has been recognized as an effective means of dealing with lost circulation during drilling operations. One of the mechanisms developed for strengthening a wellbore has been to prop induced and existing fractures with particulate lost circulation materials (LCM) to effectively increase hoop stress in the near wellbore region. However, a good understanding of this mechanism is necessary in order to avoid a potentially flawed design and implementation process which could adversely affect job success during well operations. One of the main issues is depleted sand/shales stringers stability under the strengthening conditions. This paper will describe those factors which are important in designing wellbore strengthening jobs and address the conditions necessary to help ensure depleted sands stability, as determined through geomechanics analysis. The strengthening of a wellbore by propping fractures has been discussed in a previous investigation (Wang et al. 2007a). In this paper, various parameters that affect the strengthening of the wellbore are addressed in detail. In-depth discussion of how each of those parameters affects the process of wellbore strengthening will be presented. This study was accomplished using a boundary element numerical analysis coupled with the linear elastic theorem. Hence, the stress cage concept is an approach developed to enhance wellbore pressure containment (WPC). It has been found that a weak wellbore can contain much higher pressure if the wellbore fluid is treated with particulates and as such understanding the mechanism of stress caging is recommended to design the treatments for specific field application and to advance the development of the technology for application across a wider mud weight window and with a higher success rate while drilling in depleted sands. On-the-fly preventive methods appear to be favored as they cut down on non-productive time and reduce costs in the longer term while drilling in depleted sands as can be seen using the new 3D MUDSYST model.
Abstract Under this climate of oil price and energy uncertainty, it is mandatory to limit the non-productive time (NPT) and achieve the highest levels of operational excellence. This is a key factor toward overcoming the evolving economic challenges, reducing budget and spending, and optimizing the return on investment. Worldwide, stuck pipe and borehole problems represent one major contributor into the NPT while drilling, reaming, tripping, casing and running completions. This NPT category becomes even more critical when dealing with shaly formations. Saudi Aramco constantly deal with offshore shaly formations in Saudi Arabia where stuck pipe and borehole problems contribute with over 24% to the overall drilling and workover NPT. Establishing best practices to minimize or prevent these problems will enhance the overall drilling performance and result in significant operating time reductions and cost savings. The major offshore re-entry operation challenges are first screened: formation instability, hole size, well trajectory, bottomhole assembly and experience and communication. The shaly formation rock nature is analyzed to understand the stressed shale instability root cause: mechanical and/or chemical. This diagnostic step establishes the formation shale properties and behavior. In relation to this information, three basic stuck pipe mechanisms (pack-off and bridging, differential sticking, and wellbore geometry) are discussed where the major contributing factors for each category are identified. This leads to the establishment of proactive recommendations and best practices. These practices will tackle the problem from different angles to construct an integrated solution. This includes drilling fluid design (rheology, filter cake, filtrate volume and properties, etc.), hole cleaning (rate of penetration, sweep pills, bottoms-up volume, etc.) and drilling parameters (trend analysis, flow rates, string motion, etc.). This paper will highlight the recommended practices and provide actual well examples where stuck pipe tendency was reduced in shaly formations.