CO2 Displacement Research Articles

Pore-scale visualization study on CO2 displacement of brine in micromodels with circular and square cross sections

CO2 sequestration into saline aquifers has been demonstrated as an effective technique to mitigate the effects of carbon dioxide on the atmosphere. The displacement mechanism during this process has not been clarified and the two-phase immiscible flow is affected by many factors. In this study, two types of homogeneous micromodels with circular and square cross sections were used to investigate the pore-scale of residual and capillary trapping at 25 ℃ and ambient pressure. Two salinities and six injection rates were used to study their impacts on CO2 saturation. Drainage experiments were conducted using a high-resolution microscope and a camera. The CO2 saturation and its distribution are investigated using image processing. Three forms of wetting phases are observed in circular grains, whereas additional special forms are observed in square grains, and these existing forms of the wetting phase are applied for mechanism analysis. Changes in the tortuosity and wettability are also analyzed to clarify why the saturation in the micromodel with square cross section was higher than that of circular cross section. The displacement pattern, the injection rate, the salinity, and the micromodel structure all have impacts on CO2 displacement efficiency and safe sequestration.

Time-lapse gravity monitoring of CO2 migration based on numerical modeling of a faulted storage complex

In this study, the performance of both surface and borehole time-lapse gravity monitoring to detect CO2 leakage from a carbon storage site is evaluated. Several hypothetical scenarios of CO2 migration in a leaky fault, and thief zones at different depths at the Kimberlina site (California, USA) constitute the basis of the approach. The CO2 displacement is simulated using the TOUGH2 simulator applied to a detailed geological model of the site. The gravity responses to these CO2 plumes are simulated using forward modeling with sensors at ground surface and in vertical boreholes. Results of inversion on one scenario are also presented. The surface-based gravity responses obtained for the different leakage scenarios demonstrate that leakage can be detected at the surface in all the scenarios but the time to detection is highly variable (10–40 years) and dependent on the detection threshold considered. Borehole measurements of the vertical component of gravity provide excellent constraints in depth when they are located in proximity of the density anomaly associated with the presence of CO2, thus discriminating multiple leaks in different thief zones. Joint inversion of surface and borehole data can bring valuable information of the occurrence of leakages and their importance by providing a reasonable estimate of mass of displaced fluids. This study demonstrates the importance of combining multiphase flow simulations with gravity modeling in order to define if and when gravity monitoring would be applicable at a given storage site.

Core-scale sensitivity study of CO2 foam injection strategies for mobility control, enhanced oil recovery, and CO2 storage

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.

Numerical study of CO2 injection and the role of viscous crossflow in near-miscible CO2-WAG

CO2 Water-Alternating-Gas injection (CO2-WAG) is still a challenging task to simulate and predict accurately, due to the complex interaction of CO2/oil phase behaviour, 3-phase flow and the heterogeneity of the porous medium. In this paper, we focus specifically on the regime of viscous fingering flow in CO2-WAG in heterogeneous systems because of its importance in elucidating this complex interaction. This work presents a detailed simulation study of both immiscible and near-miscible CO2-WAG and continuous CO2 displacements with unfavourable mobility ratios for 1D and 2D systems. 2D heterogeneous permeability fields were generated as Correlated Random Fields (CRF) with specified degrees of heterogeneity (permeability range, described by the Dykstra-Parsons coefficients, VDP) and structures (defined through the dimensionless correlation range, RL = λ/L).Our central aim is to improve the modelling of CO2 displacement in the transition from immiscible to miscible flows in CO2-WAG processes. To do so, two key physical mechanisms that occur during near-Miscible WAG (nMWAG) processes have been studied in detail, namely compositional effects (denoted as Mechanism 1, MCE) and low-interfacial-tension (IFT) film flow effects (denoted as Mechanism 2, MIFT). The low IFT effects in MIFT manifest themselves in an increased mobility of oil phase due to enhanced film formation and flow processes. This latter mechanism (MIFT) is modelled as an increased oil relative permeability using different well-known models (Betté and Coats) parameterized by the gas/oil IFT (σgo), calculated in the simulation from the compositional PVT model via a built-in correlation (the McLeod-Sugden equation, in this case). A range of various combinations of oil-stripping effects (MCE) and IFT effects (MIFT) has been tested to evaluate the potential impact of each mechanism on the flow behaviour such as the local displacement efficiency and the ultimate oil recovery. Oil bypassed by viscous fingering/local heterogeneity, can be efficiently recovered by WAG in the cases where both MCE and MIFT are taken into account (as opposed to either mechanism being considered alone). We also show that the way these two distinct but related mechanisms (MCE and MIFT) operate in near miscible conditions cannot be observed in (i) a simple 1D system such as a slim tube experiment, or (ii) in a heterogeneous system under continuous CO2 injection. Using tracer analysis in our simulations, we demonstrate that a major recovery mechanism in near-miscible WAG displacement is viscous crossflow between non-preferential (bypassed) flow-paths and preferential flow-paths (i.e. between the viscous fingers). Due to the significance of IFT effects (the MIFT mechanism), we also present comparative results from two of the IFT-dependent relative permeability models (Betté and Coats) showing the impact of each model on the simulation of the near-miscible WAG flow behaviour.

