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.

Polymer flooding with visco-elastic polymers is an EOR technique improving both macro and microscopic recovery of oil. Its efficiency can be greatly limited by mechanical and chemical degradation of polymers. When injected in the reservoir, the early few centimeters travelled through the rock are crucial for determining the degradation undergone (degradation being defined as the irreversible loss of viscosity). Our aim is is to establish predictive laws for the degradation of polymer solutions flowing through porous media and for the associated flow thickening which can mobility reduction curves of polymer solutions injected or re-injected through sintered ceramic cores of length varying between 1 and 8 mm, we develop a model for predicting mobility reduction and degradation at any length of porous medium, any flux. The model is built by considering that a single injection at flux J on a core having a length NL 0 is equivalent to N successive injections at flux J on a piece of the core of length L 0 . In linear fow, it is found that degradation increases sharply for the first few millimeters and then tends toward a quasi steady state value after a critical length L c which decreases for increasing fluxes. This model is then transposed to radial flow. Similarly, there exists a critical distance D c at which degradation reaches a steady state value. D c is an increasing function of the injection well radius R w and tends towards L c at high R w since radial flow becomes nearly linear. Results obtained with the model are then discussed for predicting precisely on which distance degradation will be experienced and for determining if degradation experiments performed in linear flow in the lab are representative of radial flow around a real polymer injector. This study is a first in injecting polymer solutions through cores as short as 1 mm and in predicting mobility reduction and degradation in both linear and radial flow profiles.

The main objective of this work is to shed light on the mechanism of modeling crossed-linked polymer (CLP) technology, by incorporating real field pilot injection and production data in the Dina Cretaceous field located in the Upper Magdalena Valley (UMV) Basin in Colombia. The paper will highlight why original simulation model predictions differ from the actual observed field data and the predictability of numerical simulation of CEOR process would be discussed and presented. Despite successful application and positive field results in the literature, the propagation of CLP system in porous media has been challenged with conflicting opinions and reports and still remains debatable and uncertain. This paper will use recent experimental laboratory data in conjunction with actual field data to properly explain the possible mechanism of CLP and offer practical modeling techniques to capture experimental and field data. Therefore a modeling methodology was developed and used to model the field data, this method is based on previous modeling mechanisms with incorporating a new grid-based residual resistance factor (RRF) and pore throat sizes. The model requires a proper understanding of rock typing and populate the permeability distribution based on pore throat sizes. The new modeling mechanism was able to reasonably predict the pilot performance in some of the offset producers. To model delayed viscosification and adsorption of the CLP process, two approaches has been evaluated and used in the original simulation model, the use of multiple regions and chemical reaction. The chemical reaction rate is tuned to calibrate laboratory data and to model the delayed viscosification and RRF. However recent laboratory experiments explained the possible mechanisms of CLP formation through intra-molecular crosslinking and intra-inter-molecular crosslinking. In conclusion, because of extensive and numerous laboratory experiments and the conduct of field pilot results, proposed numerical modeling demonstrate the complexity of modeling the CLP system and offers a practical solution to the field applications.

Matrix acidizing is a widely-used stimulation treatment performed below the fracture pressure of the formation. The purpose of acidizing is to improve or restore the formation permeability through rock dissolution. Natural fractures exist in approximately 50% of carbonate reservoirs worldwide ( Jo Garland et al. 2018 ). In this paper, a two-scale continuum model is implemented in UTCOMP (a 3D compositional reservoir simulator) with consideration of fractures using EDFM (Embedded Discrete Fracture Model). The model is also coupled with IPhreeqc (an open- source geochemical program) to calculate reactions occurring among minerals and geochemical species in the aqueous phase. In the coupled model, the two-scale continuum model describes convection and dispersion while IPhreeqc is responsible for the dissolution calculation both in the matrix and on the fracture surface. We validated the simulation model by comparing with the analytical solution. We used two methods for reaction calculation; in the first method we assumed a simple first-order reaction between acid and mineral; in the second method the UTCOMP-IPhreeqc coupled model is used to calculate complex reactions among geochemical species and different mineral compositions. Consistent results were obtained between the simple-reaction model and the UTCOMP- IPhreeqc coupled model by tuning the reaction calculation in the IPhreeqc database. On this basis, we investigated the effects of fractures on acidizing efficiency and wormhole propagation. It is found that for homogeneous matrix with existence of fractures, wormhole in the matrix is generated along the fracture. For heterogeneous matrix, the initiation of the wormhole is dependent on the permeability distribution in the matrix, but wormhole propagation after the initiation is dependent on the position of the nearest fracture tip and the fracture orientation. As a high- conductivity flow path, fracture retards wormhole propagation in the matrix by attracting most acid. As acid dissolves the minerals on the fracture surface, the fracture conductivity is increased and the fluid leak-off into the matrix is reduced. For a vertical fracture with a smaller height compared with the matrix thickness, wormhole propagation is slowed down for the entire matrix. For the first time, it is possible to simulate formations with hydraulic fractures or natural fractures during acidizing, with consideration of geochemical reactions among aqueous phase and different rock compositions. The presented model improves our understanding in acidizing optimization.

