Classical waterflooding methods which rely on water displacing oil are not plausible in unconventional shale reservoirs because of the low permeability of such reservoirs because the pressure gradients required to push the water through the reservoir matrix rock is impractical. However, when the shale reservoir is stimulated via multistage hydraulic fracturing a large number of microfractures form which provides a preferred pathway when subsequently water is injected into the reservoir. If this water has low salinity compared to the salinity of the resident brine in the matrix pores, an osmotic pressure gradient establishes between microfractures and the matrix pores that would cause water to enter the matrix pores and pushing oil out. In oil-wet shale reservoirs, this osmotic pressure allows brine imbibition into the matrix that promotes counter-current flow of oil into the fractures. In our research, this phenomenon was studied via carefully designed osmotic imbibition experiments that used low- salinity brines. Furthermore, adding a simple surfactant, or a wettability altering chemical, not only could enhance imbibition of water into the matrix, it can also create a low-IFT environment that would break the oil droplets into smaller ones to facilitate oil movement out of the micro and macro fractures to enhance oil recovery from the matrix. To scale laboratory results and observations to the field conditions, a multi-component mass transport model that includes advective and diffusive transport of water molecules was developed and used to match experimental results. We will present the core imbibition and numerical modeling results that indicate that low salinity brine plus a dilute surfactant enhances oil production. This paper pertains to a research effort conducted to assess the potential of a new EOR method, which involves the use of a mixture of low-salinity brine and low-concentrations of a surfactant or wettability altering chemical. In what follows, we will present the core flooding and numerical modeling results pertaining to the research objective. The results are intended to be used as the basis for designing economic EOR field applications in unconventional shale reservoirs.

The paper discusses the alkaline surfactant polymer (ASP) flood pilot design including formulation development, pilot area selection, well and pattern type, slug size and sequence, slug viscosity etc for the Bhagyam field. It also discusses the various lab, well and reservoir surveillance techniques planned for the baseline, ASP flood monitoring, residual oil saturation and incremental recovery estimates from the pilot. The Bhagyam is an onshore field in the Rajasthan state of western India and is part of Mangala-Bhagya m- Aishwariya (MBA) development in the Barmer basin. The main producing unit is Fatehgarh multi -storied fluvial sand stone. Reservoir quality is excellent with permeability in the range of 1 to 10 Darcy and porosity in the range of 25-30%. The crude oil is moderately viscous (15 to 500 cP) and highly active with TAN (total acid number) value of ~2 mgKOH/gm. All the reservoir and fluid properties together with low salinity (5000 ppm) and moderate temperature (54 degC) makes it an ideal candidate for polymer and ASP EOR methods. The field has been developed with downdip water injection and post successful evaluation of long term polymer injectivity test, it is currently under full-field polymer flood implementation. The details of polymer flood injectivity and full-field expansion plans are discussed by Sharma et. al. 2016 and Shankar et. al. 2018 . EOR assessment has been part of the field development planning process from start. Multiple phase behaviour studies and corefloods have been conducted to screen the surfactant and generate necessary parameters for the simulation studies. The formulation consists of combination of sulfate and sulfonate based surfactants. The focus of the pilot area selection has been to utilize the existing well s to maximum possible extent, reduce the geological uncertainty and minimize the interference from ongoing activity in the field. A normal 4 spot pilot with ~150m spacing has been selected together with two observation well for time lapse saturation monitoring and one coring well towards end of pilot for saturation determination. Dynamic models have been used to design slug size, sequence, viscosity and estimate incremental oil potential. Multiple tracer surveys together with distributed pressure measurements and interference tests are planned to establish connectivity and calibrate model. Initial estimates of pilot incremental oil recovery is in the range of 15-25% of stock tank oil intial in-place (STOIIP) over the polymer flood. Overall pilot design aims at collecting all the necessary data for reducing uncertainty for full-field expansion in a short time frame.

Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery. We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement. Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geo-mechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition counter-current flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.

