Core Flow Experiments Research Articles

Numerical simulation of the temporal and spatial evolution of sandstone pore type reservoir damage types and severity

During the oilfield development process, various factors can cause different types of reservoir damage, leading to reduced oil well production or even shutdown, and decreased water injection capacity in water wells, resulting in significant economic losses for the oilfield. However, formation damage control measures must be based on the quantitative diagnosis of the types and degrees of reservoir damage. This paper establishes a spatiotemporal evolution numerical model for 12 common types of damage during the oil and gas exploration and development process, based on the material balance theory and Fick’s diffusion law in reservoir damage processes. This model achieves numerical simulation of the degree of various reservoir damage types in different spatiotemporal domains. The overall damage degree of a specific well’s evolution with time and space is further simulated in simple superposition way. The sequential core flow experiment was carried out in the laboratory, and then compared with the calculation results. The accuracy is above 90%. Finally, using field test data, the simulation results show a 95% or higher degree of agreement with the actual field measurements, proving that the reservoir damage spatiotemporal evolution quantitative simulation technology established in this paper has high accuracy and practicality.

Potential application of wet-phase modified expandable graphite particles as a novel in-depth profile control agent in carbonate reservoirs

Novel wet-phase modified expandable graphite (WMEG) particles were developed for in-depth profile control in carbonate reservoirs. The harsh environment of carbonate reservoirs (≥ 130 °C, ≥ 22 × 104 mg/L) brings significant challenges for existing profile control agents. WMEG particles were developed to address this problem. WMEG particles were synthesized via intercalation with ultrasound irradiation and chemical oxidation. The critical expansion temperature of WMEG particles is 130 °C, and these particles can effectively expand 3–8 times under high temperature and high salinity water. The core flow experiments show that WMEG particles exhibit a good plugging capacity, profile control capacity, and a better-enhanced oil recovery (EOR) capacity in deep carbonate reservoirs. WMEG particles can be expanded in the formation and form larger particles that bridge the upper and lower end faces of the fracture. Then the high-permeability zones are effectively plugged, and the heterogeneity is improved, resulting in an obvious increase in oil recovery. This research provides a novel insight into future applications of profile control agents for in-depth profile control treatment in carbonate reservoirs.

Study on Plugging the Multiscale Water Channeling in Low-Permeability Heterogeneous Porous Media Based on the Growth of Bacteria

Summary To promote the effect of waterflooding of a heterogeneous low-permeability reservoir in the Ordos Basin, a microbial plugging agent is developed to plug the multiscale water channeling. Based on the characteristics of the growth of bacteria, the microbial plugging agent can plug both porous media and microfractures with different scales. The microbial plugging agent is prepared by activating the native bacteria present in low-permeability reservoirs by using the fermentation nutrients. After growing in the fermentation nutrient solution for 4 days in a beaker, the growth of microbial strains begins to stabilize. After that, the main particle size of the prepared microbial plugging agent is between 40 μm and 160 μm and the median particle size (D50) is near 90 μm. The microbial plugging agent has good shear resistance, salt resistance, and stability. At the initial state, due to good injectivity, the microbial plugging agent can smoothly enter into a low-permeability core, a heterogeneous core, and a fractured core, respectively. Thus, it can grow and reproduce in the cores. Based on the characteristics of growth, it can match with the spatial scale of pore or fracture in the cores, so that it cannot only plug the porous media water channeling with different scales but also plug the microfracture water channeling with different scales. This phenomenon has been confirmed by microscopic visualization flow experiments and core flow experiments. The developed microbial plugging agent can be applied to plug the multiscale water channeling to enhance oil recovery of low-permeability heterogeneous reservoirs.

Water shutoff treatment of low permeable reservoirs by in situ polymerization: laboratory scale development and verification through core flow experiments

Excessive water generation in oil reservoirs poses economic challenges, diminishing hydrocarbon yield and incurring additional costs for water management. This study focuses on enhancing reservoir conformance control, particularly in low-permeability zones with high water production, where traditional gel-based methods face limitations. The goal is improved penetration into narrow fractures and effective sealing of water-inflow zones through in situ polymerization and sequential cross-linking. The study systematically optimized key polymerization parameters, including initiator/monomer ratios, initiator types, and environmental conditions. Core flooding tests demonstrated a significant 17% increase in original oil recovery, alongside a substantial reduction in permeability. Analytical techniques such as CT scans, thin section scans, SEM, and EDS were employed to assess gel distribution within pores and penetration rates. This in situ polymerization and gelation approach show promise in addressing water production challenges, offering enhanced recovery, and adapting well to diverse reservoir conditions. The comprehensive optimization of polymerization parameters and the use of advanced analytical methods contribute to the study’s potential impact on mitigating economic and operational issues associated with excessive water production in oilfields.

