Summary Reduction of fracture/well spacing and increases in hydraulic fracture stimulation treatment size are popular strategies for improving hydrocarbon recovery from multifractured horizontal wells (MFHWs). However, these strategies can also increase the chance of fracture interference, which can not only negatively impact the overall production but also introduce complexities for production data analysis. A semianalytical model is therefore developed to analyze production data from two communicating MFHWs and applied to a field case. The new semianalytical model uses the dynamic drainage area (DDA) concept and assumes three porosity regions. The three-region model is comprised of a primary hydraulic fracture (PHF), an enhanced fractured region (EFR) adjacent to the PHF, and a nonstimulated region (NSR). Assuming a well pair primarily communicates through PHFs, the equations for two communicating wells are coupled and solved simultaneously to model the fluid transfer between the wells. This method is used within a history-matching framework to estimate the communication between the wells by matching the production data. The semianalytical model is first verified against a more rigorous, fully numerical simulation model for a range of fracture/reservoir properties. These comparisons demonstrate that there is excellent agreement between the fully numerical simulation model results and the new semianalytical model. The semianalytical model is then employed to history-match production data from six MFHWs (drilled from two adjacent well pads) exhibiting different degrees of communication. For the purpose of history matching the data, only strong communication between pairs of wells (intrapair communication) is considered in the three-region model, and the results show good agreement with the field data. A flexible, yet simple, semianalytical model is developed for the first time that can accurately model the communication between multiple well pairs. This approach can be used by reservoir engineers to analyze the production data from communicating MFHWs.

Summary Low-salinity waterflooding and carbon dioxide (CO 2 ) injection are enhanced oil recovery (EOR) methods that are currently increasing in use worldwide. Linking these two EOR methods is a promising approach in the exploration of mature fields and for post- and presalt basins in Brazil. Moreover, the latter reservoirs already exhibit a high CO 2 content by nature. Interfacial phenomena between fluids and rock in a low-salinity water-CO 2 (LSW-CO 2 ) environment remain unclear, particularly the wettability behavior that is related to the pH of the medium, among others. This study investigates the influence of rock composition and pH of the brine on reservoir wettability through coreflooding and zeta potential experiments in LSW and determination of contact angles and interfacial tension (IFT) in the crude oil-LSW-CO 2 system at reservoir conditions. Brazilian light crude oil, pure CO 2 , and brine solutions of different concentrations and compositions were used to represent the fluids in actual oil reservoirs. The experiments were carried out on Botucatu sandstone, Indiana limestone, and calcite crystal samples, with mineralogy determined by energy dispersive X-ray (EDX) analysis. Coreflooding experiments were conducted by the injection of 10 pore volumes (PVs) of fourfold diluted synthetic reservoir brine (SRB), followed by 10 PVs of 40-fold diluted SRB to evaluate the low-salinity effects. Interfacial properties, such as contact angle and IFT, as well as density and pH, were determined at elevated pressures to evaluate the synergistic effects between CO 2 and salt content. In addition, geochemical modeling using PH REdox EQuilibrium (in C language) (PHREEQC) was performed to predict the in-situ pH and match with the experimental data. An increase in oil recovery and pH of the effluent was observed in the coreflooding experiments during diluted SRB injection. The ionic concentrations of the effluent samples also indicated illite dissolution. Furthermore, zeta potential measurements confirmed the expansion of the water film and shift from positive to negative surface charge of Botucatu sandstone for salt concentrations less than 80,000 mg/L at pH > 7, whereas in Indiana limestone, negative surface charge was only observed in deionized water at pH > 9. These observations indicate that during LSW injection alone, an increase in pH will favor a thicker water layer on the Botucatu sandstone surface that in turn increases water wettability and results in increased oil recovery. Conversely, the presence of CO 2 in LSW causes a decrease in the pH of the medium, which is related to further enhancing water wettability when linking pH with contact angle measurements. It seems that a change in the pH of the brine induced by CO 2 solubility in LSW enhanced interactions between the rock surface and water molecules. The respective interfacial energy then decreased, resulting in a decreasing water contact angle. It was also noticed that seawater-CO 2 systems caused salt precipitation and mineralogical changes in carbonate and sandstone rock induced by calcite and kaolinite dissolution, respectively. This study contributes substantially to the understanding of interfacial properties and wettability behavior in LSW-CO 2 systems, facilitating the design of LSW-CO 2 EOR applications in Brazilian fields or even CO 2 storage. Moreover, the study provides useful data for oil companies that have acquired mature wells and exploration blocks in Brazil, supporting them in operational and investment decisions.

