Babadagli

In this issue of SPE Reservoir Evaluation & Engineering, eight papers focus on the advancements in enhanced oil recovery, unconventional gas reservoirs, and reservoir characterization/simulation.

Enhanced Oil Recovery

The first paper in this category A Pilot Carbon Dioxide Test, Hall Gurney Field, Kansas, provides an extensive analysis of a pilot CO₂ test conducted in the Hall Gurney Field, Kansas. CO₂ was injected continuously in a one-injector three-producer pattern for nearly nineteen months followed by eight-month waterflooding. At the end of the pilot test, nearly 20,000bbl oil was produced, not only from the three producers in the pattern but also in other neighboring five wells. CO₂ was injected at miscible or nearly miscible pressure conditions and a great portion of the CO₂ remained in the pilot region. The gross CO₂/oil ratio was estimated to be 4.8 MCF/bbl.

The second paper, Design Considerations of Waterflood Conformance Control with Temperature-triggered Low Viscosity Sub-micron Polymer, introduces a numerical modeling study on the improvement of waterflooding displacement efficiency using temperature-triggered sub-micron polymers with low viscosity. 3D thermal model results showed that the success of the process is primarily controlled by thief-zone to matrix permeability ratio and the placement location of the polymer. The suggested location of polymer was deep in the reservoirs close to the producer if the vertical-horizontal permeability ratio is high. The efficiency of the process could be improved if there is a high permeability layer between the injector and producer. Factors controlling the grade of the product were the temperature profile in the reservoir, interwell distance, injection rate, vertical-horizontal permeability ratio, mean residence time, and mobility ratio.

Estimation of the remaining oil in mature fields is a critical step in designing further enhanced oil recovery applications. Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field, introduces a mature carbonate field case in west Texas where a field-wide data acquisition program was conducted to estimate the remaining oil saturation (ROS). The authors tested and compared three methods used for this purpose; long-inject-log, chemical tracer tests, and core analysis. In general, the core analysis yielded the best representation of remaining oil saturation that was used in a subsequent project evaluation. The other two techniques showed a good performance in the zones with relatively homogeneous structure. They concluded that there is a wide distribution in oil saturations in this heterogeneous carbonate field and this may have a strong impact on the effectiveness of an EOR process.

Unconventional Gas and Gas-Well Testing

Geostatistical Population Mixture Approach To Unconventional Resource Assessment with an Application to the Woodford Gas Shale, Arkoma Basin, Eastern Oklahoma is the third in a series of papers aimed at enhancing the assessment of unconventional resources such as tight sands and gas shales through effective use of implicit and explicit information and accurate evaluation of the reserves. The authors demonstrated a methodology for evaluating assessment units with data showing high fluctuations in well density resulting from significant spatial variability of potential well productivity. They took an example of a shale gas reservoir from the Arkoma basin in eastern Oklahoma and showed that subdivision of the areas into as homogeneous units as possible can produce results comparable to those obtained using several variables correlated to local productivity.

The paper Establishing Key Reservoir Parameters with Diagnostic Fracture Injection Testing introduces an approach for diagnostic fracture injection testing for the evaluation of reservoir properties in unconventional formations. As opposed to previous studies that worked with the wellhead pressure using only the constant hydrostatic head correction during the falloff period, the authors explored rigorous heat transfer modeling to evaluate the bottom hole pressure. Also considered in the new approach was interpretation of the injection data to establish the fracture breakdown pressure. The wellbore heat-transfer model allowed estimation of the variable temperature profile along the wellbore that was also used to estimate changing fluid density and compressibility for different time steps, leading to the conversion of wellhead pressure to bottomhole pressure. The statistical analysis of the simulation results showed that the formation permeability is the most important variable controlling the fracture-closure time. Other parameters such as the Young's modulus of elasticity and the Poisson's ratio were observed to be less critical.

Estimating Drainage-Area Pressure with Flow-After-Flow Testing shows that flow-after-flow (AFA) testing can be used to estimate individual wells' average drainage-area pressure (p_av) for different well architecture, completion, and fluid types. After providing the theoretical framework for transient AFA testing, the authors demonstrated a pragmatic approach to handling pressure/rate data incoherence. The error correlations in p_av obtained for various well/reservoir types showed that kh is the most dominant variable, followed by the shape factor in vertical and well length in horizontal wells. It was concluded that as the values of the independent variables become larger, the error in the dependent variable, p_av, reduces due to rapid pressure equilibration before well shut-in.

Reservoir Characterization and Simulation

Two issues are critical in the petrophysical evaluation of thinly-bedded sand-shale reservoirs: (1) The recognition of thin bed geometries, and (2) the estimation of shale content from logs. In this regard, Numerical Simulation Investigation of the Effect of Heavy-Oil Viscosity on the Performance of Hydrocarbon Additives in Steam-Assisted Gravity Drainage  presents a systematic approach to evaluate thin-bed sand-shale reservoirs. A validated scaling factor was applied to the log-derived estimates of shale volume fraction. This was eventually used to estimate clay-mineral fraction for the porosity evaluation of sand layers. In these exercises, the multicomponent induction log was particularly adopted as a pivotal technology to evaluate the sand resistivity in thinly-bedded sand-shale sequences.

In the last paper of this issue, the paper titled History Matching and Production Forecast with Logs, as Effective Completion and Reservoir Managing Tools in Horizontal and Vertical Wells presents a reservoir simulation and history matching exercise relying primarily on well log data integrated with material balance, fluid data, pressure, and cores. The complex reservoir structure was divided into smaller material balance problems, i.e., each well, focusing one variable at a time, as opposed to similar approaches that apply to reservoirs as a whole. This well-based simulation and history matching practice was shown to be more advantageous compared to reservoir data based simulation applications in making strategic economic decisions to maximize reserves and optimize the reservoir development plan.

Tayfun Babadagli
Co-Executive Editor of SPE Res Eval & Eng