Fluid Design to Meet Reservoir Issues - A Process

Abstract As open hole completions, horizontal wells, multi-laterals, and underbalanced drilling become more common place, greater emphasis is being placed on the selection and design of drilling and completion fluids. The problem of assessing fluid compatibility with hydrocarbon reservoirs is ongoing and usually unique to each reservoir. This problem becomes most visible after resources have been expended to drill, with unsatisfactory results in productivity. The objective of this paper is to present a process designed to use the best available methodologies and laboratory techniques to assist in the design and selection of fluids which will be most compatible with the reservoir. Ultimately the goal is to drill zero skin wells. The process addresses fluid design issues from both a bridging or solid phase perspective and a liquid phase perspective. Optimization relative to design such as chemical selection and concentrations are an integral part of the process. Using this process will reduce uncertainty regarding fluid selection and the impact of the fluids on productivity. Ultimately it is meant to assist in both increasing well productivity and reducing the requirement for expensive stimulation. The process may lead to innovation, resulting in new systems or products. It may be applied when designing workover and completion fluids or for drill-in fluids including overbalanced or underbalanced applications. Introduction The potential to reduce wellbore productivity while conducting drilling completion and workover procedures has been addressed extensively in petroleum related literature. Productivity impairment was originally recognized in field cases where development wells produced only small volumes of fluid upon completion or where producing wells produced less after work-over procedures. In other instances, where drill stem tests taken while drilling deep wells indicated potentially good production from shallow zones, difficulty was experienced in attaining production from those zones which had remained in contact with drilling muds for an extended time(l). Investigations of specific damage mechanisms is an ongoing pursuit. Bates et al. discussed the influence of clay content on water conductivity of oil sands in 1946(2). Nowak et al. studied the effect of mud filtrates and mud particles on permeability in 1951(3). Various models which consider formation damage have quantifiable outputs such as Skin Effect(4), Productivity Index(5) and Formation Damage Index Number(6). Methods of preventing formation damage continue to be tested, developed, and documented. A greater percentage of wells are now designed as open hole completions, where perforating past the damaged zone is impractical. Consequently, sophistication in fluids testing procedures has increased and frequently operators test whole fluids against their rock. Often fluid samples are obtained from multiple sources. Return permeability tests(7) are regularly used to select the "best" fluid. Unfortunately, if an adequate candidate isn't found, the data are usually insufficient to redefine the direction testing should take. The process described herein helps to categorize and quantify discrete damage mechanisms. Fluid design is systematically optimized for all damage issues such that ultimately the fluid is compatible with the reservoir. In actual practice the first line of defense against formation impairment is to keep foreign fluids and solids out of the rock.