Gary F. Teletzke, ExxonMobil Upstream Research Company
This is the first column of my 3-year term as Executive Editor of the reservoir-engineering section of SPE Res Eval & Eng. I’d like to begin by thanking my predecessor, Diederik van Batenburg, for his past 3 years’ of dedicated service as Executive Editor. I believe strongly that peer-reviewed journals play a key role in SPE’s mission to disseminate knowledge. With the support of our highly qualified review team of Associate and Technical Editors, as well as SPE staff, I’m looking forward to continuing the high standards of technical publication that have been established by Diederik and prior Executive Editors.
I am currently senior technical advisor for enhanced oil recovery (EOR) at ExxonMobil Upstream Research Company (URC), where I have been employed for more than 30 years. I’ve led research projects related to gas injection EOR, chemical EOR, CO2 sequestration, and compositional reservoir simulation. I have has also led several EOR field studies, integrating laboratory work, reservoir simulation, and pilot testing. I’ve long been active in SPE, serving as co-chair of the SPE Forum on Offshore EOR in 2008, and as a committee member of various reservoir engineering-related committees over the past 2 decades. Before being named Executive Editor, I was Technical Editor for SPE Res Eval & Eng during 2000–2006 and served as Associate Editor since 2007. I have published 35 technical papers and was named an SPE Distinguished Member in 2013. I hold a BS degree from Northwestern University and a PhD degree from the University of Minnesota, both in chemical engineering.
This issue of SPE Res Eval & Eng brings you 13 papers that reflect areas of current activity and interest in the industry. Four papers focus on topics related to reservoir modeling. Another two papers deal with modeling of naturally fractured reservoirs; two more papers deal with to analysis of production data. The final five papers are related to EOR.
Reservoir Modeling for Flow Simulation Using Surfaces, Adaptive Unstructured Meshes and an Overlapping-Control-Volume-Finite-Element Method proposes a surface-based approach to reservoir modeling that can replace conventional-grid-based methods. Its capabilities are demonstrated by use of a number of test models that capture aspects of geologic heterogeneity that are difficult or impossible to simulate conventionally, without introducing unacceptably large numbers of cells or highly nonorthogonal grids with associated numerical errors.
Modelling Unequilibrated Oil Saturations in a Chalk Reservoir, the South Arne Field Case describes saturation-height modeling of the preproduction-hydrocarbon distribution in a North Sea chalk field having an oil distribution strongly affected by fluid dynamics, even at initial conditions. To corroborate the dynamic trapping inferred from saturation-height modeling, reservoir simulation on a million-year time scale is deployed to analyze filling scenarios.
Best Practice in Static Modelling of a Coalbed Methane Field: An Example form the Bowen Basin in Australia proposes a work flow for estimating gas initially in place in a coalbed methane field. By integrating all available data, the work flow tackles the problem of scarcity of well control and geological data across a large geographic area by estimating the uncertainties associated with sparse control points. It has been successfully applied to a field in the northern Bowen basin in Australia.
Upscaling Kinetics for Field-Scale In Situ Combustion Simulation describes an investigation of the effectiveness of a non-Arrhenius kinetic upscaling approach for in-situ combustion processes. Performance improvements of the new approach compared to the traditional Arrhenius approach are demonstrated through numerical experiments in 1D and 2D for both homogeneous and heterogeneous permeability fields.
Material-Balance Method for Dual Porosity Reservoirs using Recovery Curves to Model the Matrix-Fracture Transfer presents a material-balance method applicable to naturally fractured dual-porosity reservoirs by depicting the matrix/fracture transfer in the form of recovery factor vs. time. An example application is presented to a field with more than 500 million STB of original oil in place and a 35-year production history. The method is a potentially valuable complement to numerical reservoir simulation of naturally fractured reservoirs.
Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs describes an investigation of the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. It is shown that the derivatives of pressure-transient tests in fractured reservoirs exhibit more than 10 flow regimes, depending on whether the well intersects fractures or is in the matrix; whether the fractures are fully or partially penetrating; the conductivity, size, distribution, and orientation of the fractures; and, finally, the wellbore-storage and skin effects.