Determination of CO2 volume injection effect to reservoir fluid characteristic in miscible CO2 displacement

Carbon dioxide (CO2) miscible flooding is one of the Enhanced Oil Recovery (EOR) methods that has been recognized as a promising method to improve of oil recovery before abandonment. In addition, many issues related to global warming or greenhouse effect due to CO2. By using CO2 as either miscible or immiscible flooding to enhance oil recovery injected into reservoir, it may help reduce environmental problems. Carbon dioxide (CO2) is able to improve of oil recovery effectively by important key parameter: minimum miscibility pressure (MMP), viscosity, and density. This paper aims to determine the effect of CO2 volume injection to reservoir fluid characteristic in order to CO2 miscible flooding for displacing the oil production. This research was carried out by some series of laboratory experiment that involve PVT test, slim tube test, and swelling test. The result from laboratory experiments were used to observe the use of CO2 and its effect on reservoir fluid characteristics such as viscosity, solubility, and swelling factor. MMP obtained from slim tube test is 2805 Psi. Based on the results, all trend of parameters: viscosity, solubility, and swelling factor showed the positive impact of CO2 have on liquid recovery.

Nuclear-Magnetic-Resonance Monitoring of Mass Exchange in a Low-Permeability Matrix/Fracture Model During CO2 Cyclic Injection: A Mechanistic Study

SummaryRecent reports have demonstrated that carbon dioxide (CO2) injection can further raise the oil recovery of fractured tight reservoirs after natural depletion, with major projects in progress worldwide. There is, however, a lack of understanding of the mass-exchange process between the matrix and fracture at pore scale. In this study, a matrix (0.8 md)/fracture model was designed to experimentally simulate a CO2-cyclic-injection process at 80°C and 35 MPa (Lucaogou tight formation). The oil (dead-oil) concentration in the matrix and fracture was continuously monitored online using a low-field nuclear-magnetic-resonance (NMR) technique aiming to quantify the oil recovery in situ and clarify the mass-exchange behaviors. The results showed that CO2 cyclic injection was promising in improving the oil recovery of fractured tight reservoirs. Nevertheless, the oil-recovery rates rapidly declined with the cycle of CO2 injection and the incremental oil was primarily produced by large pores with 100 ms > T2 > 3.0 ms. The NMR T2 profiles of the model evidenced the drainage of the matrix oil by CO2 toward the fracture. Because of the light-hydrocarbon extraction, the produced oils became lighter than the original oil. We noted that the main driving forces of the incremental oil recovery were CO2 displacement, CO2/oil interactions (mainly extraction and solubility), and pressure gradient (depressurization). In the first cycle, the CO2/oil interactions driven by CO2 diffusion during soaking enhanced the mass exchange between the matrix and the fracture. However, from the second cycle, CO2/oil interactions and CO2 displacement became insignificant. The results of this study supplement earlier findings and can provide insights into the CO2-enhanced-oil- recovery (EOR) mechanisms in fractured tight reservoirs.NOTE: Supporting information available.

