Executive Summary

This issue of SPE Reservoir Evaluation and Engineering brings you 20 papers that reflect areas of current activity and interest in the industry. Five papers deal with various aspects of enhanced-oil-recovery processes, especially gas-injection processes. Five other papers specifically deal with enhanced waterflooding, primarily by low-salinity water injection. Four papers focus on heavy-oil-recovery processes, and another four papers deal with topics related to unconventional resources. The final two papers are related to reservoir fluid characterization and well log analysis.

Enhanced Oil Recovery. Long-Time Diversion in Surfactant-Alternating-Gas Foam Enhanced Oil Recovery From a Field Test describes interpretation of field data from a foam test in the Cusiana field in Colombia. The results of the test reflect the ability of foam to reduce gas mobility by at least a modest amount during long periods of gas injection. On the other hand, foam did weaken progressively as it dried out. Therefore, foam models in which foam remains strong at irreducible water saturation would not fit the long-time behavior seen in this field test. These results are important for estimating gas mobility near the well and injectivity in surfactant-alternating-gas foam field applications with large slugs of surfactant.
  
   Microscopic Fractal-Dimension Study of Rate and Viscosity Changes on Displacement Pattern by Use of 2D Glass Micromodel describes the results of glass micromodel visualization experiments to study the pore-level displacement patterns and structures that develop and progress at different flow rates and viscosity ratio of the fluids. The experiments cover a range of capillary numbers between 10 –8 to 10 –4 and viscosity ratios from 1 to 18. Different fractal dimensions are calculated to quantify the front shapes and displacement patterns that are observed on the images captured during each test. On the basis of the total saturation of injected fluid at breakthrough time, it is observed that a critical viscosity ratio can be defined below which recovery factor increases with injection rate and above which the recovery factor decreases with injection rate. It is also found that the viscous-fingering, capillary-fingering, and stable-displacement regions are consistent with the Lenormand et al. (1988) classification, and they can be quantified properly with the calculated fractal dimensions.
  
   A Case Study on Miscible and Immiscible Gas-Injection Pilots in a Middle East Carbonate Reservoir in an Offshore Environment describes two gas-injection pilots that have been implemented in offshore Middle East carbonate reservoirs to assess injectivity, productivity, sweep efficiency, flow assurance, and operational efficiency in a field that has a long water-injection history. A strong monitoring plan, including an observer well, was applied through time-lapse saturation logging, pressure measurements, production testing, and a tracer campaign to evaluate the pilot efficiency and address key uncertainties upfront before full-field application. The gas-injection performance was strongly affected by reservoir heterogeneity, gravity segregation, and the existing pressure gradient, and the history match indicates near-miscible or miscible behavior depending upon local pressure regimes, which thus govern the ultimate recovery. The history match also shows that for the same pilot, performance can be further improved through water-alternating-gas (WAG) injection, resulting in a viable development scheme for full-field implementation.
  
   Early-Time Analysis of Tracers for Use in Enhanced-Oil-Recovery Flood Optimization introduces a new method for analyzing interwell tracer test data at relatively early times that is based, in part, on a new way to extrapolate the tracer data, providing timely information to optimize flood performance. The extrapolation can be performed soon after the peak tracer concentration is observed in the well with the slowest response. The extrapolation procedure is illustrated with a synthetic, yet realistic, data set showing that the new method results in a good approximation at much earlier times. The “early-time analysis’ swept pore volumes are then compared with the (correct) swept pore volumes using the complete tracer data set. The early-time approximations can thus provide the opportunity to optimize chemical-flood performance and to enable field startup of EOR floods in a timely fashion.
  
   Ethane-Based Enhanced Oil Recovery: An Innovative and Profitable Enhanced-Oil-Recovery Opportunity for a Low-Price Environment summarizes the current state of the ethane industry in the US and explores the opportunity for using ethane for EOR. Simulation data and field examples are used to demonstrate that ethane is an excellent EOR injectant and that ethane-based EOR can supplement the very successful CO 2-based EOR industry in the US. Therefore, the current abundance of low-cost ethane from unconventional gas production presents a significant opportunity to add new gas EOR projects. 

Enhanced Waterflooding. Laboratory Investigations To Determine the Effect of Connate-Water Composition on Low-Salinity Waterflooding in Sandstone Reservoirs describes a laboratory study to investigate how the salinity and composition of the reservoir connate water affects low-salinity-waterflooding performance. Eleven spontaneous-imbibition experiments and six coreflood experiments were performed using two sandstone types (Bandera and Buff Berea) with different mineralogical compositions. It was found that reservoir cores saturated with connate water containing divalent cations (Ca and Mg) showed higher oil recovery than cores saturated with monovalent cations (Na).
  
