This issue of SPE Reservoir Evaluation and Engineering brings you 14 papers that reflect areas of current activity and interest in the industry. The mix of topics mirrors the increasing emphasis in our journal on unconventional resources and heavy oil since the discontinuation of the Journal of Canadian Petroleum Technology last year. Four papers focus on interpretation and prediction of multi-fractured horizontal well performance in unconventional resources. Another three papers deal with topics related to solvent-based processes to recover heavy oil. Three papers deal with various aspects of enhanced oil recovery processes. Another two papers deal with core analysis. The final two papers are related to reservoir modeling and well log analysis.
History Matching and Forecasting Tight Gas Condensate and Oil Wells by Use of an Approximate Semianalytical Model Derived From the Dynamic-Drainage-Area Concept describes a new analytical method, modeled after the dynamic drainage area concept, for history matching and forecasting multifractured horizontal wells (MFHW) experiencing multiphase flow during the transient and boundary-dominated flow periods. The method is validated against numerical simulation, covering a wide range of fluid properties and operating conditions. Field examples of MFHWs covering a wide range of fluid properties are also analyzed to demonstrate the practical applicability of the approach.
Multiphase Rate-Transient Analysis in Unconventional Reservoirs: Theory and Application presents a multiphase-pressure-diffusivity equation to analyze multiphase flow in single- and dual-porosity models of unconventional reservoirs. In addition to oil, gas, and formation brine, the method accounts for gas/condensate production and the flowback of the injected hydraulic-fracturing fluids. The paper includes diagnostic plots of rate-normalized well pressure for light oils and gas/condensates in unconventional reservoirs. Data from two Bakken and two Eagle Ford wells are presented to demonstrate the usefulness of the approach.
Flowback Fracture Closure: A Key Factor for Estimating Effective Pore Volume proposes a two-phase flowback tank model for interpreting multiphase flowback data from multistage-fractured wells. The objective is to introduce a simple approach for reducing parameter uncertainty and estimating fracture pore volume independent of fracture geometry. The model is applied to flowback data from 15 shale-gas and tight-oil wells to estimate the effective fracture pore volume and initial average gas saturation in the active fracture network. The results show that fracture pore volume is most sensitive to fracture closure, making it the primary drive mechanism during the early-flowback period.
Advances in Understanding Wettability of Tight Oil Formations: A Montney Case Study presents comprehensive rock/fluid experiments, using reservoir rock and fluids, to investigate wetting affinity of the Montney tight oil play in the Western Canadian Sedimentary Basin. This work is relevant for selecting optimum fracturing and treatment fluids and for defining appropriate relative permeability and capillary pressure curves. The results indicate that the effective pore network exhibits mixed-wet behavior and that in the presence of both oil and brine, the rock affinity to brine is higher than that to oil.
Relative Permeability of Foamy Oil for Different Types of Dissolved Gases describes the results of detailed laboratory experiments on foamy-oil flow through porous media. The objective is to clarify the physics of both the primary stage of cold-heavy-oil-production (CHOP) process but also post-CHOP enhanced oil recovery operations in which different gases are injected in heavy oil. Methane, propane, and CO2 were used in the tests mimicking post-CHOP EOR conditions. Among the gases tested, maximum oil recovery was obtained with CO2.
Solvent-Selection Criteria Based on Diffusion Rate and Mixing Quality for Steam/Solvent Applications in Heavy-Oil and Bitumen Recovery describes a laboratory study to characterize the criteria for selecting the optimal solvent to maximize recovery of heavy oil and bitumen using combined steam/solvent processes. Two main solvent-selection parameters – diffusion rate and mixing quality – were considered to evaluate solvent injection efficiency at different temperatures. A new image-processing-and-analysis technique was developed to measure diffusion rates. Viscosity measurements and asphaltene precipitation tests were performed to characterize mixing quality. The ideal solvent types for different oil types were determined by using the results from the diffusion-rate and mixing-quality experiments.
Experimental Investigation of Wettability Alteration in Oil-Wet Reservoirs Containing Heavy Oil describes a laboratory study to investigate the role of wettability alteration as a recovery mechanism in solvent-based processes to recover heavy oil. Different wettability-alteration agents were tested, including cationic and anionic surfactants, ionic liquids, nanofluids, high-pH solutions, and low-salinity water. The best wettability modifiers for weakly water-wet sandstone were found to be anionic surfactants, high-pH solutions, and ionic liquids. Cationic surfactants, high-pH solutions, and ionic liquids altered the wettability of oil-wet limestone better than other chemical solutions. In addition, it was found that solvent injection in heavy-oil-containing reservoirs is essential to dilute the heavy oil before any wettability-alteration treatment can take place.