The effectiveness of a low complexity chemical flooding formulation that was developed for application in offshore environments was evaluated in a single well test offshore South China Sea. The SP formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The ability to use a formulation based on only seawater avoids water treatment and reduces complexity for commercial implementation. The Single Well Test was conducted in an existing producer with its wellhead on an existing production platform offshore. The injection facilities were placed on work barge that also had accommodation to house the people that executed the injection test. The facilities on the barge consisted of seawater lift and filtering equipment, surfactant and polymer mixing capability, and high-pressure pumps to deliver the mixed fluids through a flexible high-pressure hose to the platform. A laboratory to support the QA/QC of the injected fluids was also installed on the barge. Standard Single Well Chemical Tracer test procedures were applied to determine the remaining oil saturation after waterflood and after injection of the SP formulation. The Single Well Test was completed in accordance with the objective without any recordable HSSE cases ahead of schedule. The composition of the injected SP formulation was well within the specifications resulting in good injectivity of the formulation. The single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values between 7-9% (S orc ). The main contributions described in the paper are: demonstration that a seawater-based SP formulation can be effectively mixed and injected from a barge offshore. the interpretation of the single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values similar to those observed in core floods with the SP formulation in the laboratory.

Chemical Enhanced Oil Recovery (EOR) methods have been implemented in a West Texas fractured carbonate. Due to the partially oil-wet nature of Yates field and slightly viscous oil (5-7 cP), surfactant injection was implemented to alter wettability and polymer was injected in the waterflood area to improve displacement efficiency, respectively. Single well huff-n-puff (HnP) surfactant treatments (late 1980's-today) and well-to-well pilots (1990's-2000's) have increased incremental oil production relative to base decline. Optimum surfactant chemicals were chosen based on laboratory results, reservoir performance, and economic viability. Polymer injection was carried out over a 6 year span (1983-1989) in which 55+ million pounds of polymer was injected; however the interpretation and analysis was complicated due to concurrent drilling, workover activities, and no prior waterflood development. Design parameters key to the surfactant implementation included: surfactant type and concentration, Critical Micelle Concentration (CMC), fluid saturations, oil composition, formation water salinity, fracture intensity, and treatment soak timing. Laboratory experiments included interfacial tension, contact angle, adsorption, fluid phase stability, Amott tests, and coreflooding. Numerical models were developed to help understand the sensitivity of each parameter on EOR performance and guide the design of treatments. Field implementation of surfactant included different surfactant types: anionic, non-ionic, and cationic. HnP treatments were followed by a soak period before returning the well to production and conducting flow back water analysis. Overall, HnP treatments using cationic surfactant resulted in the highest efficiency in terms of barrels of oil per kilogram of surfactant. Well-to-well tests were only conducted with non-ionic surfactants and showed mixed results. Design parameters for polymer injection such as fluid viscosity, concentration, adsorption and molecular weight were determined through coreflooding and fluid viscosity experiments. Two polymer types, high and low molecular weight, were studied and manufactured in-field and used in 200 or more injectors either continuously or alternating with produced water. Polymer injection was not effective in improving displacement efficiency in the water flood area of Yates reservoir and was suspended in 1989. The scale of field implementation and analysis of the impact of chemical injection on oil production in a massive, densely fractured carbonate field has provided valuable insight and learnings for future development and will be discussed. Other chemical EOR methods currently under investigation such as foam and other wettability altering technologies will also be discussed.