Mechanistic Insights into a Novel Controllable Phase-Transition Polymer for Enhanced Oil Recovery in Mature Waterflooding Reservoirs.

Expanding swept volume technology via continuous-phase polymer solution and dispersed-phase particle gel is an important technique to increase oil production and control water production in mature waterflooding reservoirs. However, problems such as the low viscosity retention rate, deep migration, and weak mobility control of conventional polymers, and the contradiction between migration distance of particle gel and plugging strength, restrict the long-term effectiveness of oil displacement agents and the in-depth sweep efficiency expanding capability in reservoirs. Combined with the technical advantages of polymer and particle gel, a novel controllable phase-transition polymer was developed and systematically studied to gain mechanistic insights into enhanced oil recovery for mature waterflooding reservoirs. To reveal the phase-transition mechanism, the molecular structure, morphology, and rheological properties of the controllable phase-transition polymer were characterized before and after phase transition. The propagation behavior of the controllable phase-transition polymer in porous media was studied by conducting long core flow experiments. Two-dimensional micro visualization and parallel core flooding experiments were performed to investigate the EOR mechanism from porous media to pore level. Results show that the controllable phase-transition polymer could change phase from dispersed-phase particle gel to continuous-phase solution with the prolongation of ageing time. The controllable phase-transition polymer exhibited phase-transition behavior and good propagation capability in porous media. The results of micro visualization flooding experiments showed that the incremental oil recovery of the controllable phase-transition polymer was highest when a particle gel and polymer solution coexisted, followed by a pure continuous-phase polymer solution and pure dispersed-phase particle gel suspension. The recovery rate of the novel controllable phase-transition polymer was 27.2% after waterflooding, which was 8.9% higher than that of conventional polymer, providing a promising candidate for oilfield application.

Study on Optimum Selection Method of Additives for Slick-Water Fracturing Fluid

In order to clarify the research idea of fluid system optimization in slick-water fracturing, a scientific and effective single-agent optimization method was selected to study the performance optimization method and performance evaluation method of drag reducer, clay stabilizer and cleanup additive in slick-water fracturing fluid. The specific experimental steps and application examples were investigated. To select the drag reducer, the drag reduction rate rate of the drag reducer at different concentrations should be measured first, the optimal concentration of a single agent should be selected, and then the stability test of temperature, flow rate and shear time should be performed on the optimal concentration of a single agent, and finally the combination formula with high drag reduction rate rate and stable performance can be selected. To optimize the clay stabilizer, the optimal concentration of single agent should be obtained by measuring the anti-swelling rate of different single agent and different concentration, and then the anti-swelling rate of each compound formula should be determined according to the optimal concentration of single agent, and finally the anti-swelling performance of the composite combination should be evaluated according to the core flow experiment. The optimal concentration of a single agent should first be optimized according to the surface tension of the cleanup additive, and then the combined formula should be optimized according to the surface tension of the combined combination, and the cleanup additive ability should be evaluated by core spontaneous imbibition or measuring the increase rate of cleanup additive.

Numerical simulation for MEOR considering the size effect between microorganisms and porous media

Based on the analysis of size effect between microorganisms and porous media, a one-dimensional two-phase, five-component mathematical model was presented to simulate the process of microbial flooding. The components of this mathematical model consist of oil, water, microorganisms, nutrients and metabolites, wherein the main metabolite is biopolymer. The transport equations not only consider the characteristics of microbial growth, death, chemotaxis, convection-dispersion, and adsorption-desorption, but also consider the straining behavior and the behavior of products that cannot pass through all pore areas which are caused by the size effect of microorganisms and products. This newly developed model is validated with a classical simulator and a core flow experiment. In this study, the sensitivity of the straining coefficient and product inaccessible volume were analyzed through a simulator developed according to our mathematical model. We found that: (1) The straining deposition will be much larger than the adsorption deposition; (2) The straining behavior which is caused by the size effect of bacteria has a great influence on the microbial concentration and the oil recovery; (3) The product inaccessible volume caused by the size effect of product has a significant effect on the distribution of product concentration, but has little impact on the oil recovery.

Preparation and Performance Evaluation of a Temperature and Salt Resistant Hydrophobic Associative Weak Polymer Gel System.