Density-Based Production Data Analysis of Gas Wells with Significant Rock Compressibility Effects extends the applicability of a rescaled exponential and density-based decline analysis approach for the decline analysis of gas systems experiencing significant rock-compressibility effects. The proposed formulation enables the calculation and correct prediction of well performance and original gas-in-place by incorporating formation compressibility and the change of reservoir pore volume effects, which may prove crucially important in high-pressure and/or relatively large-formation-compressibility gas reservoirs
Analysis of Decline Curves Based on Beta Derivative presents a new simplified method for forecasting oil and gas production during transient and boundary-dominated flow, which does not require the use of complex analytical or numerical-modeling tools. The method has been corroborated with the use of numerical simulation and field data from the western Canada sedimentary basin and Mexico.
Enhanced Oil Recovery
Is Wettability Alteration the Main Cause for Enhanced Recovery in Low-Salinity Waterflooding? describes an attempt to investigate the role wettability alteration plays in low-salinity waterflooding by conducting (1) dual-drop/dual-crystal contact-angle measurements to characterize wettability changes and (2) coreflood experiments to determine oil recovery and oil/water relative permeability for a dolomite-reservoir-rock/fluids system. The wettability alterations as measured by contact angles showed a correlation with secondary-oil-recovery-mode coreflood experiments that yielded significantly higher recoveries because of low-salinity flooding, alteration of brine composition, and temperature.
Simulation of Polymer Injection under Fracturing Conditions—An Injectivity Pilot in the Matzen Field, Austria describes detailed polymer-injection simulations that included complex polymer rheology in the fractures and the matrix. The reservoir stress changes and their effects on the fractures were also taken into account as a result of cold-polymer injection. The simulations revealed two distinct phases during the injection of the polyacrylamide-polymer solution: (1) injection under matrix conditions in an early phase resulting in severe degradation of the polymer and (2) injection under fracturing conditions after the formation parting pressure is reached, leading to limited degradation of the polymer. The results of the field test and the simulations indicate that screening of fields for polyacrylamide-polymer projects needs to include geomechanical properties of the reservoir sand and cap/base rock in addition to the conventional parameters used in the simulations (e.g., oil viscosity, water salinity, reservoir temperature, and reservoir permeability).
Phase-Behavior Modeling and Flow Simulation for Low-Temperature CO2 Injection proposes a new equation-of-state modeling procedure to eliminate the three-hydrocarbon-phase region for reservoir-fluid/CO2 mixtures at low temperatures and studies its implication for flow simulation. The method is considered for two sector models from oil fields in west Texas, with fine-scale (more than 600,000 gridblocks) and upscaled models. Compared with the standard characterization, in which the three hydrocarbon phases exist, the new fluid model significantly improves the stability of flow simulation, demonstrating the robustness and efficiency of the new procedure. The method can be viewed as a practical approximation to field-scale simulations of CO2 injection at low temperatures.
Fitting Foam Simulation Model Parameters to Data: I. Co-Injection of Gas and Liquid presents a method for fitting parameters in foam reservoir simulation models to laboratory data for pressure gradient as a function of foam quality at a single superficial velocity. The model fit would be appropriate for an EOR process involving foam injection at finite water fraction, but not a surfactant-alternating-gas (SAG) foam process involving large slugs of gas and liquid. For the latter process, model parameters should be fit to data relevant to that process (i.e., at extremely high foam quality), as discussed in the next paper. The parameter values quickly obtained by the method described in this paper can provide the initial guess for a least-squares fit of all parameters and a check on the parameters so obtained.
Fitting Foam Simulation Model Parameters to Data: II. SAG Foam Applications illustrates how to fit foam-model parameters to steady-state foam data for application to injection of a gas slug in surfactant-alternating-gas (SAG) foam processes. For current foam models, the behavior of foam in SAG depends on three parameters: the mobility of full-strength foam, the capillary pressure or water saturation at which foam collapses and the parameter governing the abruptness of this collapse. The challenges that can arise in fitting of these model parameters to coreflood data are illustrated. Having accurate water-saturation data is essential to making a reliable fit to the data. It is also shown how the insights of fractional-flow theory can guide the model-fitting process and give quick estimates of foam propagation rate, mobility and injectivity at the field scale.
The above papers were all reviewed and ultimately approved in the peer-review process. However, the conclusions presented in these papers are not cast in stone. Because the sharing of knowledge and experiences is essential, SPE welcomes further “discussion” of any paper published in any SPE journal. Therefore, I again urge you to submit a discussion of a paper to SPE if you have alternative views on methods, interpretations, and/or conclusions presented or if the authors and reviewers have missed publications that either support or invalidate results.
Gary F. Teletzke
Co-Executive Editor of SPE Res Eval & Eng