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This paper focuses on combining resistivity and pressure measurements to determine the effectiveness of foam as a mobility control method. It presents a theoretical framework to describe the expected resistivity changes during CO2-foam displacements. With this objective, we first provide equations to estimate the resistivity for CO2-foam systems and then utilize two distinct foam models to quantify these effects. Using analytical solutions based on the fractional flow theory, we present resistivity and mobility distributions for ideal and non-ideal reservoir displacement scenarios. Additionally, assuming pressure measurements only, we examine the inter-dependency between various foam parameters. Our results suggest that the combination of pressure and resistivity measurements in time-lapse mode could be deployed as an effective monitoring tool in field applications of the (CO2) foam processes. The proposed method is novel as it could be employed to predict under-performing CO2-foam floods and improve oil recovery and CO2 storage.

CO2 foam is an effective method to reduce CO2 mobility and improve displacement efficiency in CO2 enhanced oil recovery (EOR) and CO2 storage applications. Foam strength and stability are key parameters that influence the efficiency of the foam which depend on several factors including the presence of oil, injection velocity and rock type. The aim of this work was to evaluate the effect of rock type on CO2 foam strength and stability by conducting corefloods with sandstone and carbonate rocks at reservoir conditions. The effect of injection velocity and the presence of residual oil on the foam generation and displacement efficiency was also investigated.Steady-state CO2 injections revealed differences in foam generation, strength and stability in sandstone compared to carbonate based on the calculated apparent viscosities. Results showed that the strongest foam was generated in sandstone compared to carbonates because of higher absolute permeability. Drainage-like co-injections with increasing gas fraction showed the relation between rock permeability and the limiting capillary pressure and co-injection at different injection velocities revealed shear-thinning foam rheology in both rock types. Despite stronger foam generation in sandstone, unsteady-state CO2 injections showed similar oil displacement efficiency in both rock types. CO2 foam increased oil recovery by 200% in both rocks compared to CO2 injection without foam. In addition, foam showed a significant impact on water displacement compared to pure CO2 injection which is advantageous for CO2 storage applications. Water recovery during CO2 EOR was 60% in sandstone and 88% in limestone. Dissolution of calcite was observed in limestone, which increased pore space and the CO2 storage capacity. Overall, the results indicate that CO2 foam generation, stability and coalescence are sensitive to rock permeability and pore geometry in the conducted experiments.

A CO2 foam pilot was conducted in a heterogeneous carbonate reservoir in East Seminole Field, Permian Basin USA. The primary objective was to achieve in-depth CO2 mobility control to increase CO2 sweep efficiency and improve oil recovery in an inverted 40 acre 5-spot pattern. Foam was injected in a rapid surfactant-alternating-gas (SAG) strategy with 10 days of surfactant solution injection followed by 20 days of CO2 injection. We implemented a laboratory to field upscaling approach which included foam formulation screening, numerical modeling, and field monitoring to verify foam generation and CO2 mobility reduction. The monitoring campaign obtained baseline before the pilot and monitored reservoir response to foam injection. This included conducting baseline and pilot phase CO2 and water injection profile logs, interwell CO2 tracer tests and collecting injection bottom hole pressure data and flow rates. Transient analysis was also conducted to assess foam development at reservoir conditions. The effectiveness of foam in improving overall recovery was also evaluated. Results indicate that foam was generated and CO2 mobility was reduced during the pilot based upon higher differential pressures during the SAG cycles compared to an identical water-alternating-gas (WAG) cycle. CO2 breakthrough was also delayed with foam compared to the baseline test without foam. Injection profile logs from the foam injector showed that flow increased into unswept reservoir intervals and was diverted from a high permeability streak. The effectiveness of foam in improving the overall oil recovery revealed that the foam pilot produced 30% more oil than the pattern's projected performance without foam, despite injecting at half of the historical rate during the pilot. This work presents the complete field results and analysis from the successful implementation of CO2 foam mobility control.

Summary In this paper, we describe a laboratory investigation of a nonionic surfactant for carbon dioxide-(CO2-) foam mobility control in the East Seminole field, a heterogeneous carbonate reservoir in the Permian Basin of west Texas. A method of high-performance liquid chromatography-evaporativelight-scattering detector (HPLC-ELSD) was followed for characterizing the surfactant stability. The foam transport process was studied in the absence and the presence of East Seminole crude oil, with test results showing that strong CO2-foam forms in either a bulk-foam test or foam-flow test. An oxygen scavenger, carbohydrazide, was found effective for controlling the stability of the surfactant up to 80°C and total dissolved solid of ∼34,000 ppm. Moreover, a phosphonate scale inhibitor was investigated and found to be compatible with the oxygen scavenger to accommodate a surfactant solution in a gypsum-oversaturated reservoir brine. During the oil-fractional flow test, an emulsion appears to form, causing a noticeable pressure increase; however, emulsion generation failed to cause a significant phase plugging in the test. Also, a STARS™ (Computer Modelling Group Ltd., Calgary, Alberta, Canada) foam model was applied to obtain the foam parameters from the foam-flow experiments at steady-state conditions. The insights from laboratory experiments better enable translation of the foam technology to the field.

The efficiency of CO2 injection for enhanced oil recovery (EOR) and carbon storage is limited by severe viscosity and density differences between CO2 and reservoir fluids and reservoir heterogeneity. In-situ generation of CO2 foam can improve the mobility ratio to increase oil displacement and CO2 storage capacity in geological formations. The aim of this work was to investigate the ability of CO2 foam to increase oil production and associated CO2 storage potential, compared to other CO2 injection methods, in experiments that deploy field-scale injection strategies. Additionally, the effect of oil on CO2 foam generation and stability was investigated. Three different injection strategies were implemented in the CO2 EOR and associated CO2 storage experiments: pure CO2 injection, water-alternating-gas (WAG) and surfactant-alternating-gas (SAG). Foam generation during SAG experiments showed reduced CO2 mobility compared to WAG and pure CO2 injections indicated by the increase in apparent viscosity. CO2 foam increased oil recovery by 50% compared to pure CO2 injection and 25% compared to WAG. In addition, CO2 storage capacity increased from 12% during pure CO2 injection up to 70% during SAG injections. Experiments performed at high oil saturations revealed a delay in foam generation until a critical oil saturation of 30% was reached. Oil/water emulsions in addition to CO2 foam generation contributed to CO2 mobility reduction resulting in increased CO2 storage capacity with foam. publishedVersion