We targeted high-temperature and highly saline old oil fields, whose environmental conditions could be attributed to the significantly high heterogeneity cause by long-term water flooding. The Huabei Oilfield was chosen as the research object. We developed a hydrophobic functional monomer-polymer with temperature and salt resistance by introducing the temperature-resistant and salt-resistant monomer NVP and a hydrophobic functional monomer into the main chain for copolymerization. We used a crosslinking agent with phenolic resin to prepare a weak gel system that showed temperature and salt resistance and investigated its temperature and salt resistance, infective property, plugging performance, liquid flow ability, micropore throat migration, and plugging characteristics. The results obtained using the infrared spectroscopy technique revealed the successful preparation of the phenolic resin crosslinker. The weak gel exhibited good temperature and salt resistance when the polymer concentration was 2000 mg/L, the cohesion ratio was 1:1.5, the additive concentration was 2000 mg/L, the reservoir temperature was 120 °C, and the injected water salinity was 40,300.86 mg/L. The average viscosity retention rate of the 90-day weak gel reached more than 80% and its microstructure was examined. The coreflow experiment results revealed that the weak gel system was characterized by good infectivity. After plugging the weak gel, the effect on the direction of the liquid flow was evident and the flow rate of the low permeability layer increased to a maximum of 48.63% under conditions of varying permeability levels. A significant improvement in the water absorption profile was achieved. The plugging was carried out through a sand-filling pipe under varying permeability conditions and the pressure measuring points in the sand-filling pipe were sucessfully pressurized. The migration ability of the weak gel was good and the blocking rate was >85%.

A novel temperature-resistant fracturing fluid for tight oil reservoirs: CO2-responsive clean fracturing fluid

With the increasing demand for oil and gas resources, deep tight oil and gas reservoirs have gradually become the focus of global oil and gas exploration and development. Hydraulic fracturing technology based on water-base fracturing fluid plays a more and more important role in improving the recovery of tight oil reservoirs. Under the background of global CO2 emission reduction, a CO2-responsive clean fracturing fluid with controllable gelling/gel breaking at high temperatures was constructed in this paper. The system was not only friendly to the reservoir and environment, but also overcame the shortcomings of the traditional clean fracturing fluid with undesirable temperature resistance. The viscosity characteristics and viscoelastic behavior of temperature-resistant clean fracturing fluid were investigated through high-temperature rheology experiments. The interaction between fluid and rock was investigated through the core flow experiment. The results showed that the clean fracturing fluid had the characteristics of good CO2 responsiveness, excellent shear resistance at high temperatures, high drag reduction, satisfactory gel breaking performance, low filtration and low core damage. The complex three-dimensional network structure formed by the intertwined micelles and vesicles improves the temperature resistance of the clean fracturing fluid. It is expected that the fluid can not only be used to improve oil recovery in tight oil reservoirs, but also be used to solve the leakage problem in CO2 storage underground.

Reservoir Adaptability Evaluation and Application Technology of Carbon Quantum Dot Fluorescent Tracer

This study investigates the application of carbon quantum dots as tracers in inter-well connectivity monitoring. A new laboratory-made water-soluble carbon quantum dot fluorescent tracer (CQD-W) was studied using 3D fluorescence characterization, structural characterization, reservoir suitability evaluation, and core flow experiments. The experimental results showed that CQD-W has a size of about 2 nm, a minimum detection limit of 10−2 mg·L−1. It has good stability when the salinity is 200,000 mg·L−1, the concentration of Ca2+ is 1000 mg·L−1, the pH value is 1–9, and the temperature is 80 °C. Because CQD-W contains many functional groups, such as carboxyl and hydroxyl, it shows good water solubility and has a negative surface charge. In the process of formation flow, CQD-W has a small adsorption amount, high tracer resolution, and excellent injectivity and mobility, meaning it is less likely to cause reservoir damage. Through the study of this method, the application field of carbon quantum dots is broadened, and it is proved that the CQD-W fluorescent tracer has a high potential for application in the oil industry, laying the foundation for the popularization of this technology.

Experimental investigation on the enhanced oil recovery efficiency of polymeric surfactant: Matching relationship with core and emulsification ability

The polymeric surfactant can be used as an efficient agent for enhanced oil recovery (EOR) because of its large bulk viscosity and good interfacial activity. However, there is a sparse understanding of its matching relationship with reservoirs and emulsification occurrence conditions, which may affect its migration and EOR efficiency. One intermolecular association molecule polymeric surfactant (IAM) was synthesized by micellar polymerization and characterized with 1H NMR, FTIR, and TGA. The matching relationship between IAM and reservoirs was evaluated by comparing the viscosity retention rate of effluent in the core flow experiments. Moreover, the effect of the matching relationship on EOR in the heterogeneous reservoir was clarified with parallel core displacement experiments by considering different flow abilities of IAM in the high-permeability layer. The occurrence conditions of in-situ emulsification of IAM were evaluated via oil-water co-injection experiments under the different injection rates and oil-water ratios. Microscopic visualization displacement was carried out to compare the micro EOR mechanisms of different chemical systems. The results show that IAM features thickening, shearing resistance, viscoelasticity, thermal stability, and interfacial activity. The matching relationship between cores and IAM could be divided as hardly injected, flow limited, and flow smoothly, corresponding to the viscosity retention ratio of <20%, 20%–80%, and >80%, respectively. IAM could gain better EOR efficiency (17.69%) when its matching relationship to the high permeability layer was “flow limited”. The defined mixture capillary number shows that only when it is greater than 1 × 10−3, the in-situ emulsions can be generated. Compared to HPAM, IAM could reduce IFT and form vortices to more effectively displace film and corner remaining oils by stripping and peeling off crude oil. The formed emulsion accumulated at the pore throat could further increase flow resistance, which benefits swept area enlargement. This work could provide theoretical and data support for the parameters design in the polymeric surfactant practical application.