In this paper, we evaluate the idea of adding nanoparticles (NPs) in fracturing water to enhance its wetting affinity to oil-wet pores and to mobilize part of the oil during the extended shut-in periods. We analyzed the performance of two different nanoparticle additives (NP1 and NP2) on core plugs collected from the Montney Formation. Additive 1 is a colloidal dispersion with highly surface-modified NPs and additive 2 is a micellar dispersion with highly surface-modified silicon dioxide NPs, solvents and surfactants. The proposed methodology consists of the following steps: 1) Characterizing wettability of the candidate rock samples under different conditions of brine salinity and NP concentrations through dynamic contact-angle measurements, 2) Evaluating NP-assisted imbibition oil recovery during the shut-in period by conducting systematic counter-current imbibition tests, and 3) Evaluating pore accessibility by comparing the mean size of the particles formed in the NP solutions measured by dynamic light scattering (DLS) method with pore-throat size distribution of the core plugs obtained from scanning electron microscopy (SEM) and mercury injection capillary pressure (MICP) analyses. The dynamic contact-angle results show that the core plugs are oil-wet in the presence of reservoir brine and fresh water as base fluids, and water-wet in the presence of the NP solutions. Consistently, the measured oil recovery factor (RF) by the NP solutions is 5% to 10% higher than that by the base fluids, which can be explained by the wettability alteration by NPs. Comparing the mean particle size of the NP solutions with the pore-throat size distribution of the plugs evaluates pore accessibility of core plugs. From MICP and SEM analyses, most pores of the rock samples have pore-throat radius in the range of 4 to 100 nm. The mean particle size of NP1 in low-salinity water is less than 30 nm while that of NP2 in low-salinity water is around 40 nm. The NPs can pass through most of the pore throats under low-salinity conditions. This is supported by fast and spontaneous imbibition of the NP solutions into the oil-saturated core plugs, compared with the base cases without the NPs solutions. When salinity increases, the particle size for NP solutions increases to more than 200 nm. Therefore, fewer pores may be accessed by NPs under high-salinity conditions if the NP solutions are not optimized for such conditions.

Reservoir simulators often predict poor injectivity in polymer enhanced oil recovery (EOR) projects because of the high polymer viscosity, which is a deterrent for the project. However, field studies have shown much higher injectivity than predicted by the models. The objective of this work is to perform grain-scale, coupled fluid dynamics and geomechanics modeling to predict the injectivity of viscous, non-Newtonian polymers in wellbores. Fluid-rock interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Fluid flow is determined using an open-source CFD software that solves the volume-averaged Navier-Stokes equation using the finite volume method on Eulerian grids. Grain-scale geomechanics (DEM) is used to explicitly solve the particle trajectories in a Lagrangian reference system. The simulation results confirm the hypothesis of fracture initiation and sand failure near the injector. The results show that the polymer-driven fracture initiation is associated with sand shear failure, while the fracture geometry is the result of the localization of sand shear failure and fluidization of unconsolidated sand at the fracture tip. The injection of a viscous fluid can create fractures in the direction perpendicular to the applied minimum principal stress. The presence of fractures increases the injectivity. The peak injection pressure is more than 3 times greater than the applied minimum principal stress. The viscosity increase of polymers promotes the initiation of fractures and results in a greater fracture aperture. The injection of polymer can promote the initiation of fractures, and therefore, increase the polymer injectivity. This work, for the first time, uses a grain-scale model to predict polymer-driven fracture initiation and demonstrates the improved injectivity observed in the field.

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.