   The Role of Individual and Combined Ions in Waterflooding Carbonate Reservoirs: Electokinetic Study describes an investigation into the role of brine ionic composition in carbonate-rock/fluid interactions and its effect on rock wettability. The study focused on indirect measurements of carbonate- and crude-oil-surface charges at different ionic composition and temperatures by use of new preparation procedures and advanced characterization techniques. The measurements provide insight into the effect of individual and combined dissolved cations and anions on surface charges and the conditions under which wettability of the rock can be altered to water-wet, thus enhancing oil recovery.
  
   The Role of Sandstone Mineralogy and Rock Quality in the Performance of Low-Salinity Waterflooding reports the results of coreflood, zeta potential, X-ray-powder-diffraction, X-ray-fluorescence, scanning-electron-microscope, nuclear-magnetic resonance, and high-pressure-mercury-injection experimental investigations of the effects of clay content, rock permeability, and pore-throat radius on low-salinity waterflooding (LSW). It was found that average pore-throat radius (rock quality) has a higher impact on the performance of LSW than in high-salinity waterflooding in the secondary recovery mode. The incremental oil recovery (microscopic) for LSW increased from 4.3 to 17% when the average pore-throat radius of the core increased from 1.4 to 8.5 mm. It was also found that the distribution of the clays seems to play a significant role, but not the total clay content and the clay composition.
  
   Wettability Alteration and Spontaneous Imbibition in Unconventional Liquid Reservoirs by Surfactant Additives reports on a study that combines the effect of wettability and interfacial-tension (IFT) alteration by surfactants and the corresponding effect on spontaneous imbibition in unconventional liquid reservoirs (ULRs) from the Permian Basin. A correlated experimental work flow was used, which includes conducting contact-angle (CA) and zeta-potential experiments, IFT measurements, and spontaneous-imbibition experiments combined with computed-tomography (CT) methods to evaluate and compare the efficiency of different surfactants in altering wettability and recovering hydrocarbons from siliceous core at reservoir temperature. From the results obtained, it can be concluded that the addition of proper surfactants to fracturing fluids has the potential of improving oil recovery by wettability and IFT alteration, with the anionic surfactant showing lower CAs and IFT, better imbibition, and higher oil recovery than nonionic and mixed surfactants in these siliceous ULRs from the Permian Basin.
  
   Single-Well Chemical-Tracer Modeling of Low-Salinity-Water Injection in Carbonates investigates modeling and simulation of a single-well chemical-tracer test (SWCTT) of low-salinity-water injection (LSWI) in a carbonate reservoir by use of a nonisothermal, 3D, multiphase, multicomponent, chemical compositional simulator. Both radial- and Cartesian-grid models are set up for a field-scale pilot by use of measured rock and fluid data of a Middle Eastern reservoir. Tracer reactions and the empirical LSWI model implemented in the simulator are used to estimate residual oil saturation (ROS) as a result of LSWI. Two approaches are used to estimate ROS to LSWI, including analytical and numerical methods. Results show that both approaches give consistent values for ROS for homogeneous radial- and Cartesian-grid models. The two approaches were inconsistent for the multilayer radial model, which highlights the necessity of the use of numerical approaches for layered reservoirs. The Cartesian-grid model was used to investigate the effect of heterogeneity on SWCTT results, where a new numerical approach is proposed for estimating ROS. The proposed approach can be used to estimate ROS of the SWCTT for reservoirs with different degrees of heterogeneity, which provides a clear insight into reservoir performance before planning multiwell demonstration pilots.

Heavy Oil. Semianalytical Modeling of Steam/Solvent Gravity Drainage of Heavy Oil and Bitumen: Unsteady-State Model With Curved Interface proposes an unsteady-state semianalytical model to predict the oil-flow rate in the steam/solvent-assisted gravity drainage (SA-SAGD) recovery process. The model assumes a curved interface with transient temperature and solvent distribution in the mobile zone. It also accounts for transverse dispersion and concentration-dependent molecular diffusion for solvent distribution. The oil-flow rate and interface profile are predicted at each time in an iterative fashion. The model is validated against the CMG-STARS thermal simulator as well as experimental results for hexane-aided SAGD physical-model tests. The semianalytical model was able to predict oil-production rates by use of different solvents coinjected with steam, in agreement with reported experimental data. The model may be used to estimate the optimal operation parameters for the process over a range of different reservoir qualities and pressures in a time-efficient manner.
  