Positron emission tomography (PET) is routinely used for medical imaging; a current surge in published geoscientific research utilizing this modality also infer increasing interest for in-situ PET imaging in core analysis. Excellent signal to noise ratio coupled with high temporal and spatial resolution suggest that PET might become the new method-of-choice for core analysis. Obstacles related to production, transfer and handling of radioactive fluids and gases must, however, be dealt with for PET to become a widely used core scale imaging technique. This paper describes an ongoing, true multidisciplinary collaboration, where pre-clinical PET imaging facilities are routinely used in core analysis to investigate dynamic fluid flow at high pressure conditions. We detail challenges and opportunities related to porous media research in established pre-clinical laboratory facilities designed for small-animal imaging, and demonstrate the significant potential of PET imaging in core scale analysis in a context related to long-term porous media carbon storage. Explicit imaging of several fluid phases is possible by PET imaging using a range of readily available radiotracers. Relevant radiotracers to carbon storage in porous media are e.g. the carbon radioisotope 11C and water-soluble tracer 18F. These are both short-lived tracers (20 - 110 min) and must be used in high doses of radiation, which present challenges related to safe transfer and handling. Although there are several obstacles to conduct advanced core analysis in hospital imaging facilities (some of which are detailed in this paper), significant advantages include trained personnel on-site to operate a local cyclotron, procedures in place to ensure safe and efficient transfer of short-lived radiopharmaceuticals from the cyclotron, and advanced image analysis capabilities available. Cyclotrons are widely available worldwide (currently more than 1200 operating cyclotrons), often located in close proximity to medical and pre-clinical imaging facilities and academic institutions. Similar collaborations may therefore also be possible elsewhere, reducing the need for allocated geophysical PET-scanners and lowering the threshold for routinely using PET imaging in core analysis.

Wettability controls the location, distribution, and flow of fluids in a pore network. Obtaining a uniform core scale wettability distribution is therefore a necessary condition for reliable special core analysis (SCAL). In the present work, dynamic and static aging procedures were used to alter the wettability of outcrop Edwards limestone, and Amott-Harvey cycles were performed on whole and split core samples to evaluate wetting distribution and stability. Dynamic aging was observed to be more efficient and produced a more uniform and reproducible wettability distribution compared to static aging. Rock-fluid and fluid-fluid interactions, evaluated by Isothermal Titration Calorimetry (ITC) experiments, confirm that supplying fresh crude oil during the aging procedure to a core plug causes the greatest wettability change. Synergy between ITC and simple core scale experiments provide an improved understanding of the wettability alteration at microscopic and macroscopic levels in heterogeneous Edwards limestone.

Application of foam has been found to mitigate challenges associated with field-scale CO2 floods for enhanced oil recovery (EOR) by providing in-depth mobility control. The field pilots that have been run so far have shown varying results, inferred mainly from inter-well tracer studies and production data analysis. A research collaboration has been set up to advance the technology of using foam as a mobility control agent for CO2 EOR, with focus on integrated reservoir modelling to assist technology transfer to a high-cost environment. A heterogeneous carbonate reservoir onshore in west Texas, USA has been selected for the field trial. The reservoir has been waterflooded for more than 50 years, and a significant part of it has been on continuous CO2 injection for the last 5 years. An inverted five-spot pattern, which had rapid CO2 breakthrough in adjacent producers and is currently recycling significant amounts of CO2, has been selected for the study. The pilot is planned for 2 years with surfactant alternating gas (SAG) injection in the first year, followed by CO2 injection in the next year. A reservoir model was created by integrating available static and dynamic information. Since the measurement of static information and production performance is usually imprecise, even the most carefully constructed models do not exactly represent reality. In this paper, we present a workflow that was used to calibrate the reservoir model to historical data for practical forecasting, which takes into account a wide range of uncertainties caused by the inaccessibility of information. Laboratory studies were performed with reservoir cores, fluids and selected surfactant to obtain the base values of foam model parameters. As an output, distributions for key performance indicators such as cumulative oil production and CO2 retention were generated for the proposed pilot to guide further decision-making. Supplementary material: The details of simulation set-up and results for history matching and prediction are available at https://doi.org/10.6084/m9.figshare.c.4704374 This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

Summary The use of nanoparticles for CO2-foam mobility is an upcoming technology for carbon capture, utilization, and storage (CCUS) in mature fields. Silane-modified hydrophilic silica nanoparticles enhance the thermodynamic stability of CO2 foam at elevated temperatures and salinities and in the presence of oil. The aqueous nanofluid mixes with CO2 in the porous media to generate CO2 foam for enhanced oil recovery (EOR) by improving sweep efficiency, resulting in reduced carbon footprint from oil production by the geological storage of anthropogenic CO2. Our objective was to investigate the stability of commercially available silica nanoparticles for a range of temperatures and brine salinities to determine if nanoparticles can be used in CO2-foam injections for EOR and underground CO2 storage in high-temperature reservoirs with high brine salinities. The experimental results demonstrated that surface-modified nanoparticles are stable and able to generate CO2 foam at elevated temperatures (60 to 120°C) and extreme brine salinities (20 wt% NaCl). We find that (1) nanofluids remain stable at extreme salinities (up to 25 wt% total dissolved solids) with the presence of both monovalent (NaCl) and divalent (CaCl2) ions; (2) both pressure gradient and incremental oil recovery during tertiary CO2-foam injections were 2 to 4 times higher with nanoparticles compared with no-foaming agent; and (3) CO2 stored during CCUS with nanoparticle-stabilized CO2 foam increased by more than 300% compared with coinjections without nanoparticles.

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

SummaryA carbon–dioxide (CO2) –foam enhanced–oil–recovery (EOR) field pilot research program has been started to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic–CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory– and field–scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2–foam field trial, including pilot–well–selection criteria and laboratory corefloods combined with reservoir–scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant–alternating–gas (SAG) injection, while assessing CO2–storage potential.Laboratory investigations include dynamic aging, foam–stability scans, CO2–foam EOR corefloods with associated CO2 storage, and unsteady–state CO2/water endpoint relative permeability measurements. Tertiary CO2–foam EOR corefloods at oil–wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility–reduction factors (MRFs) up to 340 compared with pure–CO2 injection at reservoir conditions. Oil recovery, gas–mobility reduction, producing–gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.

