An increasing number of field developments in Norwegian waters are marginal, with the economics limited by reservoir deliverability and requiring optimum well productivity unaffected by formation damage. This paper presents a case history from an ongoing development in low-permeable, highly challenging reservoirs. The 150 °C downhole temperatures, well geometry restrictions imposed by the subsea development, and the use of non-perforated completions place additional constraints on fluid design. The focus of the paper is on formation damage studies and the identification of performance-critical drilling fluid parameters. The development of representative laboratory methods is discussed and uncertainties evaluated. The joint study highlights the importance of using a range of field and lab mud preparations and working in an open interactive manner for fluid development, evaluation and testing. Combining field and laboratory test results was a critical part of the effort.

Initial mud exposure tests on reservoir core samples indicated that an otherwise qualified HTHP oil-based drilling fluid could cause severe formation damage in this particular reservoir. This was quite unexpected, as the fluid in question has been used to drill highly productive wells in other fields. Similar damage was observed on field and laboratory mud samples. Parallel work showed selected water-based fluids to also be damaging with no other decisive advantages. A systematic program of reformulating the HPHT OBM was undertaken. First, each auxiliary system component was replaced, and the effect on formation damage measured. These changes were insufficient to remove the damage potential of the original fluid. Therefore, an alternative emulsifier pack-age was selected and used as the basis for designing a novel system. Core tests on lab formulations of the novel system indicated greatly reduced formation damage potential.

A field trial was immediately carried out to validate the novel system and showed good production potential with low skin damage. A repeat test in another well confirmed this observation. The field trials were designed to capture any changes in field fluid behavior that could be detrimental to well productivity. Drilling-fluid samples were collected at regular intervals and characterised for standard properties, filtration, particle sizing and formation damage. Supporting research, using powerful experimental tools such as ESEM, and pore-size analysis of reservoir cores gave added value. Surprising core-test results led to the identification of flaws in the lab test protocols affecting the saturations before and after mud exposure. By redefining the core-test procedures and correlating all the lab results, conclusions were obtained that were in agreement with the good field performance of the novel fluid and new knowledge was gained about the mechanisms of formation damage.

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