Value of Injection Testing as an Alternative to Conventional Well Testing: Field Experience in a Sour-Oil Reservoir

Summary Environmental constraints and high costs, especially offshore, are making conventional-well testing less and less feasible and accepted by the public administration. New options were thoroughly evaluated to find a viable alternative to standard production tests for characterizing the well productivity without surface production. An accurate investigation demonstrated that injection tests could provide all the information needed to calculate the well productivity at reasonably low costs and with a good degree of reliability. On the basis of the results of laboratory and field pilot tests, it was proved that injectivity tests could be applied successfully to a real sour-oil field. Laboratory tests proved that brine could be a suitable injection fluid because there were no compatibility problems with the oil and the reservoir rock. It was verified that the interpretation of the pressure transients should be referred to the falloff period rather than to the injection phase. The formation permeability-thickness product (kh) could be identified correctly from the pressure-derivative analysis only if multiphase flow was assumed. The total skin value could also be obtained from the test interpretation. The total skin comprises two components: a mechanical component resulting from permeability damage and a biphase component resulting from fluid interaction in the reservoir. Except for a limited number of cases, the biphase skin can be evaluated only with numerical well testing, provided that the fluid relative permeability curves are available. It was also demonstrated that the biphase component depends mainly on the injection rate but is independent of the formation permeability. Then, the well-known transient equation was applied to determine the well productivity index (PI) based on the kh and the mechanical skin. PI values calculated from injection tests compared satisfactorily with PI values measured from six drillstem tests (DSTs) performed on appraisal wells. Introduction In the vast majority of situations associated with exploration activities, there is no infrastructure and no equipment in place to collect the hydrocarbons produced during well tests; thus, it is common practice to burn the produced fluids. However, the demands (if not requirements) to reduce or avoid hydrocarbon emissions and the restrictive environmental regulations in place make conventional well testing less and less feasible for appraisal wells (Levitan 2002; Hollaender et al. 2002). In addition, the general target of reducing the time and cost of operations, especially for challenging oilfield developments, requires evaluating whether conventional well testing is always the optimal cost-effective option. Therefore, the potential value of alternatives that might be used as a substitute to conventional well testing needs to be investigated. It is likely that individually, these alternatives do not fulfill all the targets of conventional tests; thus, a clear understanding of the capabilities of each is necessary. The work presented in this paper refers to a real, naturally fractured reservoir with more than 200 development wells to be tested after final completion. Standard production tests are not allowed by local regulations because of the environmental concerns and the risks associated with the presence of high percentages of H2S. Possible alternatives to conventional well testing were investigated, with the principal goal being the estimation of the productivity of the field's main geological units (Pool 1, Pool 2, and Pool 3).