Enrichment of low-grade methane gas from nitrogen mixture by VPSA with CO2 displacement process: Modeling and experiment

To upgrade efficiently the low-concentration methane gas from nitrogen mixture, CO2 displacement was employed into the traditional vacuum pressure swing adsorption (VPSA) process to form the VPSA-CO2DIS process. Non-isothermal and non-isobaric mathematical model for the VPSA-CO2DIS process was developed, where ternary competitive adsorption equilibrium of CH4, N2 and CO2 was calculated using IAST-Sips formulation, and bi-pore diffusion model was used to describe adsorption kinetics. Experiments were carried out to enrich the low-grade methane gas using one-bed four-step VPSA-CO2DIS process with the home-made granular activated carbons (GACs), and results compared to process simulation predictions. Both experimental and simulated results confirmed that a high purity CH4 product gas (75.40% CH4) could be obtained continuously from 10% CH4 feed gas with 89.02% recovery. The combustion heat of the enriched CH4 product gas was estimated higher than the power consumption of this process, and carbon emissions penalty in this process was evaluated to be activated, so this VPSA-CO2DIS process was technically feasible.

A novel sample preparation method on CeO2 nanoparticles with TEM grid embedded liquid CO2 displacement and supercritical CO2 drying for microscopic analysis

The structural information of nanomaterials obtained from the microscopy is essential to interpret the crystal morphology, growth, and reaction kinetics. Transmission electron microscopy (TEM) is one of the most popular tools for the characterization of nanomaterials. This study reveals that conventional preparation methods for the TEM analysis largely influence the morphology and size of the synthesized nanoparticles even when they are cautiously controlled. A rigorous image analysis on the TEM images in conjunction with the selected area electron diffraction analysis of the pherical aberration corrected TEM images substantiates that small non-faceted particles grow on the large faceted particles during the conventional sample preparation for microscopic analysis. This result shows that a proper sample preparation method must be used to observe the nanomaterial as synthesized. We propose a preparation method to preserve the morphology and size of the synthesized nanoparticles by TEM grid embedded liquid CO2 displacement followed by supercritical drying.

The Feasibility Appraisal for CO2 Enhanced Gas Recovery of Tight Gas Reservoir: Experimental Investigation and Numerical Model

This paper proves the soundness of supercritical CO2 displacement for enhancing gas recovery of a tight gas reservoir via laboratory investigations and compositional modeling. First, a novel phase behavior experimental device with a screened supercritical CO2 dyeing agent were first presented to better understand the mixture characteristics between supercritical CO2 and natural gas. The mass transfer between two vapor phases was also measured. Then, based on experimental results, the compositional model considering the influence of CO2 diffusion on the gas recovery and critical property adjustment of supercritical CO2 was established. The miscibility process and mixing properties, such as density, viscosity, and the flowing velocity vector, of supercriticalCO2 and natural gas were visualized through a 3D display, which obtained a better understanding of the flooding mechanism of Enhanced Gas Recovery (EGR) via supercritical CO2. Finally, with experiments and numerical simulations, the main benefits of CO2 EGR were shown, which were partial miscibility between CO2 and natural gas, pressure maintenance, and CO2 displacement as a “gas cushion.” In general, experiments and numerical simulations demonstrate that CO2 EGR can be seen as a promising way of prolonging the productive life and enhancing recovery of tight gas reservoirs.