Laboratory studies of unconventional reservoirs are faced with considerably more challenges than those of conventional reservoirs. The assessment of Enhanced Oil Recovery potential in unconventional reservoirs (UCR EOR) in particular needs to address the characterization of static and dynamic properties given the tightness of the rocks, available sample size and simulation of EOR under elevated pressure and temperature conditions. This paper summarizes a laboratory study designed and performed for a potential EOR pilot utilizing cyclic gas injection (Huff-n-Puff) in the Sooner Trend Anadarko Canadian Kingfisher (STACK) shale play in Oklahoma. The lab study focuses on characterizing the rock-fluid interactions as well as upscaling key parameters for the field-scale modeling and simulation. A systematic approach was followed in the design of a laboratory program specific to the characteristics of rock/fluid interaction and the proposed injection scheme of a cyclic gas injection pilot. Digital Core Analysis (DCA) incorporating micro CT, SEM and FIB-SEM analyses were performed in order to determine basic petrophysical properties at micro scale, with capillary pressure and relative permeability curves simulated digitally. Porosity and relative permeability end points were also measured on preserved STACK core plugs. Minimum miscibility pressure (MMP) measurements of field separator gas and STACK crude oil was performed with a rising bubble apparatus (RBA). Finally, a huff-n-puff experiment was designed and performed within a custom pressure cell to study the recovery efficiency at the existing core sample scale. Digital Core Analysis (DCA) has been shown to reliably produce petrophysical properties for tight STACK cores. Laboratory miscibility pressure measurements were conducted at reservoir conditions (4,500 psi and 183 °F) using field crude samples and the associated gas composition. Seven injection/production cycles were applied to a re-saturated standard core plug with oil production observed and measured in the effluent. Cyclic injection continued until no further oil could be visually observed in the effluent. A customized 2-stage drawdown was incorporated to provide input for the recovery process. The total recovery after seven cycles reached 82 %OOIP. This work provides the first rock and fluid analysis integrating digital and traditional approaches for assessment of EOR potential in unconventional reservoirs such as those found in the STACK. This systematic approach presents properly designed and executed laboratory experiments without leaving out key formation and fluid variables. This workflow can be applied in similar UCR EOR studies to lay a solid foundation for appraising UCR EOR potential and providing reliable inputs for upscaling to the field level studies.

Reliable simulation of enhanced oil recovery processes depends on an accurate description of fluid transport in the subsurface. Current empirical transport models of rock-fluid interactions are fit to limited experimental data for specific rock types, fluids, and boundary conditions. In this paper, a general equation-of-state (EoS) approach is developed for relative permeability ( k r ) based on a set of geometric state parameters: normalized Euler characteristic (connectivity) and saturation. Literature data and pore-network modeling (PNM) simulations are used to examine the functional form of the EoS. Our results show that the new k r -EoS matches experimental data better than the conventional Corey form, especially for highly nonlinear relative permeabilities at low saturations. Using hundreds of PNM simulations, relative permeability scanning curves show a locus of residual saturation and connectivity which defines an important limit for the physical k r region. The change of this locus is also considered for two contact angles. PNM data further allows for the estimation of the relative permeability partial derivatives which are used as inputs in the EoS. Linear functions of these partials in the connectivity-saturation space renders a quadratic response of k r , which shows excellent predictions. Unlike current empirical models that are based on only one residual saturation, the state function approach allows for dynamic residual conditions critical for capturing hysteresis in relative permeability.

In this paper, we describe the design, implementation and results of a CO 2 foam pilot in a mature CO 2 flood in West Texas. The objective of the pilot was to demonstrate improved conformance/sweep efficiency of the CO 2 foam over CO 2 WAG injection. Laboratory experiments to guide design of the flood and the monitoring program to understand and model flood performance are described. Monitoring included rate and pressure tracking, injection profiles and inter-well tracer programs before and during the foam flood. While changes in injection rate and injection profile confirmed the formation of strong foam near the wellbore and redistribution of fluids in the injectors, oil response was weak, with significant oil gain observed in one of the four patterns. The gas production rate also changed very slightly from the baseline conditions. The comprehensive monitoring program in this pilot provides new insights into effectiveness of CO 2 foam in actual field applications. The results from this pilot may help to better screen and design future foam injection pilots.

