Incompatibities between reservoir fluids and drill-in fluids and/or completion fluids can cause near-wellbore formation damage, which negatively impacts project economics and productivity in the reservoir. This paper describes a systematic study of prediction and determination of negative interactions between completion fluids, oil-based drill-in fluids, and the native reservoir fluids to ensure prevention of near-wellbore damage caused by fluid-fluid and fluid-solid interactions. Correct formulation of completion fluids plays one of the most important roles in the preservation of the wellbore and production index.
Fluid losses and seepage are sometimes inevitable; however, careful selection of drill-in and completion fluids with optimum interactions (fast fluid separation without viscous interfaces) is required in order to ensure proper care of the near-wellbore formation and to facilitate production/injection at the expected rates.
A complex test matrix was designed for predicting interactions between fluids, depending on fluid type, and the likelihood of comingling while drilling the reservoir or displacing fluids. Several techniques were used to evaluate compatibility, including rheology of neat fluids and mixtures, emulsion formation tendency, and scale tendency. Contamination of oil-based drill-in fluid with drilled solids, completion brine, and seawater was studied following API-13I protocols. For all other fluids, rheology was measured before and after mixing of the fluids at several ratios. Shaken bottle tests determined compatibility between base oil and several aqueous fluids. Scale tendency was studied using a brine-based compatibility test.
Interaction between oil-based drill-in fluid and different contaminants showed favorable results. The formulated drill-in fluid tolerated contaminants including crude oil, seawater, completion brine, and drilled solids without drastically changing its rheological properties. Linear variation of rheology correlating with mix ratios of completion fluids and pills demonstrated compatibility and a smooth rheological transition between neat fluids and the mixtures. Furthermore, testing demonstrated minimum emulsion-forming tendency between oil-based products (crude oil, base oil for drill-in fluid, and hydraulic oil) and the different aqueous fluids studied. All of the fluids evaluated were compatible, achieving separation within 60 minutes. Compatibility between all of the aqueous-based fluids (formation water, seawater, and completion brine) showed no precipitation or scale formation during testing at different temperatures and fluid ratios.
Readiness for worst case scenarios and prediction of damage has never been more imperative than now because offshore drilling operations are going to deeper depths at hotter temperatures with no room for error. A comprehensive test matrix between all the completion and native fluids is needed in order to predict negative interactions and possible outcomes while drilling. This allows for reformulations, before executing the drilling plan, thus saving time and money in offshore operations.