Sequestration of CO2 in natural gas hydrate reservoirs may offer stable long-term deposition of a greenhouse gas while benefiting from CH4 gas production. In this paper, we review old and present new experimental studies of CH4–CO2 exchange in CH4 hydrate-bearing sandstone core plugs. CH4 hydrate was formed in Bentheim sandstone core plugs to prepare for subsequent lab-scale CH4 gas production by CO2 replacement. The effect of temperature, diffusion length, salinity, water saturation, CH4 hydrate saturation, and co-injection of chemicals (N2 and monoethanolamine) with the injected CO2 were measured. The measurements prove the critical role of water saturation in these processes: formation of CO2 hydrate severely reduced the injectivity for water saturations above 0.1 fractions. The results presented in this paper are important when assessing natural gas hydrate reservoirs as candidates for CO2 injection with concurrent CH4 gas production. publishedVersion

This paper presents the analysis of transient pressure measurements from a recent CO2 foam pilot in East Seminole Field, Permian Basin, USA. A surfactant-stabilized foam was selected to mitigate CO2 EOR challenges in this field by reducing CO2 mobility in an effort toimprove sweep efficiency, oil recovery, and CO2 storage potential. The surfactant system was designed in the laboratory by measuring surfactant adsorption and verifying foam stability. A surfactant-alternating-gas (SAG) injection strategy, with 10 days of surfactant solution followed by 20 days of CO2, began in May 2019. The pilot monitoring program aimed to evaluate reservoir response to foam injection. Surveys included CO2 injection profiles, CO2 tracer tests, collection of injection bottom hole pressure/temperature data, and three-phase flow rates.Injection BHP and temperature data from the downhole pressure gauge (DHPG) was used to evaluate the pilot response during surfactant and CO2 injection. The analysis was conducted by examining the differential pressure (dP) and differential temperature (dT) through time for the first nine SAG cycles. A high-resolution two-dimensional radial flow model was developed to history match the measured transient pressure data. The simulation model included the porosity and permeability distribution from a validated sector-scale model of the pilot pattern and surrounding producers. The radial flow model was used to examine the impact of foam and/or relative permeability on injectivity and mobility reduction when switching between surfactant solution and CO2 in a SAG process.Transient analysis showed that the temperature responses were quite similar during most SAG cycles. On the other hand, differential pressures consistently increased during periods of surfactant injection and decreased during the subsequent CO2 injection periods. The pressure increase (buildup) during surfactant injection was due to a decrease in mobility, showing development of a mobility bank in the reservoir. There are also questions regarding the impact of foam and/or relative permeability on injectivity and mobility reduction when switching between surfactant solution and CO2 in a SAG process.

Two major challenges in CO2 enhanced oil recovery (EOR) are the high mobility of CO2 and reservoir heterogeneity. High CO2 mobility, related to the low density and viscosity of CO2, compared to in-situ fluids can cause viscous fingering, gravity override, and flow in thief zones resulting in poor reservoir sweep efficiency and low oil recoveries. Mobility control foam can improve CO2 EOR and CO2 storage potential by mitigating unfavorable CO2 properties and reducing the impact of reservoir heterogeneity. CO2 foam injection involves injecting a foaming agent (surfactant) with CO2 to generate stable foams in porous media. This work presents an incremental physical upscaling approach that moves from the pore- to core- to field-scale for characterizing and optimizing foam systems for CO2 mobility control, EOR, and CO2 storage. An additional focus was to visualize and describe in-situ fluid saturation dynamics during CO2 storage processes. We address the challenges associated with transferring CO2 foam EOR technology offshore, using lessons learned from an ongoing onshore pilot in the Permian Basin of west Texas. The aim is to encourage co-optimized CO2 EOR and long-term CO2 storage foam technology as part of carbon capture, utilization, and storage (CCUS) for offshore applications.

Carbon dioxide has been used for more than five decades in fields for tertiary oil recovery; and because of commercial and environmental reasons, it has received lot of attention in the last few years. Based on the experience with large-scale CO2 flooding, it is well understood that even with a high local displacement efficiency, the process suffers from poor volumetric sweep due to reservoir heterogeneity, viscous instability and gravity override. Based on laboratory studies, foam has been found to address these limitations at small-scale, however understanding of CO2-Foam flow at field-scale is limited within industry. Field pilots performed so far have shown technical success especially near well, but there exist a gap to establish a methodology to scale-up the CO2-Foam technology to large-scale. A research program was established to run CO2-Foam field trial in a field with heterogeneous carbonate reservoir onshore in west Texas, USA to guide technology scale-up. The research aims at implementing a modelling and monitoring approach as part of the roadmap. The static model created by integrating geologic framework, well logs and core data, and dynamic model created based on analysis of reservoir engineering data, including relative permeability, fluid phase behaviour and EOR coreflood studies forms the basis for reservoir simulation study for the pilot area. In this paper, we provide an overview of various elements of the three-dimensional numerical model. We demonstrate the application of a systematic approach to incorporate the uncertainties associated with model inputs, which is used to guide decision making for the baseline survey. The success will be validated via an appropriate monitoring plan in the ongoing pilot program.

Presently, the only offshore project for enhanced oil recovery using carbon dioxide, known as CO2-EOR, is in Brazil. Several desk studies have been undertaken, without any projects being implemented. The objective of this review is to investigate barriers to the implementation of large-scale offshore CO2-EOR projects, to identify recent technology developments, and to suggest non-technological incentives that may enable implementation. We examine differences between onshore and offshore CO2-EOR, emerging technologies that could enable projects, as well as approaches and regulatory requirements that may help overcome barriers. Our review shows that there are few, if any, technical barriers to offshore CO2-EOR. However, there are many other barriers to the implementation of offshore CO2-EOR, including: High investment and operation costs, uncertainties about reservoir performance, limited access of CO2 supply, lack of business models, and uncertainties about regulations. This review describes recent technology developments that may remove such barriers and concludes with recommendations for overcoming non-technical barriers. The review is based on a report by the Carbon Sequestration Leadership Forum (CSLF).

SummaryPolymer gel is frequently used for conformance control in fractured reservoirs, where it is injected to reside in fractures or high-permeability streaks to reduce conductivity. With successful polymer-gel conformance control in place, increased pressure gradients across matrix blocks may be achieved during chase floods, diverting water, gas, or enhanced oil recovery (EOR) chemicals into the matrix to displace oil. Knowledge of gel behavior during placement and chase floods is important because it largely controls the success of subsequent injections. Polymer-gel behavior is often studied in corefloods, where differential pressure and effluents from fracture and matrix outlets give information about gel deposition during placement and flow paths during chase floods. The work presented in this paper uses complementary positron emission tomography (PET) chromatographic tomography (CT) imaging to quantify the behavior and blocking capacity of Cr(III)-acetate hydrolyzed polyacrylamide (HPAM) gel during chase waterflooding. In-situ imaging provides information about changes that may not be extracted from pressure measurements and material balance only, such as changes in local fluid saturations and dynamic spatial flow within the fracture and within the structure of the gel network.Polymer gel was placed in core plugs with longitudinal fractures that connected the inlet and outlet, and chase water was subsequently injected to measure the gel blocking capacity. The water phase was labeled with a positron emitting radiopharmaceutical (F-18) to visualize and quantify local flows with PET during gel rupture and subsequent flooding. By use of PET, we study gel rupture and the development of wormholes during gel erosion after rupture as a function of flow rate. A particular strength with access to dynamic, local flow patterns is the direct comparison to global measurements, such as differential pressure and production rate, to verify existing gel-behavior models.

