In the UAE, drilling intermediate sections that contain highly dispersive clays with water-based muds almost always leads to mechanical instabilities in the form of pack-offs and tight spots due to highly laminated shale formations containing a high percentage of kaolinite. Operators have struggled with designing proper fluid systems to successfully drill these sections and have resorted to invert emulsion fluids (IEF) in certain fields, but that is not always an option. This paper presents the development and application of a high-performance water-based mud (HPWBM) that provided the required wellbore stability to drill these challenging shale sections through sealing natural and induced microfractures, and thereby reduced operational cost. Based on extensive testing, technical experts customized the HPWBM system to drill the troublesome sections both in vertical and inclined wells. Multiple stages of testing were completed to understand the shale, including X-ray diffraction analysis, which revealed that mixed layers were present with a high-kaolinite content. The cation exchange capacity (CEC) was low, indicating that the clays were not reactive. The optimized HPWBM formulation included two powerful components for shale stabilization and a third key component to minimize fluid loss into the formation. The customized formulation underwent a complete suite of shale testing, including capillary suction testing, linear swell meter, shale erosion, shale accretion, as well as lubricity testing and stress testing. Proper planning and execution, using best-available drilling practices, enabled the drilling of these challenging wells without encountering any significant issues that could impact rig time and increase costs. The selection of a customized HPWBM to provide shale stability performance and low-fluid invasion was fundamental to achieving the required fluid properties. Using this HPWBM system in these formations helped the operators achieve an average rate of penetration (ROP) of 43.7 fph – which was 62% higher than in the offset well and reach 40° inclination on different wells. There was also a reduction in the total volume used to drill the sections due to lower dilution rates compared to conventional systems. As a result of the lower fluid consumption, the total fluid costs were significantly reduced compared to offset wells. The casing strings were run to planned depth with no recorded issues on the first two wells, and savings of 11 days were achieved when compared to the offset wells in the same field. The customized HPWBM system with superior performance was able to achieve high levels of shale stability and inhibition without which this milestone would not have been possible. It made the possibility to drill these formations with an environmentally friendly, lower cost alternative to IEF a reality, which maximized the clients’ returns by reducing the overall cost of ownership.
While drilling through the initial section of extended reach drill (ERD) wells in Abu Dhabi where the trajectory requires a high inclination across a recognized loss zone various options were required to be assessed to maximize efficiency while balancing risks. Factors such as loss rate, capability of mixing fluid, necessary density to help prevent flow from a shallow water-bearing zone, and rig time, where all necessary and key factors to consider in the design process. For this UAE field with common losses in the surface casing, brine capping was determined the best solution to continue drilling without generating nonproductive time or creating a possible wellbore instability issue when unable to keep up with building mud to offset mud losses. For wells with a higher inclination angle, when the loss rate reached the point where it was not possible to prepare the fluid to keep up with losses, it was necessary to identify a different solution to cure or significantly reduce the losses and enable the hole section to be drilled without potential operational risks. For vugular/fractured porosity formations, using tailored particle size materials was unsuccessful for curing the losses. Therefore, a unique solution was implemented by combining two different systems to battle the losses: a swelling polymer lost-circulation material (LCM) that hydrates and helps reduce flow velocity into the formation, followed by a shear-rate rheology-dependent cement system that is a tunable and tailored slurry with thixotropic properties, which stops losses and develops low compressive strength. With this combined solution, the drilling process was successfully resumed and completed. The usual loss rate for this particular vugular argillaceous limestone formation is between 600 and 800 bbl/hr while drilling. Once the solution was successfully implemented, losses were reduced to 15 bbl/hr. The technique was performed on a second well, applying the lessons learned from the first attempt, and the unique solution achieved a dramatic reduction of losses to 2 to 6 bbl/hr. The cost and effectiveness of the treatment demonstrated that this solution is best for optimizing the drilling process for this particular condition. Applying a swelling polymer LCM and the shear-rate rheology-dependent cement system cured losses for an argillaceous limestone formation with fractured/vugular porosity. It is the first global application of this combined solution.
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