After long-term water flooding in dipping faulted reservoirs, attic oil is formed and located above the structurally highest wells. A novel technique that combines the Gas Oil Countercurrent (GOC) and Water Flooding Assistance (WFA) is proposed in this paper in order to recover this type of remaining oil. The basic GOC mode includes three procedures, that is, gas injection, well shut-in to form a Secondary Gas Cap (SGC), and production. For the new method GOC-WFA, the WFA is considered in the gas injection and production stage. In this paper, the basic GOC and GOC-WFA experiments are performed to elaborate the EOR mechanism and efficiency of the new method. Three experiment cycles are performed in each experiment. The experiment results illustrate that the WFA can improve the production efficiency by shortening the well shut-in time. The SGC condition is much better in GOC-WFA compared to the GOC in the same well shut-in time. The well shut-in time can be shortened by 50%. In the production stage, the SGC expansion and WFA create Double Displacement Process (DDP). The WFA can inhibit the gas channeling and lower the pressure decline rate. Besides, WFA can also displace the remaining oil located between the production and injection well that cannot be displaced by the gas cap expansion. Compared to the basic GOC, the total oil production volume is nearly doubled. Based on the production model of GOC-WFA, the sensitivity of various operational and geological parameters is analyzed by the reservoir simulation method. Then, the fault-block reservoir screening condition for GOC-WFA is established; the injection-production parameters in the gas injection and production stage are optimized. Finally, the EOR feasibility of the GOC-WFA in the fault-block reservoir is testified by the experimental and simulation results. Therefore, the GOC-WFA can effectively enhance oil recovery in the sealed mature fault-block reservoir.

Modified in situ CO 2 generation was explored as an improved tool to deliver CO 2 indirectly to the target liquid rich shale formations. Once injected, the special CO 2 - generating compound, urea, decomposes deep in fractures at the elevated temperature conditions, and releases significant amounts of CO 2 . For field implementation, the minimum surface facility is required other than simple water injection equipment. Injection of urea solution may be easier and cheaper than most gas injection approaches. In this effort, in situ CO 2 treatment and designs were carried out on a group of Woodford shale core samples. The oil saturated shale cores were soaked in different urea solutions kept in pressurized (1500 and 4000 psi) and heated extraction vessels at temperature of 250 °F. The adopted treatment step closely simulates the huff-and-puff technique. A series of experiments were run with various ingredients, including brine only, brine plus surfactant, brine plus urea and ternary mixture of brine/surfactant/urea. In addition, the extraction experiments were tested at below and above MMP conditions to decipher the principal recovery mechanism. Based on our preliminary observations, the sample cores did not lose their stability after an extended period of oil extraction with in situ CO 2 treatment. The urea only case could recover up to 24% of the OOIP compared to about 6% for the brine only case and 21% for the surfactant only case. Also adding a pre-selected surfactant to the urea slug did not have any benefit. There was no significant difference in oil recovery when the test pressure was below or above MMP. The main recovery mechanisms were oil swelling, viscosity reduction, low interfacial tension and wettability alteration in this effort. Multiple researchers reported successful lab scale CO 2 gas extraction EOR experiments for liquid rich shale like upper, middle and lower Bakken reservoir. The best scenario could recover 90% of the OOIP from the shale core samples. The evidences of this effort offer a strong proof of concept of in situ CO 2 generation potential for liquid rich shale reservoirs.

The first pilot test of surfactant-polymer (SP) flood in the world with mixtures of anionic-cationic surfactants (S a/c ) was carried out for a high temperature low permeability sandstone reservoir with high content of clay to demonstrate the potential of this novel technique to improve oil recovery. Low critical micelle concentrations (CMC) of 2.78×10 −6 mol/L, ultralow interfacial tension (IFT) of 10 −3 to 10 −4 mN/m when surfactant concentrations were above 0.025 wt%, and lower phase microemulsion with high oil solubilization of 22, as well as 55.45 % oil washing rate were obtained by using S a/c . The adsorption inhibitor (AI) was adopted to reduce the adsorption because of the high clay contained in the natural core. Dynamic adsorption was about 0.30 mg/g with addition of AI, as well as IFT kept almost unchanged before and after adsorption. In order to reduce the injection pressure and improve the mobility ratio in the low permeability reservoir, low molecular weight polyacrylamide was adopted. The viscosity of polymer and SP were 2.96 mPa·s and 4.05 mPa·s, respectively. Core flooding results showed more than 16 % original-oil-in-place (OOIP) crude oil was recovered by SP over water flood. Since August 2012, the pilot test of SP containing S a/c was carried out in a Sinopec reservoir with temperature of 83 °C, salinity of 15,000 mg/L, permeability of 41.5 mD, clay of 12 %. Totally 0.40 PV chemicals, including 0.1 PV polymer pre-slug, 0.25 PV SP main slug and 0.05 PV polymer drive, were injected from August 2012 to December 2017 with an injection rate of 0.08 PV/a. After that water drive was conducted. Maximal water cut decreased from 82.2 % to 62.1 %, and the peak daily oil production increased from 12.2 t to 32.3 t. The oil recovery was increased by 8.0 % OOIP by the end of December 2018.