Summary This work demonstrates that diffusion may be a viable oil-recovery mechanism in fractured reservoirs during injection of carbon dioxide (CO2) for enhanced oil recovery, depending on the CO2 distribution within the fracture network and distance between fractures. High oil recovery was observed during miscible, supercritical CO2 injection (RF = 86% original oil in place) in the laboratory with a fractured chalk core plug with a large permeability contrast. Dynamic 3D fluid saturations from computed-tomography (CT) imaging made it possible to study the local oil displacement in the vicinity of the fracture, and to calculate an effective diffusion coefficient with analytical methods. The obtained diffusion coefficient varies between 0.83 and 1.2 ×10−9m2/s, depending on the method used for calculation. A numerical sensitivity analysis, with a validated numerical model that reproduced the experiments, showed that the rate of oil production during CO2 injection declined exponentially with increasing diffusion lengths from the CO2-filled fracture and oil-filled matrix. In a numerical upscaling effort, with the experimentally achieved diffusion coefficient, oil-recovery rates and local flow were studied in an inverted five-spot pattern in a heavily fractured carbonate reservoir.

Summary Polymer gels are frequently applied for conformance improvement in fractured reservoirs, where fluid channeling through fractures limits the success of waterflooding. Placement of polymer gel in fractures reduces fracture conductivity, thus increasing pressure gradients across matrix blocks during chase floods. A gel-filled fracture is reopened to fluid flow if the injection pressure during chase floods exceeds the gel-rupture pressure; thus, channeling through the fractures resumes. The success of a polymer-gel treatment, therefore, depends on the rupture pressure. Salinity differences between the gel network and surrounding water phase are known causes of gel swelling (e.g., observed in recent work on preformed particle gels). Gel swelling and its effect on fluid flow have, however, been less studied in conjunction with conventional polymer gels. By use of corefloods, this work demonstrates that low-salinity water can swell conventional Cr(III)-acetate hydrolyzed polyacrylamide (HPAM) gels, thereby significantly improving gel-blocking performance after gel rupture. Formed polymer gel was placed in fractured core plugs, and chase waterfloods were performed using four different brine compositions, of which three were low-salinity brines. The fluid flow rates through the matrix and differential pressures across the matrix and fracture were measured and shown to increase with decreasing salinity in the injected water phase. In some cores, the fractures were reblocked during low-salinity waterfloods, and gel-blocking capacity was increased above the initial level. Low-salinity water subsequently flooded the matrix during chase floods, which provided additional benefits to the waterflood. The improved blocking capacity of the gel was caused by a difference in salinity between the gel and injected water phase, which induced gel swelling. The results were reproducible through several experiments, and stable for long periods of time in both sandstone and carbonate outcrop core materials. Combining polymer gel placement in fractures with low-salinity chase floods is a promising approach in integrated enhanced oil recovery (IEOR).

This paper presents experimental and numerical sensitivity studies to assist injection strategy design for an ongoing CO2 foam field pilot. The aim is to increase the success of in-situ CO2 foam generation and propagation into the reservoir for CO2 mobility control, enhanced oil recovery (EOR) and CO2 storage. Un-steady state in-situ CO2 foam behavior, representative of the near wellbore region, and steady-state foam behavior was evaluated. Multi-cycle surfactant-alternating gas (SAG) provided the highest apparent viscosity foam of 120.2 cP, compared to co-injection (56.0 cP) and single-cycle SAG (18.2 cP) in 100% brine saturated porous media. CO2 foam EOR corefloods at first-contact miscible (FCM) conditions showed that multi-cycle SAG generated the highest apparent foam viscosity in the presence of refined oil (n-Decane). Multi-cycle SAG demonstrated high viscous displacement forces critical in field implementation where gravity effects and reservoir heterogeneities dominate. At multiple-contact miscible (MCM) conditions, no foam was generated with either injection strategy as a result of wettability alteration and foam destabilization in presence of crude oil. In both FCM and MCM corefloods, incremental oil recoveries were on average 30.6% OOIP regardless of injection strategy for CO2 foam and base cases (i.e. no surfactant). CO2 diffusion and miscibility dominated oil recovery at the core-scale resulting in high microscopic CO2 displacement. CO2 storage potential was 9.0% greater for multi-cycle SAGs compared to co-injections at MCM. A validated core-scale simulation model was used for a sensitivity analysis of grid resolution and foam quality. The model was robust in representing the observed foam behavior and will be extended to use in field scale simulations.

Summary A field demonstration test using CO2 foam for enhanced oil recovery (EOR) is being implemented in a heterogeneous carbonate reservoir in the Permian Basin of Texas. CO2 as an oil recovery agent part of carbon capture, utilization, and storage (CCUS) has gained recent attention due to growing concerns regarding greenhouse gas emissions. Current CO2 flood performance suffers due to an unfavorable mobility ratio between injected CO2 and reservoir fluids resulting in poor macroscopic sweep efficiency. Foam aims to mitigate the technical challenges of ongoing CO2 injection by improving macroscopic sweep efficiency and oil recovery while storing CO2. As part of a field pilot research program, this study presents project and operational design, baseline data collection program, and pilot monitoring to mitigate the technical challenges with current CO2 injection and verify foam mobility control and CO2 storage. Pilot performance is assessed with the data collection program and includes a tracer program to characterize interwell connectivity, time lapse cross well seismic to improve the reservoir characterization and monitor saturations, injection profiles and fall-off tests to determine zones of injection and injection pressure, and daily measurements of rate and pressure at various stages throughout pilot operation.

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 CO2 foam injections. Surfactant pre-floods, prior to CO2 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 CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 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 CO2 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 CO2 foam injection.

A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of in-situ foam generation, SAG operations must be optimized for field implementation. This study presents an integrated upscaling approach for designing a CO2 foam field trial, including pilot well selection criteria, comprehensive laboratory coreflood experiments combined with reservoir scale simulation to offer recommendations for a SAG injection schedule while assessing CO2 storage potential.Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam.A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection.Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.