   Experimental Analysis of Optimal Thermodynamic Conditions for Heavy-Oil/Bitumen Recovery Considering Effective Solvent Retrieval describes a sandpack experimental study to characterize solvent retrieval in solvent-injection process to improve heavy-oil/bitumen recovery from oil sands. Two heavy-oil samples (8.6 °API and 10.28 °API) from different fields in Alberta, Canada, and four light-hydrocarbon solvents (propane, n-hexane, n-decane, and distillate hydrocarbon) were used in this experimental scheme. Results showed that solvent retrieval increases when light-hydrocarbon solvents (propane and distillate hydrocarbon) are used compared with solvents with high molecular weight ( n-hexane and n-decane). Temperature and pressure highly influenced the solvent retrieval. The percentage of solvent retrieval increased when the hydrocarbon solvent was closer to the vapor phase (dewpoint). However, oil recovery showed significant reduction when propane and n-hexane were injected because of high asphaltene deposition on the sandpack.
  
   Pseudokinetic Model for Field-Scale Simulation of In-Situ Combustion focuses on a new pseudokinetic model to improve the representation of the combustion-zone effects and the fuel consumption in the field-scale in-situ-combustion (ISC) process. Along with the development of the pseudokinetic model, remedies are proposed for some shortcomings of the current reservoir simulation of ISC. The model allows maintaining the dependence of reaction rate with temperature through the use of appropriate activation-energy values. Furthermore, the model reduces the temperature-distribution effect by controlling the reaction rate on the basis of average-temperature values observed in the field-simulation model. The new pseudokinetic model should help improve the representation of the ISC process in field-scale reservoir simulation models.
  
   Water Coning, Water, and CO2 Injection in Heavy-Oil Fractured Reservoirs investigates challenges related to the recovery of heavy viscous oil from reservoirs with a dense network of fractures and vugs, but with a tight matrix and a strong underlying aquifer. To model potential recovery strategies, simulations are carried out with a higher-order finite-element (FE) compositional multiphase-flow reservoir simulator that includes a discrete fracture model and accounts for Fickian diffusion. Simulations with the 3D discrete-fracture model show excellent agreement with the laboratory experiments in which water is injected in a fractured stack saturated with oil. Next, the detrimental effect of water coning is considered by carrying out a parametric study investigating the impacts of different (1) water/oil mobility ratios, (2) matrix and fracture wettabilities, (3) matrix permeabilities, (4) domain sizes, (5) production rates, (6) well types and placement, and (7) a local viscosity-reduction treatment around producing wellbores. The only approach found to partially mitigate coning is to produce at low rates from perforated (and potentially multilateral) horizontal wells. As an alternative production strategy, CO 2 injection is also considered. CO 2 has a high solubility in this oil, and dissolution leads to volume swelling and a large reduction in oil viscosity. In combination with the much higher density difference between the phases, the latter improves gravitational drainage. Therefore, with CO 2 injection, a significant amount of matrix oil can be produced in addition to oil from fractures and vugs, and with a lower risk of water coning.

Unconventional Resources. Multiphase Linear Flow in Tight Oil Reservoirs provides a theoretical basis to explain the effect of different parameters on the behavior of solution-gas-drive tight oil reservoirs during transient linear two-phase flow producing at constant flowing pressure. It is shown that, with the Boltzmann transformation, the highly nonlinear partial-differential equations (PDEs) governing two-phase flow through porous media can be converted to two nonlinear ordinary-differential equations (ODEs). This transformation explains (a) the constant gas/oil ratio (GOR) that has been observed in some hydraulically fractured tight oil reservoirs and (b) the straight-line plot of 1/ qo and 1/ qg vs. √ t during constant-pressure two-phase production. An approximate analytical model is also developed. It is shown that the proposed approximate solution can be converted to a form similar to the well-known equations for single-phase flow, which enhances understanding of two-phase-flow behavior. Sensitivity studies are performed to examine the utility of the proposed model in predicting the performance of tight oil reservoirs. The applicability of the conclusions to the boundary-dominated flow period is investigated. On the basis of numerous simulation studies, it is shown that the impact of various parameters on boundary-dominated flow can be predicted with the transient solution, without the need for running multiple numerical simulations.
  
   A Material-Balance Equation for Stress-Sensitive Shale-Gas-Condensate Reservoirs presents a new material-balance equation (MBE) for estimation of original gas in place and original condensate in place in shale-gas-condensate reservoirs. This material-balance methodology allows estimating the critical time for implementing gas injection in those cases in which condensate buildup represents a problem. In addition, the proposed MBE considers the effects of free, adsorbed, and dissolved gas-condensate production, and also takes into account the stress-dependency of porosity and permeability. An extension of the methodology is implemented for estimating the optimum time for hydraulically refracturing shale-condensate reservoirs. 
  
