Improving the economics of the production and development of an unconventional reservoir system is a key to meeting increased demand for hydrocarbons in the near future. In general, reservoir development is vastly assisted by using hard-computing models to evaluate the potential of the formation. These models have been used to identify infill drilling locations and forecast production. However, preparing the simulation models for discontinuous tight oil reservoir systems poses a challenge with hard-computing protocols. This paper discusses a methodology developed to depict the production characteristics of a reservoir via the geological properties of the reservoir. The methodology discussed in the paper is time efficient and is proven to generate effective results. The methodology discussed in the paper utilizes Artificial Neural Networks (ANN) to map the existing complex relationships between seismic data, well logs, completion parameters and production characteristics. ANNs developed in this work are used to forecast oil, water and gas cumulative production for a two year period. The results obtained are also extended to identify potential infill drilling locations. This work enables the practicing engineer and the geoscientist to analyze an entire reservoir in a time efficient manner. The workflow is demonstrated on a discontinuous tight oil reservoir located in West Texas. The results discussed in the paper show the robust nature of the methodology. The workflow also helps in improving the resolution of the production surfaces which help in identifying productive, yet undrilled, locations in the reservoir. The production surface for the entire field is forecasted within a one minute time frame (~6600 locations). The method developed will help in avoiding low producing wells prior to drilling, and thus, is expected to help in the economic development of complex tight oil reservoirs.

Naturally fractured reservoirs constitute a significant portion of oil and gas fields worldwide. Like all reservoirs, waterflooding is routinely used in naturally fractured formations to increase recovery. However, the benefits of waterflooding can be limited due to early water breakthrough via the fractures. Therefore it is imperative to closely monitor the flood progress in these reservoirs. Analyzing transient tests in water injection wells, especially early in the life of the flood can provide valuable information, such as the mobilities in various regions around the well and the location of the flood front. An analytical model to design and analyze falloff transient data in naturally fractured reservoirs is highly desirable so that pressure transient analysis techniques can be applied for monitoring and optimizing secondary recovery projects. In this paper we present a semi-analytical solution for the pressure response during falloff tests in naturally fractured reservoirs under multiphase flow conditions. We consider water injection into an oil reservoir, resulting in two-phase flow. In our model, the radial variation of fluid saturation is modeled as a multibank reservoir with constant saturation in each bank. Each bank has a different relative permeability and compressibility value, corresponding to the fluid saturation in the bank. We model naturally fractured reservoir behavior using Warren & Root's dual porosity model, which is extended to accommodate two-phase and multi-composite reservoirs. We also include capillary pressure effects in the model. The proposed semi-analytical solution was tested and compared against numerical simulation results obtained from commercial simulators. The results have been in excellent agreement, validating our semi analytical approach. Using the proposed solution provides a rigorous and fast method to design and analyze tests. It also allows for using nonlinear regression techniques as opposed to computationally expensive trial and error matching for estimation of reservoir properties. Our analytical model can also be used as a guideline for grid refining in the vicinity of the wellbore and time-step selection in numerical simulators for transient tests analysis. We expect our analytical method will enable operators and engineers to design and analyze falloff tests quickly and accurately in naturally fractured reservoirs.

An integrated approach involving Pressure Transient Analysis (PTA) and quantitative interpretation of time lapse seismic (4D) was developed to estimate production-induced compaction in a deep-water Gulf of Mexico reservoir. The integration of both engineering and geophysical technologies is a robust approach that aims to increase the accuracy and confidence in reservoir characterization. Multiple buildups were extracted and analyzed from the flowing history of the well. Since the well was equipped with a permanent downhole gauge, good quality extended duration buildups were available for analysis. The buildups were studied using analytical pressure transient models. The well was nearly horizontal with oil, water and gas flows and the effects on permeability due to compaction were isolated from the multiphase flow effects. 4D seismic interpretations were used to estimate the temporal strain changes in the shales above the depleted sands. A relationship between shale velocity change and strain change in the reservoir was used to infer the amount of compaction observed on the 4D seismic. The interpretations indicated relatively high rates of compaction at the reservoir depths and dilation in the shales above and below. The findings were used to quantify the level of compaction in terms of porosity change in the reservoir. Sequential analysis of historical buildups integrated with 4D seismic interpretations revealed that the reservoir absolute permeability had declined significantly due to compaction. Most of this decline could be attributed to a production event after which all the buildups indicated reduced permeability level. This suggested a plastic deformation in the rocks and a study of the pressure and rate history suggested that this deformation could be associated with a sudden decrease in the flowing bottom hole pressure around the production event causing an increase in drawdown. Using the porosity-permeability correlations, a 1-2 p.u. change in porosity was estimated. The quantification of the change in porosity and permeability due to sudden increase in pressure drawdowns can be used to help guide operational decisions, where compaction is a significant concern.