Experimental secondary and tertiary CO2 injection tests in fractured, strongly water-wet, chalk core samples were performed to investigate the influence of fracture permeability, diffusion length and initial water saturation on the oil recovery potential. Liquid CO2 was injected in partially oil and brine saturated core plugs and larger blocks at miscible condition with the oil phase (n-Decane) at 20 °C and 90 bar. High final oil recoveries, up to 100%OOIP, were observed during secondary miscible CO2 injections in whole, unfractured core samples within 2 pore volumes (PV) injected. High recoveries were also observed in fractured systems (79–93%OOIP), but recovery was less efficient in terms of PV injected (4–12) as a result of increased system permeability and increased diffusion length. Tertiary CO2 injections in core samples after waterfloods were less efficient in terms of final oil recoveries (62–69%OOIP) compared to secondary CO2 injections. Additional oil recovery during tertiary CO2 injection ranged from 0% to 15%OOIP. An adverse effect of water was observed both during secondary and tertiary CO2 injections, where higher water saturation decreased the oil recovery efficiency by diffusion, indicative of a water shielding effect.

CO2 injection in hydrate-bearing sediments induces methane (CH4) production while benefitting from CO2 storage, as demonstrated in both core and field scale studies. CH4 hydrates have been formed repeatedly in partially water saturated Bentheim sandstones. Magnetic Resonance Imaging (MRI) and CH4 consumption from pump logs have been used to verify final CH4 hydrate saturation. Gas Chromatography (GC) in combination with a Mass Flow Meter was used to quantify CH4 recovery during CO2 injection. The overall aim has been to study the impact of CO2 in fractured and non-fractured samples to determine the performance of CO2-induced CH4 hydrate production. Previous efforts focused on diffusion-driven exchange from a fracture volume. This approach was limited by gas dilution, where free and produced CH4 reduced the CO2 concentration and subsequent driving force for both diffusion and exchange. This limitation was targeted by performing experiments where CO2 was injected continuously into the spacer volume to maintain a high driving force. To evaluate the effect of diffusion length multi-fractured core samples were used, which demonstrated that length was not the dominating effect on core scale. An additional set of experiments is presented on non-fractured samples, where diffusion-limited transportation was assisted by continuous CO2 injection and CH4 displacement. Loss of permeability was addressed through binary gas (N2/CO2) injection, which regained injectivity and sustained CO2-CH4 exchange publishedVersion

SummaryThis work investigated the blockage performance of a Cr(III)-acetate-hydrolyzed polyacrylamide (HPAM) gel after placement in open fractures, with emphasis on the effect of gel maturity during placement. Polymer gel is formed through a chemical reaction between a polymer and a crosslinking agent (in a gelant solution) that occurs during the gelation time. In field applications, gelant is generally pumped from the surface, but gelation may occur during injection because of high-temperature conditions and longer pumping times; hence, partially or fully mature gel may exit the wellbore during polymer-gel injection in a fractured reservoir. Gelation alters the solution properties significantly; hence, immature gelant and fully formed (mature) polymer gel show different behavior during placement in a fractured system, and the gels deposit differently in the fracture volume. Injection of gel at different maturities in a fracture may therefore influence the ability of the gel treatment to block fractures, and hence its performance during conformance-control operations. Placement of immature and mature gels and their ability to block fractures during subsequent waterfloods were investigated in this work.Gel was placed in fractures (and in the surrounding core matrix for some application regimes) in its immature (gelant) or mature state. The gel-blockage performance was assessed by recording gel-rupture pressures and subsequent residual resistance factors during chase waterfloods. Placement of mature gel in open fractures yielded consistent rupture pressures during subsequent water injections, following linear trends for given gel-placement rates and throughput volumes. The rupture pressures were predictable and stable in all the core materials studied. Rupture pressures achieved after placement and in-situ crosslinking of immature gel (gelant) were comparable with rupture pressures achieved after mature-gel placement, but were less predictable. Placing immature gel in the adjacent matrix and in the fracture increased the resistance to gel rupture compared with placing gel in the fracture volume only. In some cores, gel did not form after placement in its immature state. Interactions between Bentheim rock material and gelant were observed, and believed to be the primary cause for lack of gelation.Significant permeability reduction was achieved during subsequent waterfloods after placement of either immature or mature gel in open fractures. Residual resistance factors for cores treated with gel and gelant were comparable initially. After significant water throughput, substantially greater pressure gradients were observed in cores treated with formed gel rather than gelant crosslinked in situ, and the permeability reduction averaged 5,000 for mature gel and 600 for gelant-treated cores.

CO 2 injection in hydrate-bearing sediments induces methane (CH 4 ) production while benefitting from CO 2 storage, as demonstrated in both core and field scale studies. CH 4 hydrates have been formed repeatedly in partially water saturated Bentheim sandstones. Magnetic Resonance Imaging (MRI) and CH 4 consumption from pump logs have been used to verify final CH 4 hydrate saturation. Gas Chromatography (GC) in combination with a Mass Flow Meter was used to quantify CH 4 recovery during CO 2 injection. The overall aim has been to study the impact of CO 2 in fractured and non-fractured samples to determine the performance of CO 2 -induced CH 4 hydrate production. Previous efforts focused on diffusion-driven exchange from a fracture volume. This approach was limited by gas dilution, where free and produced CH 4 reduced the CO 2 concentration and subsequent driving force for both diffusion and exchange. This limitation was targeted by performing experiments where CO 2 was injected continuously into the spacer volume to maintain a high driving force. To evaluate the effect of diffusion length multi-fractured core samples were used, which demonstrated that length was not the dominating effect on core scale. An additional set of experiments is presented on non-fractured samples, where diffusion-limited transportation was assisted by continuous CO 2 injection and CH 4 displacement. Loss of permeability was addressed through binary gas (N 2 /CO 2 ) injection, which regained injectivity and sustained CO 2 -CH 4 exchange.

Summary A CO2 foam field pilot research program has been initiated to test and advance the technology of CO2 foam systems with mobility control to optimize CO2 integrated EOR and CO2 storage. Previous CO2 foam pilot tests have analyzed field scale displacement mechanisms, foam’s effects on gas mobility, reservoir injectivity, and overall recovery. Past tests have shown variable amounts of success, establishing the need for a more integrated methodology for advancing CO2 foam technology for EOR. This work describes initial design, generation of geologic and dynamic reservoir models, laboratory investigations, and the application of a reservoir management workflow for a CO2 foam field pilot in the Permian Basin of west Texas, USA. Application of a reservoir management workflow guides a systematic approach from data gathering, model generation, and decision making to final implementation and analysis of the CO2 foam field pilots. Initial pilot design begins with an improved reservoir characterization, field pilot selection criteria, and laboratory studies. Laboratory work investigating foam’s behavior at variable pressures found that increased reservoir pressure will result in more favorable CO2 foam behavior as it will recover oil more effectively, considering the economic limits on CO2 and surfactant usage.