Summary This paper gives a critical review of miscibility-measurement techniques published in the open literature along with recommendations and lessons learned. Many of these published methods violate the inherent assumptions for multicontact miscibility (MCM). The confusion often arises from a failure to distinguish between first-contact miscibility (FCM), in which two fluids can be mixed in all proportions without forming two phases, and MCM, in which fluid compositions that arise during the flow of two phases in a porous medium approach a specific critical point within the constraints of the MCM definition. There are many analytical, numerical, correlational, and experimental methods available to estimate the minimum miscibility pressure (MMP) for MCM flow. The numerous available methods, some of which are quite inexpensive, have caused significant misunderstandings in the literature and in practice regarding their ability to estimate MMP. Our experience has shown that the best methods are those that honor the multicontact process (MCM), in which flow interacts with phase behavior in a prescribed way. Good methods that achieve this are slimtube experiments, detailed slimtube simulations, multiple-mixing-cell calculation methods, and the method of characteristics (MOC). Techniques such as the rising-bubble-apparatus (RBA) and vanishing-interfacial-tension (IFT) (VIT) experiments are subject to significant uncertainties, although they can still provide useful information. Numerous MMP correlations have been developed. They should be used with caution for systems similar to those used to develop the correlation. Use for other fluid systems can lead to significant errors. We discuss the advantages and disadvantages of most current methods and show that various combinations of methods can reduce uncertainty.

Summary The heavy-oil- and bitumen-recovery process by injection of a pure condensing solvent in a solvent vapor chamber provides an alternative to steam-based recovery techniques such as steam-assisted gravity drainage (SAGD). Because of the lower operating temperature between 40 and 80°C, the process uses a much lower energy budget than a steam process and thus results in significantly reduced greenhouse-gas emissions. This paper describes the route to a successful production function with the physical processes at play and using analytical tools. Physical relationships are derived for the solvent/bitumen (S/B) ratio, the bitumen drainage from the roof of the solvent vapor chamber, and for bitumen extraction from both sides of the solvent chamber by the draining condensed solvent. The fast diffusion of bitumen into this narrow liquid solvent zone is likely subtly enhanced by transverse dispersion. The speed of bitumen extraction from the roof of the solvent vapor chamber is constrained by the gas/oil capillary pressure. Extraction from the side of the chamber is approximately three times faster by the action of the thin gravity-draining liquid solvent film. Several equations are provided to enable creation of a heat balance for this condensing solvent process. Laboratory and field observations are matched, including the rates, the heat balance, and the S/B ratio. The model can explain constrained production performance by identifying the rate-limiting steps (e.g., when insufficient solvent condenses). The model predicts high solvent holdup during the rise of the solvent chamber. A method to estimate this solvent liquid saturation is provided. The S/B ratio depends on injector-wellbore heat losses, the (high) liquid saturation in the rising solvent chamber, and the process properties (operating temperature), reservoir properties (heat capacity, porosity, and oil saturation), and solvent properties (density and latent heat). In the existing body of literature, no satisfactory analytical model was available; this new approach helps to constrain production performance and to estimate solvent and heat requirements. The methods in this paper can be used in the future for subsurface project design and performance predictions.

Summary A potential enhanced oil recovery technique is to inject alkali into a reservoir with a high-total acid number (TAN) crude to generate soap in situ and reduce interfacial tension (IFT) without the need to inject surfactant. The method may be cost-effective if the IFT can be lowered enough to cause significant mobilization of trapped oil while also avoiding formation of gels and viscous phases. This paper investigates the potential field application of injecting alkali to generate in-situ soap and favorable phase behavior for a high-TAN oil. Oil analyses show that the acids in the crude are a complex mixture of various polar acids and not mainly carboxylic acids. The results from phase behavior experiments do not undergo typical Winsor microemulsion behavior transition and subsequent ultralow IFTs below 1×10 −3 mN/m that are conventionally observed. Instead, mixing of alkali and crude/brine generate water-in-oil macroemulsions that can be highly viscous. For a specific range of alkali concentrations, however, phases are not too viscous, and IFTs are reduced by several orders of magnitude. Incremental coreflood recoveries in this alkali range are excellent, even though not all trapped oil is mobilized. The viscous phase behavior at high alkali concentrations is explained by the formation of salt-crude complexes, created by acids from the crude oil under the alkali environment. These hydrophobic molecules tend to agglomerate at the oil-water interface. Together with polar components from the crude oil, they can organize into a highly viscous network and stabilize water droplets in the oleic phase. Oil-soluble alcohol was added to counter those two phenomena at large concentrations, but typical Winsor phase behavior was still not observed. A physicochemical model is proposed to explain the salt-crude complex formation at the oil-water interface that inhibits classical Winsor behavior.