A new organic fiber composite gel as a plugging agent for assisting CO2 huff and puff in water channeling reservoirs

The utilization of CO2 for enhancing oil recovery is an environmentally friendly way to dispose the industrial CO2 emissions. CO2 utilization ratio is defined as the volume ratio of produced oil to injected CO2. CO2 huff and puff technology can further improve oil recovery in high water cut reservoirs. However, as the huff and puff cycle increase, gas channeling is easy to happen and the utilization ratio of CO2 is reduced. Organic fiber composite gel is an effective plugging agent for gas channel. The major objective of this paper is to study the mechanisms of increasing CO2 utilization by injecting organic composite gel as the plugging agent. A large scale (40 cm*40 cm*3 cm) natural rock model with grooves is used to simulate the experimental conditions such as channeling channel and horizontal well. Two groups of experiments of direct CO2 huff and plugging agent assisted CO2 huff and puff were conducted. By comparing the pressure changes during the experiments, the mechanism of blocking the channel, balancing the CO2 displacement front and improving the utilization ratio of CO2 were analyzed. The experimental process was fitted by reservoir numerical simulation, and the remaining oil distribution, plugging agent distribution and CO2 distribution in CO2 huff and puff under different conditions were further demonstrated. Results show that compared with direct CO2 stimulation, the distribution of remaining oil saturation and reservoir pressure become more uniform and the utilization ratio of CO2 is greatly increased after injecting organic fiber composite gel. It is mainly due to the fact that the injected plugging agents flow preferentially into high water saturation region along the high permeability channels. Then, they can generate the organic fiber composite gel and remain in the channeling paths. As a result, the following injected CO2 will be forced to flow towards oil-rich regions radially and uniformly. Thereby, more CO2 can contact and react with the in-situ oil, resulting much higher oil recovery. In other words, the utilization ratio of CO2 is greatly improved. Taking Jidong oilfield as an example, it has been injected 19.2 × 104 t CO2 with the total oil production by 21.1 × 104 t. The utilization ratio of CO2 is calculated as high as 1.09. The observations of this study provide the theoretical basis for future application of organic fiber composite gel before CO2 flooding in the water channeling reservoirs.

Enhanced Shale Gas Recovery: Gas Sorption Controls on Recoverable Gas and CO2 Storage Capacity

The natural gas industry has seen a revolution in recent times due to the boom in shale gas extraction. The process can be made more efficient by using CO2 injection as part of enhanced recovery. This would serve two key advantages: (1) Preferential shale adsorption of CO2 leading to CO2 storage and (2) Displacement of CH4 leading to higher recovery of natural gas. Executing this process on a field-scale level would need an understanding of the controls on gas adsorption in shale and the overall Gas-in-Place (GIP). In this study, CO2 and CH4 adsorption have been gravimetrically measured at high pressure on a sample of the Bowland shale at 80°C using a Rubotherm Magnetic Suspension Balance. To quantify the compositional effect on adsorption, mesoporous carbon, a synthetic material, has also been used in similar experiments, as an analogue of the organic matter in shale. Both sets of adsorption isotherms have been used to calculate the GIP at reservoir conditions. Good agreement between the two independent sets of data suggests that shales are largely mesoporous and that the organic matter is the main contributor to gas adsorption in shale.

Pore–scale analysis of supercritical CO2–brine immiscible displacement under fractional–wettability conditions

The objective of this study was to investigate the effect of wettability heterogeneity on pore–scale characteristics of Supercritical (sc) CO2 displacement dynamics and its capillary trapping mechanism during a scCO2–brine drainage and imbibition cycle. A multiphase lattice Boltzmann (LB) model was employed to simulate scCO2–brine flow in rock samples of Tuscaloosa sandstone taken from the Cranfield CO2 injection site. Using a spectral method, we adopted various wettability fields to generate rock samples containing distributed CO2–wet regions. To gain a better insight into the effect of fractional wettability on scCO2 displacement patterns during drainage, we quantified the evolution of scCO2 interface with brine and rock surface for samples with various wettability heterogeneities. In addition, the effect of heterogeneous wettability on the drainage relative permeability and capillary pressure curves has been investigated in this study. According to our results, heterogeneous distribution of CO2–wet regions in the rock leads to more dispersed fluid distribution and, hence, more tortuous flow paths, resulting in higher interfacial area between fluid phases and rock surface at any given scCO2 saturation. Furthermore, the spatial distribution of wettability controls the scCO2 entrapment pattern and spatial distribution of residual scCO2 clusters during brine flooding. In fractional–wet samples, residence of scCO2 phase in CO2–wet regions creates more trapped scCO2 clusters, suppressing the connectivity of the CO2 phase, thus enhancing more residual trapping. Our results imply that the total number of scCO2 clusters and, as a result, their residual trapping, increases as the fraction of CO2–wet regions becomes larger, leading to a larger surface area of scCO2 with brine and rock surface, potentially, facilitating the likelihood of long-term dissolution and mineral trapping.

