An operator in Gulf of Guinea experienced dramatic production impairment due to calcium carbonate scaling. Post completion analysis revealed that the scaling magnitude was dependent upon several influences, primarily the reservoir pressure; access to mobile formation water coupled with its scaling tendency induced carbonate scales deposit. The impact of the completion brine and drilling mud and filtrate as whole losses or secondary filtrate were identified as contributors. The above study and its conclusions were reported concurrent with on-going planning for the next horizontal drill and open-hole gravel-pack completion. The water-base reservoir drilling fluid (RDF), screen running fluid (SF), completion brine, gravel pack carrier fluid, and filter-cake breaker fluid were designed with divalent calcium chloride brine. The required products for these systems were already on location and operations very close to commencing.

Redesigning all these systems by replacing the divalent brine with monovalent brine would require additional resources and delay the project. However, a scale inhibitor was recommended to mitigate the initial risk of scale formation when using divalent calcium brine. Concentrations of Scale inhibitors were tested over a range of temperature from 150F to 250F, and ratios between formation water and selected fluids from 25/75 to 75/25. Testing considered adding a scale inhibitor to the RDF as well as the other required systems.

This upfront assessment indicated that the selected inhibitor prevented scaling with formation water. As such, the operator approved the use of the scale inhibitor and the well was successfully drilled and completed. Higher initial production than modeled was realized for this well compared to other wells in this field.

This paper will present the upfront testing to assess shale inhibitor efficiency, results, and the field application used to reduce the risk of formation damage during the drilling and completion phases.

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