   Analytical Modeling of Linear Flow in Pressure-Sensitive Formations describes analytical models to model production from hydraulically fractured tight formations with pressure-dependent permeability, for both constant-pressure and constant-rate production scenarios. By deriving an explicit relationship between time and pseudotime, it is shown that the analytical liquid solutions can be directly applied to pressure-dependent permeability reservoirs. This paper develops the appropriate transformation, and discusses its application by comparing the numerical solution of the nonlinear problem with the proposed analytical solution. The analytical models are used to assess whether permeability is decreased so much that a reduction in rate results when drawdown is increased. Depending on the strength of the nonlinearity, there could be a point beyond which the rate will not improve measurably as the flowing pressure is lowered. However, for a particular reservoir with a constant permeability modulus, it is not possible to reduce the production rate by increasing the drawdown. This is contrary to previous publications that suggest that in a reservoir with pressure-dependent permeability, there is an optimum drawdown for maximum production.
  
   Dependence of Shale Permeability on Pressure describes derivation of an equation relating shale permeability to pressure and geomechanical properties. This is important because the success of shale gas and oil developments depends on increasing fracture-based permeability with pressure caused by fluid injection. A simple equation relating shale permeability to pressure, Young’s modulus (a measure of the elasticity of the shale), and Poisson’s ratio is derived from the basic conservation-of-momentum equation. The use of this equation to predict shale permeability and, hence, the likely success of fracturing for any particular shale, on the basis of measured geomechanical properties is discussed.

Fluid Characterization. Microfluidic PVT-Saturation Pressure and Phase-Volume Measurement of Black Oils introduces a small-scale pressure/volume/temperature (PVT) cell that allows for the measurement of saturation pressure and phase-volume ratio by use of only a few microliters of black-oil samples. This novel PVT measurement technique has been successfully tested on live samples at elevated pressure (86 MPa) and temperature (150°C). In the microfluidic PVT platform, the small microfluidic device performs the same function as the laboratory-scale pressurized visual PVT cell. Because of the small thermal mass of the device, the temperature of the sample can be changed rapidly, which enables the measurement of multiple saturation pressures in quick succession. Below the saturation pressure, the growing gas bubbles form a segmented gas/liquid distribution in the capillary. The lengths of the liquid and gas segments are measured in real-time with an automated image-capturing and analysis tool to determine the gas/liquid phase-volume ratio at a given pressure. Validation tests have proved this technique to be repeatable and feasible for rapid PVT measurements of black oils [gas/oil ratio (GOR) ranging from 102 to 143 m 3/m 3].

Well Logging. Prediction of Resistivity Index by Use of Neural Networks With Different Combinations of Wireline Logs and Minimal Core Data describes an investigation of whether neural networks could be applied to predict special-core-analysis (SCAL) parameters, such as resistivity index (RI), from minimal training data. The study was undertaken in the Nubian sandstone formation of two Libyan oil fields (A-Libya and B-Libya). A series of different neural-network predictors, to predict RI, was trained in Well A-02 by use of laboratory measurements undertaken on SCAL plugs together with different combinations of associated wireline logs. The performance of the predictors was then tested in two test wells (Well A-01 in the same oil field as Well A-02, and Well B-01 in a different neighboring oil field). One set of neural-network predictors was trained on a data set containing all 55 SCAL plugs, along with the corresponding wireline-log data, from the Training Well A-02. This training data set is in itself relatively small compared with many previous neural-net studies in the petroleum industry. The predictions were then compared with another set of genetically-focused-neural-net (GFNN) predictors trained on a much smaller subset of just 14 SCAL plugs, again with the corresponding wireline-log data, from a representative genetic unit (RGU) in Well A-02. The RGU contained representative core plugs from each global hydraulic element (GHE) in that well. Remarkably, the predictors trained on the smaller subset of 14 representative SCAL plugs gave slightly better predictions, compared with the measured values throughout the test wells, than the predictors trained on the larger data set comprising 55 SCAL plugs. For Test Well A-01, even better results were obtained when the GFNN predictors were tested only in the interval equivalent to the RGU of Training Well A-02. Subsequently very good results were also obtained from GFNN predictors of the Amott-Harvey wettability index in Test Wells A-01 and B-01 when tested in the intervals equivalent to the RGU of Training Well A-02. This study demonstrates that the SCAL parameters investigated can be reasonably well-predicted from neural nets, and that the training data set can be quite small if one carefully chooses SCAL plugs that are representative of the petrophysical properties in the reservoir. This approach has the potential of saving both time and costs, because it requires only minimal SCAL data, and would be particularly useful for wells where no core material is available.

Conclusion. 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 Teletzke, SPE Res Eval and Eng Executive Editor;
ExxonMobil