Impact of the Drill-In Fluid Type and Weighting Material for Oil Producers when Drilling Reservoirs

Abstract High density fluids are required to drill deep wells in the Gulf of Mexico (GOM) due to wells drilled in deeper water and with higher formation pressures. The drilling conditions are further challenged by the required low equivalent circulating densities (ECDs) to effectively handle wellbore pressures. A formulated drill-in fluid (DIF) for this area therefore needs to minimize the damage to the formation while ensuring all the other conditions are achieved, such as compatibility between reservoir fluids and workover fluids to avoid near-wellbore formation damage, which negatively impacts project economics and productivity in the reservoir. Invert emulsion (IE) and water-based (WB) fluids could be used for the task, but each type of fluid has positive and negative impacts to the formation. Invasion of the high filtrate volume, invasion of weighting materials and polymers, and high filter cake liftoff pressures could cause a complicated return to production operation. A 16.4 lbm/gal DIF with minimum solids and filtrate invasion was desired for an offshore well at 280°F. The application required a stable fluid from 40°F up to 280°F with flat rheology. The designed fluid was subjected to several tests, including HPHT viscometry, HPHT sag test, and return permeability. The WB DIF showed a reduction in return permeability of 75%. Optimization of the fluid without changing significantly other properties was achieved, and the optimized fluid showed return permeability >90% without significant solids invasion after adding an enhancer. Three different IE DIFs were developed. Manganese tetraoxide or barite with different particle size distributions (PSDs) were used as weighting material in the fluids. The IE DIF containing manganese tetraoxide showed return permeability ~30% while the fluid formulated with high PSD barite showed ~60% when using Castlegate cores. The fluid formulated with micronized barite showed return permeabilities >73% when using Berea Buff cores, and SEM studies showed invasion of the weighting material into the cores. Deeper solids invasion was observed with a small PSD depending on the weighting material type. The results showed the weighting material affected the return permeability and the properties of the fluid. The fine particles could plug the formation in a similar effect to fines migration in the near wellbore and were impaired from flowing back in production. The bridging and packing of solids in the filter cake must therefore be enhanced to improve filter cake flexibility and decrease invasion without detrimental effect on other properties. Readiness and prevention of reservoir damage is imperative for GOM offshore operations on HPHT wells. Selecting the correct fluid could be the difference between a successful case history or high economic impact for the operation. The chosen testing matrix and products allow predictions and contingency plans.