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An alternative method is presented for estimation of reservoir properties that are usually estimated in a classic buildup test are obtained using flowing conditions thereby eliminating the need for shut-in periods and measurement of static pressure data. The proposed approach is based on the effect of two consecutive periods of production with different rates in a single well-reservoir model. The well is initially produced at a constant rate until pseudo-steady state conditions are reached, followed by a different rate that will generate a pressure transient response measured at bottom of the wellbore. A mathematical formulation is applied to estimate the reservoir pressure as function of radius of investigation, which is equal to the bottom hole pressure observed during a shut-in buildup test. A single well-reservoir model with known petrophysical parameters, fluid properties, pressure and temperature is used as a reference to evaluate the proposed methodology. The reservoir (i.e. the simulation model) is tested by applying two methods: the first one, is the simulation of a classic buildup test, and the second one, is the simulation of two flow rates periods according to the new theory; the results are compared with the model of reference, calculating percentage of error for permeability, skin, and average reservoir pressure. Additionally, it is demonstrated that a shut-in period is not required to obtain data equivalent to a classic buildup test since it is possible to calculate it from dynamic behavior. The ability to complete a well pressure transient analysis test from flowing conditions and provide valid and reliable results has a direct impact in reduction of cost and deferred production for companies involved in oil and gas operations.

An Optimized Isochronal Test (OIT) is presented to evaluate the deliverability of a reservoir eliminating the need of shut-in periods during a multirate well test, which represents an operational constraint for classical isochronal tests and in some instances for modified isochronal tests. The proposed technique is based on the effect of several consecutive and different production rates over the well-reservoir model during both transient flow and pseudo-steady state flow; thus, it is possible to estimate the reservoir pressure at different radius of investigation, and the ratio between production volume and pressure drop. This method does not require stabilization of static reservoir pressure after a flowing period since it is calculated using a mathematical procedure based on the transient pressure equation. A reservoir simulation model with known petrophysical parameters, fluid properties, pressure and temperature, is used as a reference to evaluate the accuracy of the proposed methodology. Two types of fluids are tested, a low compressible black oil and a high compressible gas condensate, with the objective to demonstrate the optimized isochronal test applicability with pressure, pressure squared P^2, and pseudo-pressure Ψ(P) equations. The production deliverability is evaluated applying four different analysis: flow after flow test, isochronal flow test, modified isochronal flow test and the proposed optimized isochronal flow test; the results are compared and analyzed using the percentage of error found for every method. The optimized isochronal analysis provides the option to avoid shut-in periods during a multipoint well test and provide reliable production deliverability curves. OIT has a direct impact in reduction of costs and deferred production for companies involved in oil and gas operations.

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This paper presents an automated workflow that can estimate the oil and gas rates of a well, with the high frequency data, distinguishing the behavior of the reservoir under transient flow and pseudo steady state flow conditions. The new approach matches the wellhead pressure of a well model with the current value reported by a SCADA system, by adjusting the bottomhole pressure. For transient flow, it considers the response of the inflow performance relationship as a function of time. For pseudo steady state flow, it considers the declination of the reservoir pressure. The estimation of the production rate is carried out every 15 minutes, and the total daily produced volume is calculated based on the effective flowing time. To evaluate the accuracy of the new well rate estimation workflow, the output of the workflow is evaluated using two different criteria. Initially, the estimated oil and gas productions are compared with data from a real well test that is used as a quality control point. Secondly, considering that the fluid properties remain stable over time (water cut and gas-oil ratio), the critical flow through a choke valve defines a historical production trend that is used to quantify the deviation of the estimated values. As a result of the new workflow application, the difference between the estimated and measured rates decreased from 10% to 3%. The novelty of the new method is that it reduces the error of the estimated oil and gas production rates using the actual reservoir pressure behavior and provides more precise data for the different reservoir engineering analyzes.