This paper demonstrates the effect of pore systems and mineralogy on imbibition capillary pressure (P ci ) of carbonate rocks. A systematic workflow is developed and followed to ensure the data quality of P ci , minimize uncertainty in deriving the P ci from centrifuge tests, and analyze the data together with pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then the quality-checked data is used to produce six different P ci curves using the analytical and numerical models. The analytical and numerical solutions assess the variability in solutions for various rock types, and ultimately, lead to the selection of the most-representative P ci curve. Finally, the representative P ci curves of varying rock types are analyzed together with the MICP and QEMSCAN data to examine the change in P ci curves as a result of changes in the number and character of pore systems, dominant pore throat radii, and mineralogy. Findings from this study present insights into the impact of mineralogy and pore systems on the behavior of the P ci curves. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO 2 ) within the rock composition has a strong influence on the P ci behavior of carbonate rock. The data reveals that the contrast between the micropore and macropore systems of bi-modal carbonates has the strongest influence on P ci . We find that P ci can be clustered based on mineral content for bi-modal carbonate rocks and the degree of communication between micropore and macropore systems. The novel approach presented in this study links the MICP and QEMSCAN data to the imbibition process making the way toward a better dynamic rock typing.

Polymers are extensively used in chemical EOR processes to provide mobility control. Both synthetic polymers (e.g., HPAM) and biopolymers (e.g. Xanthan, Scleroglucan) are used. HPAM and Xanthan, do not show high temperature and high salinity (HTHS) tolerance. The purpose of this study is to evaluate temperature and salinity tolerance of an EOR grade biopolymer, Scleroglucan at HTHS conditions (100 °C and sea water salinity) and study its transport through medium permeability rocks (200-500 mD). In the absence of oxygen and glutaraldehyde, the Scleroglucan solution prepared in synthetic seawater, maintained its viscosity at 100 °C for at least two months. In the presence of a biocide, glutaraldehyde, the biopolymer degraded at 100 °C. Transport of this biopolymer was studied in both Indiana limestone (200~500 mD) and Berea sandstone (~300 mD) cores at 100 °C. The results suggest transport in porous media (~200 mD) without inducing any face plugging.

Capturing the correct reservoir heterogeneity in a geological model is critical for designing and accurately forecasting expected production benefits from improved/enhanced oil recovery (IOR/EOR) processes. In simple terms, reservoir heterogeneity is often considered as a measure of statistical variation of static properties, such as porosity and permeability. Lorenz coefficient and Dykstra-Parsons coefficient are two such measures of reservoir heterogeneity that account for these static effects. These measures are considered simplistic because the spatial distribution and arrangement of these properties is more critical for reservoir characterization than its statistical variation. Dynamic Lorenz coefficient is one such measure that accounts for the spatial distribution and arrangement of porosity and permeability. Dynamic Lorenz coefficient cannot be directly measured in the field but can be implicitly inferred from tracer data. This inferred heterogeneity will be influenced by the spatial distribution of static properties and can also be significantly influenced by multiphase flow effects, such as, viscous fingering and gravity over/under-ride which often arise from the differences in the viscosities and densities of the different phases involved. Dynamic Lorenz coefficient interpreted from a tracer test response lumps both static and multiphase (dynamic) effects into one measure of heterogeneity. During geological model construction, dynamic Lorenz coefficient is also used to rank the model in terms of heterogeneity to select the most representative model. However, the geological models are ranked using fast single-phase/streamline simulations and are devoid of complications caused by adverse mobility or density effects. This creates a disconnect between the heterogeneity measures used to characterize a geological model and those available to characterize a reservoir. Thus, calibrating a geological model to field data is a laborious task. In this paper, we present a workflow that bridges this gap by decoupling the effect of adverse mobility to obtain an approximate measure of heterogeneity that can be cross-checked against the geological realizations to select the most representative model. The workflow developed in this paper is for inverted, seven-spot patterns and is mainly focused on water-wet reservoirs.

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.