Chemical-Reaction Mechanisms That Govern Oxidation Rates During In-Situ Combustion and High-Pressure Air Injection describes development of a new reaction framework for petroleum oxidation in oil recovery processes that involve air injection. Mechanisms proposed in the literature were screened to identify generally accepted reaction paths that could help reveal how oxidation occurs in petroleum reservoirs. Eight groups of fundamental reactions were found to dominate the oxidation rates of crude oils or their pyrolysis products. Various oxidation behaviors that were reported for both light and heavy crude oils were then compared and aligned with the eight identified reactions to create a framework for selecting pseudoreactions that can facilitate the prediction of the oxidation kinetics under a wide range of oilfield conditions.
The Use of Tracer Data To Determine Polymer-Flooding Effects in a Heterogeneous Reservoir, 8 Torton Horizon Reservoir, Matzen Field, Austria describes an application of tracers to aid interpretation of a polymer injection pilot in a heterogeneous reservoir. The tracer responses demonstrated that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. The tracer measurements were used to assess changes in the amount of water flowing from the injection well to production wells and to calculate polymer adsorption, residual resistance factor, and dispersivity. Along the flow path connecting injection and production wells, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume in the reservoir were in the same range as in corefloods.
Demulsifier in Injected Water for Improved Recovery of Crudes That Form Water/Oil Emulsion describes laboratory studies to investigate the addition of demulsifier to injected water to mitigate the adverse effects of water-in-oil (W/O) emulsions in waterflooding processes. Stable W/O emulsion formation was found to correlate with low total acid number (TAN) of the oil. A demulsifier was identified that led to significant reduction of pressure drop and pressure-drop fluctuations associated with W/O emulsion formation in corefloods when the demulsifier was injected at low (100 ppm) concentration in the carrier brine.
Gas/Oil Relative Permeability Normalization: Effects of Permeability, Wettability, and Interfacial Tension introduces a methodology to predict the gas/oil relative permeability for new rock/fluid conditions (such as permeability, wettability, and interfacial tension) by use of existing gas/oil relative permeability data measured at different conditions. It is shown that gas/oil relative permeability of rocks with different permeability and wettability conditions can be adequately predicted by applying an appropriate normalization technique. However, the effect of interfacial tension change cannot be captured by normalization techniques. To improve the methodology, a new hypothesis is introduced based on the concept of a dynamic trapped saturation. Finally, an improvement is offered to the Coats (1980) interfacial tension scaling method.
Estimation of Three-Phase Relative Permeabilities for a Water-Alternating-Gas Process by Use of an Improved Ensemble Randomized Maximum-Likelihood Algorithm proposes a modified ensemble randomized maximum-likelihood (EnRML) algorithm to estimate three-phase relative permeabilities for water-alternating-gas (WAG) injection with consideration of hysteresis. The proposed technique is first validated by use of a 1D synthetic coreflood model for three scenarios. Subsequently, the method is further applied to an actual coreflooding experiment to demonstrate feasibility of the method for determining three-phase relative permeabilities under realistic conditions.
Simultaneous History-Matching Approach by Use of Reservoir-Characterization and Reservoir-Simulation Studies introduces an approach for integrating history matching and reservoir characterization, applying a simultaneous calibration of different objective functions while honoring well data and maintaining geologic consistency during the history matching process. The approach includes a new proposal for reservoir characterization by use of virtual wells and a new way of combining multiple objective functions to calibrate candidate models while considering well-production data. A case study is presented to validate the proposed methodology.
Imaging Radial Distribution of Water Saturation and Porosity near the Wellbore by Joint Inversion of Sonic and Resistivity Logging Data presents a work flow for joint inversion of sonic flexural-wave dispersion data and array-induction resistivity data acquired in a vertical well. The work flow estimates the radial distribution of water saturation and porosity extending several feet into the formation at each log depth. Joint inversion of these data can help to characterize the formation beyond the zone affected by mud filtration and mechanical damage. The work flow is validated on synthetic data for several near-wellbore alteration scenarios and tested on field data form an offshore well drilled with oil-based mud in a gas-bearing clastic formation. The results are in good agreement with independent core analysis and traditional interpretation.
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.
Executive Editor, SPE Reservoir Evaluation & Engineering-Reservoir Engineering