Summary A new method is presented that uses transient well testing to determine the in-situ absolute permeability of the formation when three phases of fluids are flowing simultaneously in the reservoir. The method was verified through simulation using synthetic data, and its applicability and practicality were confirmed through application to field data. Determining the absolute permeability over the reservoir scale using readily available transient testing data will have major benefits in accelerating history matching and improving reservoir-performance prediction. A recently developed method (Kamal and Pan 2010) to determine the in-situ absolute permeability under conditions of two-phase flow extended the applicability of transient well testing and has been adopted in commercial software. In this study, We extend the analysis method to determine the absolute permeability and fluid saturations when three phases are flowing in the reservoir. We show that an optimization procedure is needed to obtain the required results in this case. We show that the theoretical bases for the method presented to determine absolute permeability from transient tests under multiphase-flow conditions are the same as those used in obtaining relative permeability relations from core analysis and predicting reservoir performance in reservoir-simulation studies. The method presented in this study uses surface flow rates and the fluid properties of the three phases. It also uses the same relative permeability relations used in the simulation models, thus ensuring that the same permeability values calculated from field data are used in history matching and predicting the performance of the reservoir. It is assumed that the fluid saturations are relatively uniform in the region around the well at the time of the transient test. The method was verified by comparing the input values with the results obtained from analyzing several synthetic tests that were produced by numerical simulation. Data from a deepwater field were also used to test the practicality and validity of the method. For the field case, the method was verified by matching reservoir production and pressure using the calculated absolute permeability. Excellent agreements were obtained for both synthetic and field cases.

Summary Improved-oil-recovery (IOR) and enhanced-oil-recovery (EOR) methods are used to increase recovery from proven reserves, mainly after waterflooding. Monitoring and managing the progress of flood in IOR and EOR operations is currently a challenge to the oil industry, especially in situations with large well spacing and cost-prohibitive measures such as drilling observation wells (e.g., in offshore and deepwater applications). Falloff tests have proved to be successful under waterflooding operations to determine the reservoir properties in various banks around injection wells and the location of flood fronts. In this paper, we present a new development that extends transient testing and analysis technology to IOR and EOR operations during polymer flooding. With the expanded use of permanent downhole-pressure gauges (PDHGs), the newly developed technique can be used without additional testing cost or interruption of field operations. In this paper, the effects of polymer are described by shear-rate-dependent viscosity (non-Newtonian flow). We developed an analytical solution of wellbore pressure by combining the non-Newtonian fluids and the multicomposite reservoir models. The solution addresses the polymer region, where the fluids follow either the power law or Meter's model (Meter and Bird 1964), and the Newtonian flow in the oil or water regions ahead of the polymer, with varying Newtonian- and non-Newtonian-fluid saturations in both regions. The developed solution was validated by analyzing synthetic data generated using a commercial numerical reservoir simulator. In secondary-recovery operations, the Newtonian fluid ahead of the polymer bank is usually oil, and in tertiary-recovery operations, the Newtonian fluid is usually the water used in waterflooding. The solution provides a deeper understanding of the physics behind the pressure transient behaviors during polymer flooding, and can be applied to guide a better implementation of well tests. An interpretation method for falloff tests using the new solution and the conventional Bourdet derivative and Horner plots is presented, indicating that existing commercial well-testing software is sufficient to analyze data with the recent development. The new solution allows us to obtain reservoir properties such as fluid mobilities in various banks and the location of the flood front. The developed solution was applied to field data. The pressure behavior expected from the new solution was observed in the field data, validating our developed technique and yielding the characterization of reservoir parameters in various banks. Field-application results are shown in the paper. The novelty of this method of characterizing the dynamic properties of the various banks during injection of non-Newtonian fluids and the location of the flood fronts is that an analytical solution of pressure transient behavior in two-phase flow of non-Newtonian fluids and Newtonian fluids was developed, validated, and used to analyze field data. This is the first analytical solution published to address this situation.