A novel method to predict the risk of asphaltene precipitation due to CO2 displacement in oil reservoirs

A new fully predictive method was developed to calculate the risk of asphaltene precipitation in oil reservoirs based on a modification of the Asphaltene Instability Trend (ASIST) method. For prediction of asphaltene precipitation by oil depletion, this new method simplifies the ASIST method in order to use a minimum number of experimental data. As a novelty, prediction of asphaltene precipitation by CO2 displacement using a modification of the ASIST method is introduced. Both modifications were validated for a large number of oils from the literature. Results show that with both modifications this new method provides better results than previous ones to predict the risk of asphaltene precipitation in oils by depletion and unprecedented good results to evaluate potential asphaltene precipitation in oil reservoirs due to CO2 displacement with requirement of few experimental data. The proposed method may be used in the oil and gas industry to predict the risk of asphaltene precipitation by depletion or by CO2 displacement.

Investigation of high frequency 1D NMR to characterize reservoir rocks

Typical laboratory Nuclear Magnetic Resonance (NMR) measurements for core analysis are made at a frequency of 2 MHz, principally to verify downhole logging measurements with frequency ranging from 0.7 to 2 MHz. However, higher frequencies have been introduced in measuring shale properties. In this study, we investigate the differences between low frequency (2 MHz) NMR and higher frequency (12 MHz) NMR responses with different TE (Echo Time) ranging from 114 to 300μs in various rock types including sandstones and shales. We found that 12 MHz instrument attains a greater SNR (Signal to Noise Ratio) ranging from 7.3 to 9.8 times higher with fewer scans than the 2 MHz instrument. While this is an insignificant factor for highly porous rocks, it is very important when measuring shales, which requires numerous scans to achieve an acceptable SNR levels. This is also significant while tracking time dependent fluid changes in rocks. We demonstrate novel technique of the dynamic monitoring for a CO2 displacement of oil experiment with 12 MHz NMR instrument. T2 spectra were obtained every 20 min to document the oil saturation profile. From this saturation profile, breakthrough time and residual oil saturation were determined to be 340 min and 54%, respectively. Total porosity measurements were almost identical between 2 MHz and 12 MHz with an average difference of ±0.38 p.u. For shale samples only, the difference in porosity measurement was much less, i.e., ±0.16 p.u. Our results suggest that higher frequency NMR produces similar total porosity estimates, T2 geometric means, and T2 spectra for some conventional sandstones with low paramagnetic mineral content and shale lithologies.

Experimental Investigation on the Effects of CO2 Displacement Methods on Petrophysical Property Changes of Ultra-Low Permeability Sandstone Reservoirs Near Injection Wells