For very viscous oils (>500cp), a stable polymer flood is not economical due to low processing rates. In such cases, a partially stable (mobility ratio >1) polymer flood must be designed. Depending on the magnitude of viscosity ratio, these displacements will be influenced by viscous fingering. Typically, viscous fingers cannot be accurately captured with the grid sizes used in full-field simulations. To optimize and design a partially-stable polymer or water flood, it is critical to correctly upscale the laboratory-generated relative permeability curves for reservoir simulation. In recent years, such models have been published in SPE literature. Unfortunately, most of these models require multiple fitting parameters (3+). In this work, we present a simplified technique that requires systematic change in only one parameter to generate upscaled relative permeability curve for a given viscosity ratio. Using fine-grid simulations, we show that due to small-scale random heterogeneities, the flow at high viscosity ratio is channelized even in a core perceived to be homogeneous at laboratory scale. Upscaling averages these fine variations in heterogeneities, causing the grids to be over-swept, and thus the recovery is over-predicted. To compensate for this over-prediction, relative permeability curves need to be upscaled.

After the successful pilot (18%STOOIP incremental oil, Juri et al. 2017 and utility factor of 1,76 kg polymer/bbl) of two technologies, 0.3 pore volume (PV) continuous polymer injection followed by 0.3PV high-frequency water-alternate-polymer, a series of multiple simulations cases indicated an optimal extension of 3-year cycle −0.4 to 0.6PV of polymer injection- in a cyclic modular development. Despite all the advantages of polymer injection, few full-field expansions emerge because there are many challenges in integrating multiple disciplines -lab studies, subsurface reservoir modeling, engineering, energy, procurement, logistics, storage, project management-. All parties find it difficult focusing on a common goal and streamline the decision process. It has long been thought that the EOR road map means planning for large scale EOR. However, that is false in the sense that there are very few full-field injections. The past strategy in EOR has led to a few pilot extensions implemented. Planning for large-scale EOR suffers from having incremental oil, uncertainty in oil price, uncertainty in economic drivers, uncertainty in technical solutions for the expansion and management uncertainty in the same time frame, which undermines economics. What it seems to be the only way to make progress with EOR is that EOR should align with planning for quick oil response in a time frame of three to five years. We present here the steps to accelerate EOR in the Grimbeek field from a 4-injectors pilot to 80 new injectors in a fast, less than 18 months deployment. We compare the capital and operating cost of multiple expansion scenarios. The scope is to accelerate EOR deployment opposite to the slow typical EOR workflow. We have seen the opportunity in accelerating the oil focusing on a simple modular strategy rather than iterating multiple possible engineering solutions to distribute the polymer across the field. NPV of the overall project is higher than the costs of delaying the injection or having to redo parts of the implementation along with the deployment. Future optimization is necessary for options of logistics, storage, in-situ skid connection and mounting along with by-pass remote control valves and remote control of injection skids. The building blocks of the strategy are containerized mobile skids containing ten pumps, polymer dispersion unit, and 30-metric ton silos that target the by-passed oil zones, so-called sweet-spots. These sweet-spots emerge from detailed 3D subsurface simulations. The mobile skids plug-in the waterflooding manifolds in an easy and fast connection. We risk saying that standard modeling lacks showing a complete mapping of the remaining oil in the subsurface and therefore we could under-predict polymer flooding potential. This injection scheme distributes polymer using the already implemented waterflooding in-situ installation. We focus on having a simple, standard and mobile system targeting fast implementation and fast oil response that can move to the next sweet-spot to increase rapidly the production rather than large facilities that take longer to design and construct and have limited flexibility. The oil response shows a faster response than expected in the range of three to four months despite a reduction in the target polymer injection rate because of issues in the water availability. The oil rate displayed good recovery values, thus, demonstrated the efficiency of the proposed higher concentration dosage mechanism for inducing additional crossflow.