Summary Optimal spacing between fracture clusters has eluded reservoir and completions engineers since the inception of multistage hydraulic fracturing. Very small fracture spacing could result in fracture to fracture (intrawell) interference and a higher completion cost, whereas very large fracture spacing could lead to inefficient hydrocarbon recovery, which is detrimental to the well economics. Meramec Formation has moved to full‐field development, and multiple wells are put on production in a relatively short time. Depending on the desired economic metric, net present value (NPV), or rate of return (ROR), the magnitude of intrawell interference can be optimized by adjusting fracture spacing. For instance, if the objective is to maximize ROR, then tighter fracture spacing can be accepted. Furthermore, petroleum economics are often ignored in simulation studies, particularly the concepts of time value of money and oil‐price sensitivity. This has led to a knowledge gap in identifying optimal drawdown procedure and fracture spacing from numerical models. This study proposes a framework that integrates petroleum economics with simulation results to optimize a horizontal well from the Meramec Formation. On the basis of this framework, we identified optimal drawdown procedure and fracture spacing. Then, oil‐pricing sensitivity analysis was conducted to illustrate the effect of oil‐price volatility on design parameters. Moreover, this study investigates the relative contribution of reservoir and completions characteristics with regard to short‐ and long‐term well performance. These characteristics include drawdown management, fracture spacing, pressure‐dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model that is used to history match a well from the Meramec Formation. The geologic model covers an area of 640 acres that encompasses a multistage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than 2 years of continuous production without being disturbed by offset operations. Findings suggest that the drawdown strategy (aggressive vs. conservative) has more effect on short‐term oil productivity than fracture spacing. Drawdown strategy even has more of an effect on short‐term oil recovery than does a 20% error in porosity, or water saturation. Furthermore, the profile of the producing‐gas/oil ratio (GOR) depends on completions efficiency, and it has been interpreted using linear‐flow theory.

Summary Seawater injection is widely used to maintain offshore-oil-reservoir pressure and improve oil recovery. However, injecting seawater into reservoirs can cause many issues, such as reservoir souring and scaling, which are strongly related to the seawater-breakthrough percentage. Accurately calculating the seawater-breakthrough percentage is important for estimating the severity of those problems and further developing effective strategies to mitigate those issues. The validation of using natural-ion boron as a tracer to calculate seawater-breakthrough percentage was investigated. Boron can interact with clays, which can influence the accuracy in seawater-breakthrough calculation. Therefore, the interaction between boron and different clays at various conditions was first studied, and the Freundlich adsorption equation was used to describe the boron-adsorption isotherms. Then, the boron-adsorption isotherms were coupled into the reservoir simulator to investigate the boron transport in porous media, and the results in turn were further analyzed to calculate the accurate seawater-breakthrough percentage. Results indicated that boron adsorption by different clays varied. pH value of solution can significantly influence the amount of boron adsorbed. As a result, the boron-concentration profile was delayed in coreflood tests. The accuracy of the new model was verified by convergence rate tests and comparison with analytical results. Furthermore, model results fit well with experimental data. On the basis of the reservoir-simulation results, the boron-concentration profile in produced water can be used to calculate the seawater-breakthrough percentage by considering the clay-content distribution. However, the seawater-breakthrough point cannot be determined by boron because the boron concentration is still at the formation level after seawater breakthrough due to boron desorption.

Summary A technique to quickly determine the asphaltene onset pressure (AOP) of a crude oil from low‐volume, nonequilibrium measurements is presented. The pressure at which the optical signature indicative of asphaltene aggregation is first detected in recombined crude oils is found to decrease strongly with the rate of depressurization and can be well‐described with a modified power law. This technique exploits this rate dependence and uses two separate decompressions at highly disparate depressurization rates to determine the AOP. Benchmarking with this technique was performed with recombined crude oils that were characterized with conventional pressure/volume/temperature analysis. Using this technique, measurements enabling the determination of the AOP of a live crude oil can be obtained in minutes with a nominal uncertainty of 500 psi. This is a significant reduction in time compared with the multihour process used for conventional equilibrium‐based measurements. Onset‐time data from these studies are consistent with conventional aggregation theories, but there is insufficient range to differentiate between reaction‐limited aggregation (RLA) and diffusion‐limited aggregation (DLA).