The petrophysical properties of ultra-low permeability sandstone reservoirs near the injection wells change significantly after CO2 injection for enhanced oil recovery (EOR) and CO2 storage, and different CO2 displacement methods have different effects on these changes. In order to provide the basis for selecting a reasonable displacement method to reduce the damage to these high water cut reservoirs near the injection wells during CO2 injection, CO2-formation water alternate (CO2-WAG) flooding and CO2 flooding experiments were carried out on the fully saturated formation water cores of reservoirs with similar physical properties at in-situ reservoir conditions (78 °, 18 MPa), the similarities and differences of the changes in physical properties of the cores before and after flooding were compared and analyzed. The measurement results of the permeability, porosity, nuclear magnetic resonance (NMR) transversal relaxation time (T2) spectrum and scanning electron microscopy (SEM) of the cores show that the decrease of core permeability after CO2 flooding is smaller than that after CO2-WAG flooding, with almost unchanged porosity in both cores. The proportion of large pores decreases while the proportion of medium pores increases, the proportion of small pores remains almost unchanged, the distribution of pore size of the cores concentrates in the middle. The changes in range and amplitude of the pore size distribution in the core after CO2 flooding are less than those after CO2-WAG flooding. After flooding experiments, clay mineral, clastic fines and salt crystals adhere to some large pores or accumulate at throats, blocking the pores. The changes in core physical properties are the results of mineral dissolution and fines migration, and the differences in these changes under the two displacement methods are caused by the differences in three aspects: the degree of CO2-brine-rock interaction, the radius range of pores where fine migration occurs, the power of fine migration.

Experimental study on the inlet behavior of CO2 foam three phase displacement processes in porous media

In relation with the potential applications of CO2 foam technology on Enhanced Oil Recovery and CO2 geological storage, the foam assisted CO2 displacement process in a surfactant solution and oil pre-saturated porous medium is experimentally investigated with special attention on the dynamic foam propagation behavior in the entrance region of porous media. Computational Tomography (CT) imaging is employed to visualize the transient CO2 foam sweep process and the dual-energy CT measurement is performed to obtain the dynamic three phase saturation distributions along the sample core. Studying parameters include the comparison with N2 foam, system backpressure and the porous medium permeability. It is found foam could push most of the liquid phase in the latter part of the porous media but leaves the forepart of the sample less flooded, showing a clear entrance effect of foam flooding process. Compared to CO2 foam, N2 foam displacement process shows higher liquid phase saturation in the entrance section and presents less oil recovery rate. Elevating system backpressure to 1.0 MPa leads to less pressure drop for CO2 foam flooding process without compromising the oil phase sweep efficiency. The CO2 foam flooding process in lower permeable medium shows higher pressure drop and higher oil recovery rate. The mechanisms for the inlet behavior of the foam displacement processes have been scrutinized based on good qualitative and quantitative agreement of the experimental and numerical results with the stochastic bubble population balance model.

Experimental study of drying effects during supercritical CO2 displacement in a pore network

Underground storage in geological aquifers is one of the most important options for large-scale mitigation of CO2. During the supercritical CO2 (scCO2) injection process, water dissolved in scCO2 may have significant impact on the displacement process. In this study, a series of wet scCO2 (WscCO2, 100% water saturation) and dry scCO2 (DscCO2, 0% water saturation) displacement experiments were conducted in micromodels for a large range of flow rates. The displacement was visualized using fluorescence microscopy. Results showed that DscCO2 saturations were up to 3.3 times larger than WscCO2 saturations when the capillary fingering dominated the displacement. The specific interfacial areas and mobile fractions for the DscCO2 displacements were also much larger than those for WscCO2. The capillary forces combined with drying effects are identified as the leading causes for the considerably higher DscCO2 sweep efficiency. Results from this study showed the important impact of mutual solubility of scCO2 and water on the displacement process and saturation of scCO2 (SscCO2), suggesting that the conventional model describing the relationship between capillary pressure and SscCO2 needs to be modified for the effect of the mutual dissolution of multiple phases to more adequately describe the scCO2 displacement process in saline aquifer formation.

Lewis Acid Enhancement of Proton Induced CO2 Cleavage: Bond Weakening and Ligand Residence Time Effects.

Though Lewis acids (LAs) have been shown to have profound effects on carbon dioxide (CO2) reduction catalysis, the underlying cause of the improved reactivity remains unclear. Herein, we report a well-defined molecular system for probing the role of LA additives in the reduction of CO2 to carbon monoxide (CO) and water. Mo(0) CO2 complex (2) forms adducts with a series of LAs, demonstrating CO2 activation that correlates linearly with the strength of the LA. Protons induce C-O cleavage of these LA adducts, in contrast to the CO2 displacement primarily observed in the absence of LA. CO2 cleavage shows dependence on both bond activation and the residence time of the bound small molecule, demonstrating the influence of both kinetic and thermodynamic factors on promoting productive CO2 reduction chemistry.