Carbon dioxide has been successfully used in fields as EOR agent; and because of technical, commercial and environmental reasons, it has received considerable attention in recent years over other solvents. Based on experience with CO2 flooding worldwide, it is well understood that despite its high local displacement efficiency, the process suffers from poor sweep efficiency due to reservoir heterogeneity, viscous instability and gravity override. Application of foam has been found to mitigate these limitations at laboratory scale, however understanding of CO2-Foam flow behaviour at a larger scale is limited industry-wide. Some of the previous pilots have shown technical success especially near wellbore, but there exist a need to establish an integrated methodology to scale-up the CO2-Foam technology efficiently and effectively. As part of an ongoing research program, we have identified a field with heterogeneous carbonate reservoir onshore in west Texas, USA to run CO2-Foam field trial. The research emphasizes on implementing a modelling, monitoring and verification approach as part of the roadmap. Static model created by integrating petrophysical logs and core data in-line with geologic framework, and dynamic model created based on analysis of reservoir engineering data including RCA, SCAL, PVT, pressure data and coreflood experiments forms the basis for reservoir simulation study for the pilot area. In this paper, we provide an overview of different elements of numerical model and demonstrate application of a probabilistic framework to incorporate the uncertainties associated with model inputs. The success will be validated via appropriate monitoring plan in the ongoing pilot research program.

Numerical tools are essential for the prediction and evaluation of conventional hydrocarbon reservoir performance. Gas hydrates represent a vast natural resource with a significant energy potential. The numerical codes/tools describing processes involved during the dissociation (induced by several methods) for gas production from hydrates are powerful, but they need validation by comparison to empirical data to instill confidence in their predictions. In this study, we successfully reproduce experimental data of hydrate dissociation using the TOUGH+HYDRATE (T+H) code. Methane (CH4) hydrate growth and dissociation in partially water- and gas-saturated Bentheim sandstone were spatially resolved using Magnetic Resonance Imaging (MRI), which allows the in situ monitoring of saturation and phase transitions. All the CH4 that had been initially converted to gas hydrate was recovered during depressurization. The physical system was reproduced numerically, using both a simplified 2D model and a 3D grid involving ...

Foam injection is a proven enhanced oil recovery (EOR) technique for heterogeneous reservoirs, but is less studied for EOR in fractured systems. We experimentally investigated tertiary \(\text {CO}_{2}\) injections, and \(\text {N}_{2}\)- and \(\text {CO}_{2}\)-foam injections for enhanced oil recovery in fractured, oil-wet limestone core plugs. Miscible \(\text {CO}_{2}\) and \(\text {CO}_{2}\)-foam was compared with immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foam as tertiary recovery techniques, subsequent to waterfloods, in fractured rocks with different wettability preferences. At water-wet conditions waterfloods produced approximately 40 % OOIP, by spontaneous imbibition. Waterflood oil recovery at oil-wet conditions was below 20 % OOIP, due to suppressed imbibition where water predominantly flowed through the fractures, unable to mobilize the oil trapped in the matrix. Tertiary, supercritical \(\text {CO}_{2}\)-mobilized oil trapped in the matrix, particularly at weakly oil-wet conditions, by diffusion. Recovery by diffusion was high due to small core samples, high initial oil saturation and a continuous oil phase at oil-wet conditions. Both immiscible \(\text {CO}_{2}\)- and \(\text {N}_{2}\)-foams and miscible, supercritical \(\text {CO}_{2}\)-foam demonstrated high ultimate oil recoveries, but immiscible foam was less efficient (30 pore volumes injected) compared to miscible foam (2 pore volumes injected) to reach ultimate recovery. This is explained by the capillary threshold pressure preventing the injected \(\text {N}_{2}\) gas from entering the matrix, verified by computed X-ray tomography, and the mobilized oil was displaced by the aqueous surfactant in the foam. At miscible conditions, there exists no capillary entry pressure between the oil-saturated matrix and the injected \(\text {CO}_{2}\), allowing foam to invade the matrix for efficient oil recovery.

This work investigates dehydration of polymer gel by capillary imbibition of water bound in gel into a strongly water-wet matrix. Polymer gel is a cross linked polymer solution of high water content, where water can leave the gel and propagate through porous media, whereas the large 3D polymer gel structures cannot. In fractured reservoirs, polymer gel can be used for conformance control by reducing fracture conductivity. Dehydration of polymer gel by spontaneous imbibition contributes to shrinkage of the gel, which may open parts of the initially gel filled fracture to flow and significantly reduce the pressure resistance of the gel treatment. Spontaneous imbibition of water bound in aged Cr(III)-Acetate-HPAM gel was observed and quantified. Oil saturated chalk core plugs were submerged in gel and the rate of spontaneous imbibition was measured. Two boundary conditions were tested; 1) all faces open (AFO) and 2) two ends open-oil-water (TEO-OW), where one end was in contact with the imbibing fluid (gel or brine) and the other was in contact with oil. The rate of spontaneous imbibition was significantly slower in gel compared to brine, and was highly sensitive to the ratio between matrix volume and surface open to flow, decreasing with increasing ratios. The presence of a dehydrated gel layer on the core surface lowered the rate of imbibition; continuous loss of water to the core increased the gel layer concentration and thus the barrier to flow between the core and fresh gel. Severe gel dehydration and shrinkage up to 99 % was observed in the experiments, suggesting that gel treatments may lose efficiency over time in field applications where spontaneous imbibition is a contributing recovery mechanism. The implications of gel dehydration by spontaneous imbibition, and its relevance in field applications, are discussed for both gel and gelant field treatments.

Magnetic resonance imaging (MRI) was used to monitor the displacement of refined oil by spontaneous imbibition of brine into fully oil-saturated cylindrical cores with either one end open (OEO) or two ends open (TEO) to flow. The rocks were outcrop Whitestone Upper Zone (UZ) limestone, Berea and a Bentheim sandstone/Rordal chalk composite. In all cases, the wetting state was very strongly water-wet (VSWW). For OEO imbibition, high resolution imaging showed that brine invasion started at localized points and grew hemi-spherically outwards. The invaded regions increasingly overlapped until, after invasion of about one-third of the length of a standard core plug, a well-defined imbibition front formed that progessed as a remarkably sharp front at a velocity proportional to the square root of time. This behavior was usually observed for different boundary conditions and a range of permeabilities. For imbibition tests on a single core with TEO, imbibition started from the same core face no matter whether the core was horizontal, vertical or also vertical but inverted, showing that core heterogeneity dominated over the effect of gravity. The effect of heterogeneity was investigated further by imaging imbibition fronts in a TEO composite core formed from chalk butted against sandstone to provide a large difference in pore size. The fronts in the composite core moved at different times and velocities. Results are explained in terms of the capillary pressure gradients that develop within the composite core and, in particular, the capillary pressure at the open face(s). None of the behavior observed for a wide range of conditions can be modeled by the standard method which assumes relative permeabilities and capillary pressure relationships to give self similar fronts that expand as the front advances. The development of distinct fronts supports the modeling of imbibition, after the initial stages, as a piston-like displacement process.

