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).

Hazard and operability analysis is a decisive factor to evaluate safety and reliability of plants considering the propagated effects due to consecutive failures of known critical components. A good design and analysis practice increases the robustness of the considered system in different operating conditions; however, in the plant design process, the use of a model-based design approach is fundamental to increase speed, efficiency and reliability. In this work, a tool for the 1-D simulation of thermal hydraulic plants is presented and applied to the analysis of critical system for compressor and gas turbine units, e.g. the lubrication circuits. Different from known commercial products, the proposed tool is implemented to work in cooperation with PidXP TM (the GE Nuovo Pignone P&ID definition tool), and it is optimized for fixed step solvers in order to easily include the rotating machine control logics within the simulation environment (essential prerequisite for hazard and operability evaluations). All the above makes it suitable for the fast prototyping of real time code. Moreover, the proposed tool represents a general tool in the model-based approach, and it can be used as a Simulink TM library of components that have been optimized and specifically designed in order to make easier the automatic generation of simulation models from P&Id schemes and technical documentation, reducing errors associated to data transcription and operator misbehaviour. In this work, proposed approach and test bench on experimental data for validation purposes are shown.

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. Based on the results of laboratory and field pilot tests it was proved that injectivity tests could be successfully applied in 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 fall-off period rather than to the injection phase. The formation permeability thickness product (kh) could be correctly identified 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 due to permeability damage, and a bi-phase component due to fluid interaction in the reservoir. The biphase skin could only be evaluated with numerical well testing, provided that the fluid relative permeability curves were available. It was also demonstrated that the bi-phase component mainly depends on the injection rate, but is independent from 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 6 DST tests performed on appraisal wells. Introduction In the vast majority of situations associated with exploration activities, there is no infrastructure and 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 gas emissions and restrictive environmental regulations make conventional well testing less and less feasible for appraisal wells.[1,2] In addition, the general target of reduction of time and costs of operations, especially for challenging oil field 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 of them 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, due to environmental concerns and to the risks associated with the presence of high percentages of H2S. Possible alternatives to conventional well testing were investigated, the principal goal to be achieved being the estimation of the productivity of the main geological units (Pool 1, Pool 2, and Pool 3) of the field. After a first screening, three methods were considered as potential alternatives to well testing:Mini-DST (Dual Packer Formation Test)Closed Chamber Testing (CCT)Injection Test Each alternative was thoroughly analyzed to verify whether it met the desired targets. For a consistent evaluation of the advantages and disadvantages of each possible option, the following critical issues were considered:Value Of the Information (VOI)Timing and costs of operationsHSE constraints and risks

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