CO2-Foam Field Pilot Test in a Sandstone Reservoir

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190312, “CO2-Foam Field Pilot Test in Sandstone Reservoir: Complete Analysis of Foam-Pilot Response,” by P.D. Patil, T. Knight, A. Katiyar, SPE, and P. Vanderwal, The Dow Chemical Company; J. Scherlin, SPE, Fleur De Lis Energy; P. Rozowski, SPE, The Dow Chemical Company; M. Ibrahim and G.B. Sridhar, SPE, Schlumberger; and Q.P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed. This paper presents an analysis of a CO2-foam-injection pilot in the Salt Creek Field, Natrona County, Wyoming. The pilot was successful in demonstrating deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. A 22% decrease in the amount of CO2 injected also was realized as a result of better use of CO2 compared with the baseline. Introduction Foam-assisted CO2 enhanced oil recovery (EOR), commonly referred to as CO2-foam EOR, has been proposed as an effective technology for correcting sweep inefficiencies caused by gravity segregation and reservoir heterogeneity. The central concept of CO2-foam EOR is the in- situ generation of a viscous emulsion of CO2 and water stabilized by a surfactant at reservoir conditions. Because the apparent viscosity of a CO2/water/surfactant system is much higher than that of CO2 itself, the mobility of CO2 is significantly reduced. In the reservoir, the generation of foam occurs first in the zones preferentially swept by CO2, gradually diverting CO2 to unswept zones where oil saturation is typically higher. An important feature of the CO2 foam is that the foam strength, and hence the mobility reduction, weakens in the zones where there is substantial oil saturation. As a result, the foam does not interfere with the CO2 displacement process once the CO2 is diverted into zones with substantial oil saturation. Salt Creek Foam Pilot Although the CO2 flood in the Salt Creek Field, begun in 2004, has been very successful, certain isolated patterns were seen to exhibit high CO2 production and inefficient CO2 use, most likely because of the channeling of fluids through high-permeability, low-volume zones and the gravity override of the injected fluid. A CO2-foam pilot was undertaken to test whether these conditions could be remediated. An inverted-five-spot pattern in the Phase V area of the field was screened as the best candidate for the CO2-foam EOR pilot (Fig. 1). The pilot injector was labeled as 22SE30 and the four production wells to be monitored were wells 15SE30, 14SE30, 26SE30, and 28SE30. While other papers have been devoted to the Salt Creek foam pilot, this paper focuses on the injection-well response, the interwell tracer analysis, and the production response from the monitored producer wells in the pilot area. The authors discuss the injection and production responses for 2 years and 8 months of data. The foam injection in the field was completed in June 2016.

Self-assembled microspheres feasibility study for conformance control in high temperature and high salinity reservoirs

This paper investigated the micro-structure and swelling and heat tolerance of DCA (divinylbenzene-co-acrylamide) microsphere and its self-assembly ability at high temperature, high salinity, oil-water system. Heterogeneous cores have been used in displacement experiment to evaluate the conformance control effectiveness of DCA microsphere. The result suggested that DCA microsphere has a hollow structure and many oligomer chain segment on the microsphere surface extending into the aqueous solution. The particle size of microsphere has strong stability. DCA microsphere can tolerate temperature up to 260 °C and still self-assemble in an oil-water system at high temperature and high salinity condition; DCA microsphere can self-assemble in the core into microspherical clusters used for conformance control of injected water, resulted in subsequent water flooding pressure increase of tenfolds and oil recovery enhancement of 9.53%; DCA microsphere exhibit effective conformance control of CO2 and control well CO2 channeling. CO2 displacement with conformance control using DCA microspheres has 15.8% higher oil recovery than direct CO2 displacement. DCA self-assembled microsphere can improve development of high–temperature, high-salinity heterogeneous reservoir and provide an aid for enhanced oil recovery.