Enhanced oil recovery (EOR) from mature oil fields presents unique challenges, as it requires well designed workflows for the injection of water, gas, or chemicals. Determining the optimal injection and production plan for mature fields can both maximize hydrocarbon recovery and reduce cost. This study proposes an integrated reservoir management workflow to improve oil recovery in mature oil fields in an ongoing field pilot research program. The workflow involves integration of traditional reservoir management methods with a real-time optimization approach. The early phase pilot research program management strategy is composed of several key components, including: improved reservoir characterization, generation of reservoir and simulation models, history matched simulation models, and development of a real time approach to optimize EOR reservoir peformance. The optimization strategy allows decision making at two different time scales: coarse and fine. At the coarse time scale, decisions are made about monthly injection and production rates over a time horizon from the decision making point into the distant future, aiming to optimize net present value (NPV). Various economic and technical constraints are included at both time scales. Field data from a conjoined five-spot well pattern, with two injectors and six surrounding producers, in a heterogeneous carbonate reservoir in the Permian Basin of west Texas is considered. Several realizations of a reservoir model were history-matched to field performance and subsequently used to predict and optimize future performance. The proposed workflow is being adopted within a current field pilot research program. The implementation of such a reservoir management plan allows operational decision making to be better informed and updated in real time. Assimilation of newly obtained data removes the cumbersome task of manually updating reservoir models to forecast field operations.

We present experimental results of the mixing of injection water and connate water during oil production by waterflooding in two outcrop chalk samples at three different wettabilities. The displacement of connate water by the injected water was determined using nuclear tracer imaging (NTI). For all three wettabilities investigated, strongly water-wet ( I w =1.00), moderately water-wet ( I w =0.44) and less water-wet ( I w =0.28) conditions, the connate water was fully removed from the core by the injected water. The connate water accumulated in front of the injected water, and constituted a large fraction of the water that immiscibly displaced the oil from the core plug. The connate water bank was less pronounced at reduced water-wet conditions, and the mixing between connate and injected water was increased at less water-wet conditions. Connate water breakthrough was observed at one mobile-oil-pore-volume of water injected at all three wettabilities. Breakthrough of the injected water was delayed at strongly water-wet conditions compared with less water-wet conditions, where both water phases were produced simultaneously.

The use of foam to increase oil recovery by reducing the gas mobility during gas injection in heterogeneous reservoirs with permeability variations is a proven EOR technology. The use of foam for fracture permeability reduction in fractured reservoirs is less studied. In this work laboratory experiments using foam to reduce fracture transmissivity and improve the matrix sweep in highly fractured, low permeable, oil-wet limestone are reported. Oil recovery either by individual water-, surfactant-, or gas injection exhibited low recovery, less than 10%OIP, with oil recovered predominately from the fractures. Oil recovery was significantly improved by simultaneous injection of surfactant and gas to generate foam in the fracture network and thus divert flow to the oil saturated matrix. Two foam injection schemes were tested: 1) co-injection of surfactant and gas in the fracture for in-situ foam generation, and 2) pre-generated foam injection. In-situ foam generation in the smooth-walled fractures was weak and not sufficient to divert fluids from the fractures and into the matrix. Injection of stable, pre-generated foam caused an increase in the differential pressure and diverted fluid to the matrix, yielding a significant increase in oil recovery, 80% OIP was receverd at high pore volumes injected.

Summary This work studies the mixing of injected water and in-situ water during waterfloods and demonstrates that the mixing process is sensitive to the initial water saturation. The results illustrate differences between a waterflooded zone and a preflooded zone during, for example, water-based EOR displacement processes. The mixing of in-situ, or connate, water and injected water during laboratory waterfloods in a strongly water-wet chalk core sample was determined at different initial water saturations. Dynamic 1D fluid-saturation profiles were determined with nuclear-tracer imaging (NTI) during waterfloods, distinguishing between the oil phase, connate water, and injected water. The mixing of connate and injected water during waterfloods, with the presence of an oil phase, resulted in a displacement of all connate water from the core plug. During displacement, connate water banked in front of the injecting water, separating (or partially separating) the injected water from the mobile oil phase. This may impact the ability of chemicals dissolved in the injected water to contact the oil during secondary recovery and EOR processes. The effect of the connate-water-bank separation was sensitive to the initial water saturation (Swi). The time difference between breakthrough of connate water and breakthrough of injected water at the outlet showed a linear correlation to the initial water saturation Swi. The results obtained in chalk confirmed earlier findings in sandpacks (Brown 1957) and thus demonstrated the generality in the results.

The displacement of connate water by spontaneously imbibing water was determined for chalk core plugs at different wettability conditions. The development and distribution of both aqueous phases were determined by nuclear tracer imaging (NTI) to obtain 1D fluid saturation profiles. Two boundary geometries were applied to investigate the displacement and water mixing during strictly counter-current imbibition (One-End-Open: OEO) and during both co- and counter-current imbibition (Two-Ends-Open: TEO). The connate water was displaced from the open end face exposed to the invading water phase for both boundary geometries and all wettabilities, but the rate and displacement efficiency were highly influenced by the matrix wettability. The average connate water saturation did not change during spontaneous imbibition, but its distribution in the core plug changed as the invading water phase saturation increased in all tests. A connate water bank formed at strongly water-wet conditions for both boundary conditions. In both cases the connate water accumulation constituted the entire fraction of water saturation at these positions, with little or no mixing between the connate and invading water phase during the displacement. At the end of the test the connate water accumulated in the middle of the core at TEO imbibition and at the closed end face during OEO. At weakly water-wet conditions the connate water banking was reduced and the mixing of waters was increased. The invading water displacement of the connate water was also reduced, and the aqueous phases mixed by diffusion when redistribution of fluids stopped.

Experimental oil–water and water-oil displacements in stacked, moderately oil-wet limestone core plugs are presented. The in-situ development of the oil saturations in the matrix and in the fracture was between the stacked core plugs obtained during each displacement using magnetic resonance imaging (MRI). The mechanisms of fluid flow into and across open fractures were studied as function of fracture surface wettability, oil saturation in the matrix and the injected fluid. Oil droplets formed on the fracture surface during oil- and water injections at moderately oil-wet conditions, whereas no droplets were observed at strongly water-wet conditions. Water needed to overcome a threshold pressure to enter the moderately oil-wet matrix block downstream of the fully water-filled fracture. Growing oil droplets contributed to the fluid transfer across the open, partially oil-filled fracture between two separated matrix blocks, and oil transport occurred without associated fracture pressure increase. The re-occurring droplet growth-detachment-growth behavior and the flow of isolated oil globules in fractures may have an effect on a commonly used transfer functions in dual-porosity/permeability formulations, which are based on the assumptions of instantly water filled fractures, uniform pressure distributions and time-independent shape factors.