This paper presents the performance of a CO 2 foam injection pilot implemented in the East Vacuum Grayburg San Andres Unit (EVGSAU) by ConocoPhillips in cooperation with The Dow Chemical Company. The pilot project focuses on a single CO 2 injection pattern, consisting of one injector and eight producers, selected due to signs of early gas breakthrough and poor overall sweep efficiency. To solve these conformance issues and increase overall pattern production performance, a new foaming surfactant with low adsorption and high gas partitioning characteristics was developed and experimentally tested at simulated reservoir conditions. A "water alternating surfactant-in-gas" injection strategy was created utilizing a history matched reservoir simulation model and an empirical foam model. This reservoir model was also utilized to better understand the dependency of surfactant concentration on foam generation and fluid diversion. Injection profile logs (IPLs) were also run, in both water and CO 2 phases, prior to pilot implementation to establish baseline injection performance. This paper will detail several performance indicators that illustrate sustained improvement in pattern injection and production after more than 15 cycles of alternating water, CO 2 +surfactant, and CO 2 -only injection. During each cycle, gas injectivity trends were calculated and compared to the baseline to monitor foam strength and performance. Four additional IPLs were run, which indicated continuous improvement in vertical sweep efficiency and ultimately resulted in uniform injection distribution between the upper and lower sections of the producing zone. Finally, the most significant result of the trial was the uplift in pattern oil production. It has averaged ~20% above the baseline production forecast throughout the entire pilot period and peaked within the first six months at ~60% above the baseline. The success of this pilot illustrates the benefits of using a low adsorbing and CO 2 soluble foaming surfactant to address reservoir conformance issues for CO 2 floods. Further optimization of the pilot based on the simulation forecast is planned to improve long-term pilot economics.

The purpose of this paper is to (1) describe the mechanisms of gas-based enhanced oil recovery (EOR) in tight unconventionals, and (2) emphasize the need for single-porosity model tuning of the dual-porosity model when it is used to model EOR for unconventionals on well or field scale. We study two different gas-based EOR methods that inject and produce cyclically through the same well: The Huff-n-Puff (HnP) method, and a method we will refer to as the Fracture-to-Fracture (F2F) in which every other hydraulic fracture is used for injection and production in each cycle. We show that the recovery mechanisms and EOR target volume for HnP and F2F are fundamentally different. We argue that the target volume for HnP is a rubblized ("shattered") rock volume adjacent to the hydraulic fracture. To accurately predict the performance of this rubblized region, we use a compositional reservoir simulator that includes molecular diffusion to model the EOR performance of rubble-rock pieces of varying size. Gridding of numerical models is given considerable attention for both HnP and F2F to show its importance when modeling miscible EOR processes. Coarse gridding may result in significant numerical dispersion, which can falsely yield artificially optimistic recoveries for the HnP process. Results from this paper show that the primary recovery mechanism for HnP stems from a target EOR volume represented by a rubblized rock volume. The size of the rubble, and in particular its minimum dimension, will control the amount of gas that enters, mixes, and recovers oil from the rubble pore space through a process of Darcy flow, molecular diffusion, and phase behavior that involves swelling, vaporization, and first-contact miscibility conditions. The F2F method is not particularly affected by the rubblized region, but instead targets recovery from the entire rock volume between hydraulic fractures; this EOR process is akin to a conventional miscible-displacement mechanism with a much larger EOR target than HnP. The F2F method is presented in this paper as an alternative to the HnP method to show that HnP is not necessarily the best or the only EOR strategy in tight unconventionals. The EOR target volume for F2F is potentially much larger than for HnP, as everything between the fractures may be swept with a piston-like efficiency. However, the response time (i.e. the time before uplift in production is observed) can be much longer for F2F than HnP, depending mainly on the fracture spacing and matrix permeability.

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.

Most tight carbonate reservoirs have low oil recovery factors after the primary and secondary recovery stages. High-temperature carbonate reservoirs tend to be oil-wet/mixed-wet due to positively charged minerals and negatively charged oil molecules, hence reducing oil relative permeability. This study aims to enhance oil recovery from tight carbonates by virtue of wettability alteration using surfactants. Twenty different surfactants of different classes and different functional groups are systematically evaluated by first testing their aqueous stability at reservoir conditions. The aqueous stable surfactants were tested for contact angles on the mineral surface. Seven surfactant candidates were selected for spontaneous imbibition experiments, where oil recovery was monitored as a function of time. Wettability-altering surfactants increase the oil recovery by spontaneous imbibition. Up to 190% increase in oil recovery from outcrop core plugs was observed compared to the control sample with sea water.