Low recovery of fracturing water is partly due to fracturing fluid leak-off into formation and water trapping in matrix. In our previous studies ( Soleiman Asl et al. 2019 and Yuan et al. 2019 ), we showed that using surfactant solutions in fracturing fluid can significantly enhance imbibition oil recovery. However, there is one critical question remained unanswered: What are the consequences of these additives on well performance during flowback and post-flowback processes? Can they block the pore-throats of rock matrix and induce formation damage? To answer this question, we develop and apply a comprehensive laboratory protocol on a tight core plug to simulate leak-off and flowback processes under reservoir pressure, with and without initial water saturation (S wi ). We evaluate the possibility of pore-throat blockage by comparing pore-throat size distribution of the core plug and size distribution of the particles formed in a microemulsion (ME) solution. We also investigate the effects of S wi on effective oil permeability (k o eff ) after the flowback process. The results of leak-off and flowback tests using tap water as the base case shows that k o eff after flowback is lower than that before the leak-off, mainly due to phase trapping. However, results of the tests using the ME solution show that k o eff after flowback is greater than k o eff before leak-off. This observation suggests that the leak-off of ME solution enhances regained oil relative permeability during flowback by reducing phase trapping and water blockage. When S wi = 0, the blockage of leaked-off fluid reduces k o eff during the flowback process. The mean size of self-assembled structures (referred to as "particles" here) formed by mixing the ME solution with water is around 10-20 nm. The MICP profile of the core sample shows that around 95% of pore throats are bigger than the size of formed particles, suggesting low chance of pore-throat blockage by the suspended particles.

Accurately modeling three-phase relative permeability remains a great challenge to reservoir engineers, in part because of a lack of experimental data to use when verifying model results. This is especially true when the fluids are changing composition, such as for miscible gas injection, when many simulator models have difficulty identifying the phases and sometimes do so incorrectly, causing inaccurate results or even crashing the simulator. Recently, there has been a shift away from labeling phases as simply "oil" and "gas", and instead labeling them according to a physical property that is continuous and tied to composition, such as density or the Gibbs free energy (GFE) of the fluid. In this research, we measure three-phase oil and gas relative permeability as a function of the fluid's GFE. We see from our results that composition changes can cause big shifts in the relative permeability curves, however, the relative permeability parameters are non-monotonic with respect to the Gibbs free energy. More experimental data will be needed to further study the GFE model and the nature of the composition effects.

To speed up coreflood experiments, we have developed a state of the art experimental setup (CAL-X) designed for high throughput coreflood experimentation. The setup is composed of an X-ray radiography facility, a fully instrumented multi-fluid injection platform and a dedicated X-ray transparent core holder. The equipment was designed to handle small samples of 10 mm in diameter and 20 mm in length, and can be operated at up to 150 bar and 150 °C. The X-ray facility consists of a high power X-ray tube and a high speed-low noise detector allowing real-time radiography acquisition and offering sufficient density resolution to use dopant-free fluids. The injection platform is fully automated and allows the control and monitoring of different parameters (pressure, temperature, flow rate…). 1-D and 2-D saturation profiles are followed in real-time, allowing a precise determination of the recovery curve, reducing thus drastically time-consuming effluent measurements. Using this setup, a typical coreflood experiment can be run in less than a day. To validate the setup we have run a series of experiments on water-wet sandstone samples to determine capillary desaturation curve, steady-state relative permeabilities and recovery factor for a formulation designed for high temperature conditions (110°C). The results show good repeatability as well as good agreement when compared to standard coreflood experiments. In the recovery factor experiment, during surfactant injection, the formation and displacement of an oil bank was observed, yielding a recovery factor of 92% OOIP.

An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO 2 foam injections. Surfactant pre-floods, prior to CO 2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO 2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO 2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO 2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO 2 foam injection.

CO 2 capture and sequestration in subsurface reserves are expensive processes. Therefore flue gas can be directly injected into the oil and gas reservoirs to eliminate the cost of CO 2 separation from power plant emissions and simultaneously enhance hydrocarbon production that may offset the cost of gas compression. However, gas injection in subsurface resources is often subject to poor volumetric sweep efficiency caused by low viscosity and low density of the injection fluid and formation heterogeneity. This paper aims to study gas mobility control techniques of water alternating gas (WAG) and foam in Cranfield via field-scale simulations. A coupled compositional flow and geomechanics simulator, IPARS, is used to accurately simulate the underlying physical processes. A hysteretic relative permeability model enables modeling local capillary trapping. Foam mobility control technique is examined to investigate the eminent level of CO 2 capillary trapping by an implicit texture foam model. The coupled flow-geomechanics model can detect the effect of the plausible interaction of geomechanics and fluid flow on CO 2 plume extension by analyzing the critical pressure that could induce hydraulic fracturing. Field-scale simulations indicate that during WAG and foam processes, the oil recovery increased 1.35 times and 1.6 times; and CO 2 storage increased by 13.6% and 38.7% of total gas injection during the injection period compared to continuous gas flooding, respectively. During SAG process, coupling geomechanics will significantly increase the predicted gas storage volume, as a result of reservoir pore volume increase. Furthermore, analysis of the pressure margin for inducing hydraulic fracturing ensured the safety of SAG operation.