The effect of increased sulfate concentration in the imbibing water during oil recovery by spontaneous imbibitions in different outcrop chalks at various wettability conditions at 130 °C has been determined. Core plugs from three chalk outcrops, Rordal, Niobrara, and Stevns, were aged in crude oil and included in this study. Stevns chalk exhibited increased oil recovery during spontaneous imbibition with increased concentration of sulfate in the imbibing water phase. The effect was less than reported by others and was wettability dependent. Spontaneous imbibition tests showed that the added oil recovery was greatest at Amott water indices below 0.2, and tests at and above 0.25 showed only minor effects from sulfate. Niobrara and Rordal chalk did not show increased oil recovery with increased sulfate concentration in the brine. These core plugs reflected more water-wet imbibition characteristics at elevated temperature, and the effect of sulfate could not be isolated. Measurements of Amott water indices be...

We present experimental wettability alteration results in originally strongly water-wet, outcrop chalk core plugs using a static and two dynamic aging methods. Dynamic aging with continuous crude oil injection during the entire aging process exhibited greater reduction in water-wetness of the strongly water-wet chalk plugs than static aging without flushing. Two dynamic aging procedures were tested to find an optimal flooding rate for the most efficient reduction in water-wetness: (1) a constant crude oil flooding at 3 cm3/h using variable aging times (48, 96, and 192 h) and (2) a constant aging time (96 h) with variable flooding rates (1, 3, and 5 cm3/h). The aging temperature was kept constant in all tests (90 °C), and the impacts from varying aging times, pore volumes injected, and crude oil injection rate on the wettability alteration process were investigated. Aging was performed on consolidated, porous chalk samples with initial water present in the pore space. It was shown that static aging, i.e., ...

SummaryDuring waterfloods of six outcrop chalk core-plug samples prepared at various wettabilities, simultaneous local pressures and in-situ fluid saturations were measured. Using high-spatial-resolution magnetic-resonance imaging (MRI) to image fluid saturations and pressure taps with semipermeable disks to measure individual phase pressures allowed calculations of relative permeabilities and the dynamic capillary pressure curves for the imbibition processes. A second objective was to identify individual-fluid saturation changes caused by spontaneous imbibition and viscous displacement to determine the local recovery mechanism and to calculate local recovery factors and in-situ Amott-Harvey indices. The obtained results contribute to improved description and understanding of multiphase-fluid flow in porous media, including in situ measurements of relative permeabilities, dynamic capillary pressure curves, Amott-Harvey Indices, and local oil-recovery mechanisms.

Two-dimensional imaging of water and oil saturations during waterfloods in fractured carbonate rock models was obtained using nuclear tracer imaging and magnetic resonance imaging. Large outcrop chalk and limestone blocks were aged in crude oil to obtain wetting conditions from strongly water-wet to weakly oil-wet. The change in the oil recovery mechanism as the wettability shifted was investigated with and without the presence of fractures. Visualization of local, in situ fluid saturations during waterfloods improved the interpretation of the displacement process and oil recovery mechanisms. Experimental results demonstrate how fractures determine the displacement pattern differently depending on the matrix wettability conditions during waterfloods. At strongly water-wet conditions, the fractures had a minor impact on the ultimate recovery but significantly changed the progression of the water front compared to the unfractured case. At less water-wet or oil-wet conditions, capillary imbibition of water f...

Formation of methane hydrate in Bentheim sandstone was monitored in situ with magnetic resonance imaging (MRI). Sequestration of CO 2 in hydrate accumulations was achieved by exposing the hydrate to liquid CO 2 . The spontaneous exchange of methane with C0 2 within the hydrate structure was monitored by MRI. The process of CO 2 ―CH 4 exchange in hydrates without the addition of heat or melting hydrate has the potential as a viable strategy for thermodynamically stable long term CO 2 -sequestration, with the added benefit of associated natural gas production. The MRI proved to give excellent information about the spatial distribution of the hydrate growth, the rate of the hydrate formation and the rate of the CO 2 ―CH 4 exchange. A standardized and reliable data analysis software package was developed to handle the huge amount of MRI-generated data.

Complementary imaging techniques used to study enhanced oil recovery (EOR) processes in fractured oil reservoirs have provided new and improved fundamental understanding of how oil recovery is affected by fractures. The combination of two imaging techniques such as magnetic resonance imaging (MRI) and nuclear tracer imaging (NTI) enables a complementary investigation on materials and processes, where large scale (∼m) phenomena are controlled by small scale (μm) heterogeneities. MRI provides high spatial resolution and fast data acquisition necessary to capture the processes that occur inside fractures less than 1 mm wide, while NTI provides information on macro-scale saturation distribution in larger fractured systems. The oil recovery mechanisms involved with waterflooding fractured chalk blocks were found to be dependent on the wettability of the chalk, as the wettability had great impact on the fracture/matrix hydrocarbon exchange. The MRI images of oil saturation development inside the fractures clearly revealed two distinct transport mechanisms for the wetting phase across the fracture at several wettability conditions, and provided new and detailed information on fluid fracture crossing previously observed in block scale experiments investigated by NTI. The ability to obtain rapid (∼s) 1D saturation profiles, high spatial resolution 2D images (sagital, transverse and coronal) within minutes and detailed 3D images within a couple of hours, makes MRI a powerful tool in studies of multiphase flow in fractured porous rocks, and provides excellent dynamic information of enhanced oil recovery efforts.

During spontaneous counter-current imbibition of brine into oil-filled porous rock, it is generally assumed that the flow rates of the brine and oil are equal and in opposite directions. However, significant scatter and inconsistent dimensionless times were observed in experiments using matched-viscosity fluids in two ends open (TEO) sandstone cores using an established correlation factor. In further TEO experiments, the oil production at each end face was measured separately and ranged from being equal and symmetrical to highly asymmetrical, with almost all of the mobile oil being produced from one end in nominally duplicate tests. The dimensionless time for scaled imbibition increased with increasing asymmetry in oil production. Thus, for imbibition into cores with the TEO boundary condition, although the overall flows of brine and oil have to be equal, the individual flows at each end face are not necessarily equal and opposite. The asymmetry in oil production during imbibition with the TEO boundary co...