Summary Advances in horizontal drilling and multistage hydraulic fracturing have unlocked tight-oil resources, such as the Montney Formation in the Western Canadian Sedimentary Basin. However, the average oil‐recovery factor after primary production is 5 to 10% of the original oil in place. The aims of this study are to investigate phase behavior and to estimate the minimum miscibility pressure (MMP) of the Montney oil/natural‐gas systems. First, we measure the MMPs of the oil/gas systems using the vanishing interfacial tension (VIT) technique. The gas samples are methane (C 1 ) and mixtures of methane and ethane (C 1 /C 2 ). Second, we perform constant‐composition‐expansion (CCE) tests to study the phase behavior of the oil/gas systems using a pressure/volume/temperature (PVT) cell. To complement the VIT and CCE tests, we perform bulk‐phase tests to visualize vaporizing/condensing phenomena at the oil/gas interface using a visualization cell. Finally, we use the measured CCE and MMP data to calibrate the Peng-Robinson (Robinson and Peng 1978 ) equation of state (PR‐EOS) and predict the MMP of the oil/gas systems using ternary diagrams. The results suggest that the dominant mechanism for developing miscibility conditions for oil/C 1 and oil/C 1 /C 2 systems is vaporizing and condensing gas drive, respectively. According to the results of the VIT and CCE tests, increasing C 2 mole fraction in the gas mixtures significantly reduces MMP of the oil/gas system (from 4,366 psi for oil/C 1 to 1,467 psi for oil/C 1 /C 2 with 71.3 mol% C 2 ) and increases the oil‐swelling factor (from 1.47 to 1.61 by increasing C 2 mol% from 0 to 70 mol%). The results of visualization tests show that the presence of C 2 in the injection gas significantly enhances oil swelling compared with the pure‐C 1 case. We observe vaporizing flows of oil components in all tests and strong condensing flows of C 1 and C 2 into the oil phase in the C 1 /C 2 test with increasing gas‐injection pressure. The MMP values predicted by plotting two‐phase equilibrium data on ternary diagrams appear to be in good agreement with the measured ones. The results can be used to optimize the injection‐gas composition and operating pressure in the Montney.

Summary Foamy oil flow is a commonly encountered drive mechanism in the primary production (depletion of naturally methane‐saturated heavy oil) and secondary stage (cyclic gas—mostly methane—injection after primary production). In the former, among other important parameters, pressure depletion rate has been reported to be the most crucial parameter to control the process. In the latter, type and amount of the gas (also described as “solvent”) and application conditions such as soaking time durations and depletion rates are critical. The cornerstone of the foamy oil behavior relies on its stability, which depends on parameters such as oil viscosity, temperature, dissolved gas ratio, pressure decline rate, and dissolved gas (solvent) composition. Although the process has been investigated and analyzed for different parameters in the literature, the optimal conditions for an efficient process (mainly foamy oil stability) has not been thoroughly understood, especially for the secondary recovery conditions (cyclic solvent injection, CSI). In this paper, internal and external gas drive mechanisms for foamy oil performance are reviewed in detail. The optimal conditions of the applications were compiled and listed for different primary production and secondary recovery stages. Combination of methane with other gases as a CSI practice was also discussed to accelerate the process and reduce cost in an effort to improve efficiency. It is reported that combining methane injection with air as a secondary recovery method can save up to 51% of solvent gas.

Summary Phase change plays an essential role in wettability during steam injection, and oil becomes the wetting phase in the steam zone. This study investigates this unfavorable phenomenon using visual data obtained from micromodel experiments and how the wettability can be reversed using chemicals. All measurements were conducted at temperatures up to 200°C on glass‐bead micromodels. The models were initially saturated with brine solution and then displaced by two types of mineral oils (450 and 111,600 cp at 25°C). Steam was then constantly injected into the micromodels to evaluate the effect of phase change and wettability status on residual saturation development. Next, chemical additives, screened from the previous contact‐angle and thermal‐stability measurements, were added to the steam to observe their ability in modifying phase distribution and wettability state. The results showed that phase distribution and residual oil saturation are critically sensitive to the steam phase. At any circumstances, wettability alteration with chemicals was possible. The shape and characteristics of the trapped oil with and without chemicals were identified through micromodel images, and suggestions were made as to the conditions (pressure, temperature, and time to apply during the injection application) at which these chemicals show optimal performance.

