This paper was prepared for presentation at the 1999 SPE European Formation Damage Conference held in The Hague, The Netherlands, 31 May–1 June 1999.

Well productivity can be significantly affected by damage to the near well-bore area caused during drilling in the reservoir section of a well. Historically, the use of perforated completions allowed for penetration of the producing formation beyond the damaged area but the recent trend towards non-perforated completions has resulted in an increased emphasis on damage minimisation. This, in turn, has increased the importance of evaluating drilling fluids and completion techniques used from a reservoir damage perspective. The suitability of a drilling or completion fluid for use in a particular reservoir can, and should, be determined using the measurement of return permeability or some other indication of formation damage. A major factor which limits this practice is that no industry standard equipment or methodology exists for this type of testing and differences in results obtained at different times or in different laboratories cannot be reliably compared. Repeatability and reproducibility of the tests conducted have not been widely established. In order to address these problems, a recommended practice for formation damage testing has been developed which covers all aspects of the test methodology from core selection and preparation to the writing of the final report and interpretation of the results. By standardising on equipment and methodology, it has been possible to establish the degree of variation which can be expected when the same samples are tested in the same way in different laboratories. Further testing in which selected parameters have been varied has also given an indication of the degree to which the setting of these variables affects the final result. It is hoped that this recommended practice will now gain acceptance throughout the industry and that the process of evaluating fluids for formation damage potential will become simpler and more efficient through the greater use and validity of comparisons between data from different sources. Introduction During the last ten years, there has been a very significant increase in the number of highly deviated and horizontal wells drilled through hydrocarbon reservoirs. At the same time, completion techniques have also changed with an increase in the number of open-hole completions. The driver for these changes has been financial, with economic pressures on oil companies resulting in the need to more cost-effectively develop resources. Open hole completions allow production from a greater percentage of the wellbore surface than cased and perforated completions but this increase will only be realised in practice if the damage caused by the drilling and completion fluids can be overcome. This requirement has lead to the development of specialised "drill-in" fluids with a focus on the minimisation of reservoir damage. It is now becoming common practice to evaluate the efficacy of such fluids prior to use by the measurement of formation damage potential. The most common test which is used for this purpose is the measurement of return permeability, either using standard material such as Berea sandstone, synthetic disks or reservoir core if available. Return permeability testing is conducted in many laboratories using many different techniques ranging from simple evaluations taking a few hours to more complex methods requiring up to a week to produce a result. The basic process involves the determination of the initial permeability of a sample of reservoir material or surrogate, the exposure the sample to drilling and/or completion fluids and the subsequent re-measurement of permeability. The difference between the two measured permeabilities is taken as an indication of the suitability of the fluid under test for exposure to the reservoir. There are many points in the testing where decisions have to made concerning the selection of a method or technique to use and there is no industry standard to guide this process. Obviously the testing should be designed to simulate field conditions as closely as possible. P. 103^

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