The straight line model introduced by Havlena and Odeh require plotting of the underground recoverable function F against the oil plus dissolved gas expansion function E o or gas cap expansion function E g or the connate water and rock properties E fw or a combination of these drives depending on the existing reservoir drive. The consequence is that the estimation of the initial oil in place and cumulative oil produced do not considered the timing factor of the average production of the field life. Hence, this paper present an alternative Havlena & Odeh model in which the reservoir functions such as F are plotted against E per cumulative time making reservoir engineers to appreciate the reservoir behaviour at each time space/limit and also act as a check to the original Havlena and Odeh model. The average production per day is used as against the cumulative production. An appropriate equation and method of analysis is show in this paper. Nevertheless a practical field case is considered. Result from the new model maintained relevant trend with the old Havlena and Odeh model with error factor of 0.043%, hence suitable for predicting reservoir performance as a function of time and also estimating initial oil in place and cumulative production.

This paper introduces the statistical method for diagnosing flow regimes for flowing and shut-in conditions. The method utilise the second differencing of pressure change and time that are stationary; then integrate the residual pressure differences using simple statistical tools such as sum of square error SSE, moving average MA and covariance of data to formulate the statistical derivative models. These models are tested with constant pressure, constant rate conditions and in well with high water production. Results from three scenarios investigated demonstrated that the statistical derivatives yielded much clearer reservoir radial flow regimes as the conventional pressure derivatives without data smoothing; therefore give more confident formation permeability estimation. It demonstrated that for high water production well, a good radial stabilisation can be identified. It also showed that in all three scenarios, the drawdown radial fingerprint can be replicated in the build-up pressure responses, hence a good match of the data.

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This paper presents the numerical density derivative approach (another phase of numerical welltesting) in which each fluid’s densities around the wellbore are measured and used to generate pressure equivalent for each phase using simplified pressure-density correlation, as well as new statistical derivative methods to determine each fluid phase’s permeabilities, and the average effective permeability for the system with a new empirical model. Also density related radial flow equations for each fluid phase are derived and semilog specialised plot of density versus Horner time is used to estimate k relative to each phase. Results from 2 examples of oil and gas condensate reservoirs show that the derivatives of the fluid phase pressure-densities equivalent display the same wellbore and reservoir fingerprint as the conventional bottom-hole pressure BPR method. It also indicates that the average effective kave ranges between 43 and 57 mD for scenarios (a) to (d) in Example 1.0 and 404 mD for scenarios (a) to (b) in Example 2.0 using the new fluid phase empirical model for K estimation. This is within the k value used in the simulation model and likewise that estimated from the conventional BPR method. Results also discovered that in all six scenarios investigated, the heavier fluid such as water and the weighted average pressure-density equivalent of all fluid gives exact effective k as the conventional BPR method. This approach provides an estimate of the possible fluid phase permeabilities and the % of each phase contribution to flow at a given point. Hence, at several dp' stabilisation points, the relative k can be generated.

The prohibitive costs & risks associated with performing PLT and potentially the isolation of the water producing zone through WSO in deepwater fields such as Akpo renders these operations economically unattractive. This paper addresses the application of analytical method including the use of 4D monitor results to replace conventional PLT to identify, screen and select viable successful water shut off candidates. Prior to executing water shut-off treatment programs, a combination of 4D seismic interpretation, production history review as well as the collection of completion and reservoir information were thoroughly performed to ensure that the wells are properly selected. Well's diagnostic plot (WOR and WOR′) must be consistent with the type of water coning or channeling problem identified from the 4D time lapse seismic and also the depth of possible mechanical plug must be around or above estimated current oil-water contact (COWC). Two candidate wells having 6-5/8″ SAS Slot 10 in 8.5″ open hole, at approximately 4,000 meter TD, and 82 deg C reservoir temperature were selected. The water cut values were 55% in one well and 60% in the other. This paper presents below the significant upside for WSO attributed to the use of analytical method and integration of 4D seismic data by eliminating the need to run a traditional PLT. The operation was technically & economically successful on one well with a decrease of watercut from 55% to 16% resulting in the well incremental oil production of ~3kbopd. Operation is planned mid 2019 for the second well