Summary The coexisting free gas, solution gas, and oil in a tight oil reservoir, constrained by the capillary force of the micrometer/nanometer pore/pore‐throat system, are of crucial importance to the sweet spot of a tight oil reservoir. Equations of modified total capillary force for the liquid phase are proposed to indicate the tight oil mobility in situ, and are derived from the Kelvin capillary force equation, the Peng‐Robinson (PR) equation of state (EOS) (Robinson et al. 1977 ), and the Van-Laar (VL) equation (Renon and Prausnitz 1968 ). In addition, relationships between the vapor/liquid state, phase‐flow state for production, and gas/oil ratio (GOR) are established in correspondence with the production data of North American and Chinese (Yanchang) tight oil plays. The following conclusions can be drawn. We proposed a modified total capillary force function to indicate the tight oil mobility in situ, using the PR EOS method and the EOS+ λ (VL equation) method. We identified five phase stages according to the gas volume ratio ( y i ) in situ: the single‐phase oil flow stage, the multiphase transient‐flow stage, the multiphase stable‐flow stage, the multiphase supercritical‐flow stage, and the single‐phase gas flow stage. Tight oils are more mobile in three stages: near the critical point of y i ‐critical(1) , such as in the Yanchang and Bakken tight oils; at the transition zone between oil and wet‐gas zones before y i ‐critical(2) , such as in the Eagle Ford tight oil; and between the y i ‐critical(2) and y i ‐critical(3) in a gas-condensate state, which is at the transition zone between wet‐gas and dry‐gas zones.

Summary Chemical enhanced oil recovery (EOR) leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high total acid number (TAN) could be produced by the injection of alkali. Alkali might lead to the generation of soaps and emulsify the oil. However, the generated emulsions are not always stable. Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. On the basis of the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in the formation of initial emulsions is observed. Micromodel experiments are performed to investigate the effects on the pore scale. For the injection of alkali into high‐TAN oils, the mobilization of residual oil after waterflooding is seen. The oil mobilization results from the breaking up of oil ganglia or the movement of elongated ganglia through the porous medium. As the oil is depleting in surface‐active components, residual oil saturation is left behind either as isolated ganglia or in the down gradient side of grains. Simultaneous injection of alkali and polymers leads to a higher incremental oil production in the micromodels owing to larger pressure drops over the oil ganglia and more‐effective mobilization accordingly. Coreflood tests confirm the micromodel experiments, and additional data are derived from these tests. Alkali/cosolvent/polymer (ACP) injection leads to the highest incremental oil recovery of the chemical agents, which is difficult to differentiate in micromodel experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micromodels, the incremental oil recovery is also higher for alkali/polymer (AP) injection than with alkali injection only. To evaluate the incremental operating costs of the chemical agents, equivalent utility factors (EqUFs) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and, hence, the lowest chemical incremental operating expenditures are incurred by the injection of Na 2 CO 3 ; however, the highest incremental recovery factor is seen with ACP injection. It should be noted that the incremental oil recovery owing to macroscopic‐sweep‐efficiency improvement by the polymer needs to be accounted for to assess the efficiency of the chemical agents.

Summary The objective of aqueous-surfactant formulation design is to achieve ultralow interfacial tension (IFT) with the oil in place at reservoir conditions. Several parameters have to be investigated, and among them, it is well-known that the presence of gas dissolved in crude oil can greatly affect the surfactant/brine/crude-oil-microemulsion phase behavior. Omitting it might degrade the formulation performance. In this work, we present a combined experimental and theoretical investigation of optimal-salinity evolution as a function of live-oil compositions and conditions, varying the pressure independently of the gas/oil ratio (GOR) (i.e., the amount of gas dissolved in crude oil). A specific high-pressure/high-temperature (HP/HT) sapphire cell with a mobile piston is used to separately study the effect on the optimal salinity of the GOR by adding different amounts of n -alkanes methane (C 1 ), ethane (C 2 ), and propane (C 3 ) at the corresponding saturation pressure, and the effect of pressure (up to 500 bar) is studied in a second cell by varying the cell volume (without changing the live-crude-oil composition). Using the HP/HT sapphire cell, we show that GOR variations (tested values up to 135 std m 3 /m 3 ) induce important modifications of the brine/surfactant/oil-microemulsion phase behavior. In the case of the studied fluids, experimental data indicate that the optimal salinity of the brine/surfactant/oil system decreases linearly when increasing the amount of gas dissolved in the live crude oil. As a consequence of the Salager relation (Salager et al. 1979), the equivalent alkane carbon number (EACN) of the live crude oil varies linearly with the GOR. We demonstrate hereafter that the cell pressure alone (up to 500 bar), for a fixed composition (i.e., fixed GOR), affects neither the formation nor the stability of the Winsor III (WIII) microemulsion. Furthermore, results suggest that the composition of the dissolved representative gas can have an effect on the microemulsion phase behavior. Three models have been evaluated to estimate EACN values for 13 live crude oils and for the two live oils of interest in this study [Crude Oil 1 and n -tetradecane ( n -C 14 )]. We compared predictions with our new experimental data. The Creton and Mougin (2016) model quantitatively predicts the behavior of live oils and agrees with the negligible effect of pressure on microemulsion formation and stability.

