Ensuring shale stability while drilling the reservoir and completing a well is critical to guarantee well integrity and to enable the reservoir to product at its maximum potential. Drill-in fluid type, completion brine, and shale inhibitors play an important role in maintaining well integrity and preventing formation damage as they have different effects on shale. Reactivity of shale samples from offshore Gulf of Mexico was studied using several reservoir and completion fluids. The shale was first characterized using X-Ray diffraction (XRD) and X-Ray fluorescence (XRF). Then, the effect of fluids on shale was determined by performing several tests including linear swell meter (LSM), capillary suction time, and cuttings dispersion. Water-based (WB) and oil-based (OB) drill-in fluids, synthetic formation water, and completion brines with and without shale inhibitor were used to study the shale reactivity. XRD and XRF test showed presence of 5wt% illite and 6wt% kaolinite in the shale sample. Performance tests conducted on the shale samples showed a similar trend of high reactivity with improvements when inhibitor is added. Some brines showed poor synergistic effects when inhibitors were present in the fluid formulation. The type of drill-in fluid has a large impact on the LSM test results. Type of brine in the WB drill-in fluid also showed a major influence on the shale behavior. Oil-based drill-in fluids are commonly used to drill sections with very reactive shales. Nevertheless, water-based fluids are sometimes required due to performance preferences, environmental concerns, economic and logistic reasons, and/or synergistic effects with logging tools. Filtrate invasion and drill-in fluid/completion brine losses could cause detrimental effects in the reservoir if the fluids have not been designed to inhibit the shale hydration and swelling or fines migration. Therefore, improving the clay inhibition and shale stability while using water-based fluids is fundamental when drilling through reactive shale sections. Performing a comprehensive test matrix to determine the feasibility of using water-based fluids is imperative. Achieving excellent inhibition for a very reactive GOM formation shale while maintaining performance is possible when a precise and well-engineered combination of brine/shale inhibitor in the drill-in and completion fluids are found.
Offshore reservoirs in the Southwest Persian Gulf are commonly oil-wet limestone with an average permeability of 10 md. High production of hydrogen sulfide and carbon dioxide is often encountered in the oil producer wells. The tight reservoirs are commonly drilled with water-based reservoir drill-in fluid (DIF) with high concentrations of lubricants. DIFs based on sodium chloride or calcium chloride brines with corresponding optimal breakers to remove the filter cakes were formulated and evaluated to optimize production in newly drilled wells. Fluid displacement by return permeability (RP) testing was used to evaluate the fluid/limestone rock interaction. This paper discusses the compatibility of a sodium chloride-based and a calcium chloride-based DIF with limestone formation and the necessity of introducing an optimal breaker to maximize the opportunity to achieve high production rates. RP tests are widely used to determine the potential damage caused by the DIF and production enhancement after removing the DIF filter cake with a breaker. Desired results for RP tests performed with the brine-based DIF in limestone cores were a minimum of 75% regain permeability to oil production. The cores used for the RP tests were from an analogue limestone outcrop from a Mississippian formation with permeability between 9-16 md and 14-18% porosity. DIF properties were determined following API RP-13I recommended practices. Emulsion tendency for the fluids was determined by using emulsion tendency testing with a high-speed mixer to mimic shear at the pore throat. A 10.0 lb/gal sodium chloride water-based DIF with a high content of ester-based lubricant was designed for drilling a limestone formation. A high pH close to 10 was necessary to control H2S and CO2 corrosion. The return permeability of the 10.0 lb/gal fluid was 44% using LVT-200 oil as an analogue for the native hydrocarbon permeating fluid. The low return permeability was likely caused by emulsion blockages generated by the saponification of the ester-based lubricant used in the sodium chloride-based DIF. Emulsion tendency was observed between the DIF filtrate and permeating fluid in a fluid/fluid compatibility evaluation. Therefore, a breaker system was formulated and customized to enhance RP from 44% to a minimum of 75%. In contrast, a 11.0 lb/gal calcium chloride-based DIF with pH of 9.0 and same ester-based lubricant content was evaluated using a comparable limestone analogue core and demonstrated a high return permeability (>80%). Filtrate of the calcium chloride-based DIF did not form emulsions during fluid displacement in the RP test. Compatibility evaluation (return permeability) between drill-in fluids and reservoir rock is essential for oil producer wells in order to determine and avoid potential problems caused by interactions between them.
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