Gas injection is a widely applied enhanced oil recovery method. However, poor vertical and areal sweep efficiency result in inefficient oil displacement. For improving gas mobility control, Water-Alternating- Gas injection has often been applied. The goal of this study was to compare several immiscible nitrogen injection schemes and to investigate how rock-fluid and fluid-fluid interactions control the immiscible flooding process. Well-controlled core-flood experiments were performed in Bentheimer sandstone cores. Nitrogen was injected into cores saturated with n-hexadecane at connate water saturation at constant pressures (5 and 10 bar) and while varying backpressure (5 to 60 bar). Nitrogen was also injected at residual oil to waterflood and a Water-Alternating-Gas injection scheme was assessed. Coreflood results clearly demonstrated the beneficial effects of Water-Alternating-Gas injection over continuous gas injection. The findings in this study suggest that a) an increase in pressure favours oil recovery slightly during continuous nitrogen injection at connate water saturation, b) residual oil saturation for immiscible nitrogen flooding is lower under three-phase flow compared to two-phase flow and c) the relatively high oil recovery, i.e. lower ultimate residual oil saturation, by Water-Alternating- Gas injection is most likely related to an increase in trapped gas saturation.

Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations. The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.

This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode. Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model. The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.

Mixing of an asphaltenic oil with light gases (e.g., CO 2 ) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.

This study investigates how compositional effects interact with the flow behavior during near miscible (and immiscible) CO 2 -oil displacements in heterogeneous systems. A series of numerical simulations modeling 1D slim-tube and 2D areal systems were performed using a fully compositional simulator. With negligible numerical dispersion, the fine-scale (Δx=0.005m) slim-tube simulations were performed to provide the "truth case" in terms of the compositional effects and oil/component recovery. A number of grid resolutions were tested to examine cell-size effects on the simulation accuracy. It was found that coarse cell size not only leads to spreading of the displacing front, but also lowers the displacement efficiency by reducing the component stripping effects, as noted by Orr (2007 ). The corresponding 2D cases are based on a small heterogeneous sector model of dimensions 50m × 10m, in order that the finest scale displacement physics can be modelled accurately. We investigated various flow regimes ranging from viscous fingering to channeling displacements within heterogeneous random correlated fields. CO 2 dissolves in oil at near-miscible conditions and improves the mobility of the oil, but leads to earlier breakthrough of CO 2 in both fingering and channeling flow. It was also found that the instability of fingering flow could introduce considerable variation in the composition paths during oil displacement by CO 2 , compared with the slim-tube simulations, particularly in the later stages of the flood. For this reason, heavier component recovery is more likely to be affected and reduced by viscous instability. In the case of channeling flow, compositional effects were less important since the permeability channel dominated the displacement. Both the ultimate oil recovery and component recovery are significantly and about equally reduced, when the underlying heterogeneity is of dominant influence. To summarize, compositional effects can have a very significant impact on the prediction of near-miscible CO 2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channeling during CO 2 near-miscible displacement can lead to behavior that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO 2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. Lastly, the appropriate upscaling methods considering mass transfer still require further investigation for CO 2 near-miscible displacement in field-scale applications. The complete dataset and results of this study are available online as a model case example for testing out potential upscaling techniques for compositional flows in heterogeneous systems ( Wang et al. 2019 ).