Summary The solvent thermal resource innovation process (STRIP), a downhole steam‐generation technology, has the capacity to show improved recovery factors with a significantly reduced environmental footprint compared with traditional thermal‐enhanced‐oil‐recovery (TEOR) methods, most notably by delivering all the combustion heat to the pay zone. In this effort, a quarter‐symmetry inverse‐five‐spot model and a multiphase, multicomponent reservoir‐simulation framework were used to simulate the STRIP technology. Commercial simulators such as STARS - Thermal and Advanced Processes Reservoir Simulator [Computer Modelling Group Ltd. (CMG), Calgary, Alberta, Canada; CMG 2015b] often use the K ‐value approach to simulate TEOR. However, the method cannot simulate STRIP's carbon dioxide (CO 2 ) and steam coinjection because the K ‐value method does not consider miscible gas injection. On the other hand, CMG's GEM - Compositional and Unconventional Simulator (CMG 2015a) includes the effects of miscible gases but does not provide comprehensive support for steam‐injection processes, which are better handled by STARS. The novel simulation framework developed here leverages and combines the individual strengths of STARS (thermal features) and GEM (compositional features). In this framework, STARS simulated steam injection (but cannot directly simulate the effects of CO 2 ) and was the governing model that synchronized temperature, pressure, and phase saturations for two parallel iterations of the GEM models (GEM‐1 and GEM‐2) at each timestep. Immiscible methane (CH 4 ) was added to GEM models to maintain gas saturations equivalent to the STARS model. GEM‐1 simulated hot‐water and CH 4 injection, but at increased rates to yield a pressure field and gas saturations equivalent to STARS. A final run of GEM‐1 injected both CO 2 and hot water and demonstrated the expected increase in oil production. Calibrated injection rates from GEM‐1 were specified in GEM‐2 to ensure equivalence of the pressure field. Next, the GEM‐2 model also simulated hot‐water and CH 4 injection, but matched both water and oil productions along with oil saturations from the final GEM‐1 run by altering relative permeabilities. Finally, the updated relative permeabilities were fed back to STARS, and iteration proceeded. Results from this framework were verified against a STARS steam‐injection simulation. Finally, when considering coinjection of CO 2 , STRIP's superior performance was demonstrated through increased oil recovery and a lower steam/oil ratio (SOR).

Summary The Todd and Langstaff (1972) mixing parameter ( ω ) is the most commonly used parameter in black oil reservoir simulators for modeling the effects of viscous fingering on a field scale, as their model is a useful alternative to compositional simulations. Todd and Longstaff (1972) recommended a choice for the value of ω to be ⅔ for secondary miscible gas injection to match the recovery of oil from Blackwell et al. (1959) experiments and ω to be 1 3 for secondary miscible gas injection on a field scale to account for field‐scale heterogeneities. Blunt and Christie (1993) extended the model and showed that ω needs to be calibrated for simultaneous water alternating gas (SWAG) injection. They showed that the mixing parameter should be increased to 1 when modeling secondary miscible SWAG injection, and to 0.92 when modeling tertiary miscible SWAG injection. This work is a modification of Blunt and Christie's (1993) work to calibrate the value of ω for miscible finite‐sized slug water alternating gas (FSS WAG) injection. In this paper we focus on the impact of WAG ratio, slug size, and type of recovery on the calibration of Todd and Longstaff's (1972) mixing parameter to highlight the importance of taking this parameter into account when simulating miscible FSS WAG injection using a black oil simulator. The value of ω was computed by matching the solvent concentration and the water saturation profiles from the 1D model against the 2D simulation. The results show that as the slug size increases, the value of ω decreases at different WAG ratios for both secondary and tertiary recovery. The application of the calibrated value of ω on a field scale showed that the value of ω had an impact on the oil recovery and on the total gas and water production, highlighting the importance of an appropriate mixing parameter selection.

Summary Straight‐line analysis (SLA) methods, which are a subgroup of model‐based techniques used for rate‐transient analysis (RTA), have proved to be immensely useful for evaluating unconventional reservoirs. Transient data can be analyzed using SLA methods to extract reservoir/hydraulic‐fracture information, whereas boundary‐dominated‐flow (BDF) data can be interpreted for fluid‐in‐place estimates. Because transient‐flow periods might be extensive, it is also advantageous to evaluate the volume of hydrocarbons in place contacted over time to assist with reserves assessment. The new SLA method introduced herein enables reservoir/fracture properties and contacted fluid in place (CFIP) to be estimated from the same plot, which is an advantage over traditional SLA techniques. The new SLA method uses the Agarwal ( 2010 ) approach for CFIP estimation, extended to variable‐rate/pressure data for low‐permeability (unconventional) reservoirs. A log‐log plot of CFIP vs. material‐balance time (for liquids) or material‐balance pseudotime (for gas) is created, which typically exhibits power‐law behavior during transient flow, and reaches a constant value [original fluid in place (OFIP)] during BDF. Although CFIP calculations do not assume a flow geometry, the SLA method requires this to extract reservoir/fracture information. Herein, transient linear flow (TLF) is assumed and used for the SLA‐method derivation, which allows the linear‐flow parameter (LFP) to be extracted from the y ‐intercept (at material‐balance time or material‐balance pseudotime = 1 day) of a straight‐line fit through transient data. OFIP can also be obtained from the stabilization level of the CFIP plot. Validation of the new SLA method for an undersaturated oil case is performed through application to synthetic data generated with an analytical model. The new SLA results in estimates of LFP and OFIP that are in excellent agreement with model input (within 2%). Further, the results are consistent with the traditional SLA methods used to estimate the LFP (e.g., the square‐root‐of‐time plot) and the OFIP (e.g., the flowing material‐balance plot). Practical application of the new SLA method is demonstrated using field cases and experimental data. Field cases studied include online oil production from a multifractured horizontal well (MFHW) completed in a tight oil reservoir, and flowback water production from a second MFHW, also completed in a tight oil reservoir. Experimental (gas) data generated using a recently introduced RTA core‐analysis technique were also analyzed using the new SLA method. In all cases, the new SLA‐method results are in excellent agreement with traditional SLA methods. The new SLA method introduced herein is an easy to apply, fully analytical RTA technique that can be used for both reservoir/fracture characterization and hydrocarbon‐in‐place assessment. This method should provide important, complementary information to traditionally used methods, such as square‐root‐of‐time and flowing material‐balance plots, which are commonly used by reservoir engineers for evaluating unconventional reservoirs. The method is currently limited to cases exhibiting single‐phase flow, the flow‐regime sequence of TLF to BDF, and reservoir homogeneity. In future work, these limitations will be resolved.

Summary Recently, there has been an increasing interest in enhanced oil recovery (EOR) from shale‐oil reservoirs, including injection of carbon dioxide (CO 2 ) and field gas. For the performance assessment and optimization of CO 2 ‐ and field‐gas‐injection processes, compositional simulation is a powerful and versatile tool because of the capability to incorporate reservoir heterogeneity, complex fracture geometry, and multiphase and multicomponent effects in nanoporous rocks. However, flow simulation accounting for such complex physics can be computationally expensive. In particular, field‐scale optimization studies requiring a large number of high‐resolution compositional simulations can be challenging and sometimes computationally prohibitive. In this paper, we present a rapid and efficient approach for the optimization of CO 2 ‐ and field‐gas‐injection EOR in unconventional reservoirs using a fast‐marching‐method (FMM) ‐based flow simulation. The FMM‐based simulation uses the concept of diffusive time of flight (DTOF). The DTOF is a representation of the travel time of pressure‐front propagation and accounts for geological heterogeneity, well architecture, and complex fracture geometry. The DTOF can be efficiently obtained by solving the Eikonal equation using the FMM. The 3D flow equation is then transformed into an equivalent 1D equation using the DTOF as a spatial coordinate, leading to orders of magnitude faster computation for high‐resolution and compositional models as compared to full 3D simulations. The speed of computation enables using robust population‐based optimization techniques such as genetic‐ or evolutionary‐based algorithms that typically require a large number of simulation runs to optimize the operational and process parameters. We demonstrate the efficiency and robustness of our proposed approach using synthetic and field‐scale examples. We first validate the FMM‐based simulation approach using an example of CO 2 huff ‘n’ puff for a synthetic heterogeneous dual‐porosity model with a multistage hydraulically fractured well. Next, we present a field‐scale optimization of operating strategies for gas‐injection EOR in the Eagle Ford Formation. The rapid computation of the FMM‐based approach enabled a comprehensive evaluation of the EOR project, including sensitivity studies, parameter‐importance analysis, and optimal operating strategies using high‐resolution geologic models.

Summary When considering the wettability state during steam applications, we find that most issues remain unanswered. Removal of polar groups from the rock surface with increasing temperature improves water‐wettability; however, other factors, including phase change, play a reverse role. In other words, hot water or steam shows different wettability characteristics, eventually affecting the recovery. Alternatively, wettability can be altered using steam additives. The mechanism of this phenomenon is not yet clear. The objective of this work was to quantitatively evaluate the steam‐induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the phase change of water and by chemical additives. Heavy oil from a field in Alberta (27,780 cp at 25°C) was used in contact‐angle measurements conducted on quartz, mica, calcite plates, and rock pieces obtained from a bitumen‐containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature ranging up to 200°C using a high‐temperature/high‐pressure interfacial tension (IFT) device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock type, and contact sequence, were considered and studied separately. To study the effect of pressure on wettability, we started by maintaining the water in liquid phase and measuring the contact angles between the oil and water at different pressures. Next, the contact angle was measured in pure steam by keeping the pressure lower than saturation pressure. The influence of contact sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement; these measurements were repeated on different substrates. Different temperature‐resistant chemical additives (alkalis, surfactants, ionic liquid) were added to the steam during contact‐angle measurement to test the wettability alteration characteristics at different temperatures and pressure conditions (steam or hot‐water phase). In addition to these wettability‐state observations, surface‐tension experiments were conducted to evaluate the performance of additives in reducing surface tension for the oil/steam system. The results showed that the wettability of the tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil‐wet in steam than in water at the same temperature in the calcite test. The wettability state could be altered by using chemical additives in certain ranges of concentration; moreover, the optimal chemical‐additive concentration was also observed from both contact‐angle and surface‐tension measurements. Analysis of the degree of wettability alteration induced by steam (or hot water) and temperature was helpful to further understand the interfacial properties of the steam/bitumen/rock system, and proved useful in the recovery‐performance estimation of the steam‐injection process in carbonate and sand reservoirs, specifically in chemically enhanced heavy‐oil recovery.

Summary Our objective in this paper is to highlight the potential of the Eagle Ford (Cretaceous) and Pimienta (Upper Jurassic) shales in Burgos Basin (Mexico) through a comparison with the Eagle Ford Shale in Texas. The comparison is a case study focused on real data and their interpretation, north and south of the border, including geochemistry, geology, production, and reservoir–engineering data. Our overall approach includes the description of Eagle Ford data in Texas, as well as Eagle Ford and Pimienta data in the Burgos Basin. The geologic comparison is carried out using cross sections of the various formations and geophysical data. Geochemical and petrophysical data are compared using specialized crossplots. Production data are compared through rate transient analysis and by investigating the different flow periods observed in wells in both sides of the border. Reservoir–engineering aspects are compared using material–balance methods developed specifically for analyzing multipurpose shale petroleum reservoirs. Results indicate that there are many similarities but also some differences between the Eagle Ford Shale in Texas and shales in Mexico. The geologic and seismic cross sections show that there is continuity of the Eagle Ford on both sides of the border. However, structural geology in Mexico tends to be more complex than that in Texas. The geological and geochemical descriptions also show important similarities in the rock mineralogy, and the quantity, quality, and maturity of the organic matter. Well–log data show the same pattern of distribution on modified Pickett plots, developed originally for evaluation of the Eagle Ford Shale in Texas. Production data in the Burgos Basin shales are characterized by long periods (several months or even years) of transient linear flow, something that compares well with the Eagle Ford in Texas. Specialized material–balance calculations, which consider multiple porosities, have been used in the Eagle Ford Shale in Texas and are shown to have similar application in the Burgos Eagle Ford and Pimienta shales. On the basis of the Eagle Ford Shale performance in Texas, and the similarities with Burgos shales, the conclusion is reached that there is significant potential in the Mexican Eagle Ford and Pimienta shales. We present a comparison of the interpretation of real geoscience and engineering shale data collected on both sides of the border. The comparison is meaningful and suggests that the potential of shale reservoirs south of the border will be quite significant. Mexico should benefit from the lessons learned from the Texas Eagle Ford Shale.