Study of fluid system for pressure reduction and injection of long-term injection wells in sensitive reservoirs

Due to the sensitivity of the reservoir itself and the aggravation of reservoir damage caused by long-term water injection in a sensitive reservoir of a block in northwest China, the phenomenon of high wellhead pressure and water injection difficulty of new injection Wells is presented in different degrees. Based on the analysis of the effect of increasing injection measures in each stage, combined with the analysis of the cause of reservoir scaling and the sensitivity of long-term water injection volume flow, a new composite treatment liquid system was developed. The system integrates the secondary precipitation inhibition technology, anti-expansion and shrinkage composite technology, deep acidification technology and foam composite acidification technology, and achieves the dissolution rate of the main treatment solution of 22.5%, can maintain a low pH for a long time, and meet the long-term scale inhibition rate of 84.89%. In the evaluation of the core flow experiment, the core permeability recovered and increased after the treatment of the working fluid system, and achieved a good effect of plugging removal and injection increase in the field practical application.

Study on the Imbibition Damage Mechanisms of Fracturing Fluid for the Whole Fracturing Process in a Tight Sandstone Gas Reservoir

Tight sandstone gas is a significant unconventional natural gas resource, and has been exploited economically mostly through the application of hydraulic fracturing technology in recent decades. However, formation damage occurs when fracturing fluid percolates into the pores inside sandstones through imbibition driven by capillary pressure during fracturing operations. In this work, the formation damage resulting from the whole operation process composed of fracturing, well shut-in and flowback, and the degree of damage at different moments were investigated through core flow experiments and the low-field Nuclear Magnetic Resonance (NMR) technique. The results show that imbibition damage occurs starting from the contact surface between the formation and the fracturing fluid, which penetrates into an increasingly deep position with time down to a certain depth. The T2 spectra of NMR at different moments indicates that fracturing fluid initially enters the small pores, followed by the large pores due to the larger capillary pressure in the former. Thus, the sandstone cores with low permeability incur a higher degree of damage due to their stronger capability of retaining fracturing fluid compared to high-permeability cores. The front position of the fracturing fluid imbibition at different moments, along with the degree of damage, were characterized through the one-dimensional encoding processing of the NMR signal. These results underlie the effective strategy to relieve formation damage resulting from imbibition during hydraulic fracturing operations.

Inorganic Acid Optimizes Remediation of Formation Damage in Carbonate Producer

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 208185, “Single-Phase Retarded Inorganic Acid Optimizes Remediation of Drilling Formation Damage in High-Temperature Openhole Horizontal Carbonate Producer,” by Ahmed Mohamed Fawzy, Noor Nazri Talib, SPE, and Ruslan Makhiyanov, SPE, ADNOC, et al. The paper has not been peer reviewed. Emulsified acid is one of the preferred choices among retarded-acid options used in Middle East high-temperature carbonate producers. However, it also brings operational complexities. The recent introduction of a single-phase retarded inorganic acid system (SPRIAS) has enabled stimulation with the same benefits as those of emulsified acids while eliminating its drawbacks. A newly drilled oil producer in one of the largest carbonate fields onshore Middle East was selected for pilot implementation of the SPRIAS. The experience gained with this pilot well confirmed the SPRIAS as a reliable option to replace emulsified acids in the region. SPRIAS The SPRIAS has the dissolution capacity of hydrochloric acids (HCl) of similar concentration. It also has a retardation factor equivalent to that of emulsified acid, which allows the creation of wormholes just as deep into the formation. Such a retardation effect was demonstrated through numerous pore-volume-to-breakthrough (PVBT) coreflow experiments at downhole conditions. Fig. 1 shows such a PVBT experiment with 15% HCl, emulsified acid, and a SPRIAS of similar HCl acid concentration on a 1-in.-diameter×6-in.-long, 8-md Indiana limestone core at 250°F. The PVBT of the emulsified acid and SPRIAS are significantly smaller than that of HCl and are statistically similar. Because it is not an emulsion but a single-phase aqueous fluid, the SPRIAS also has a viscosity within the same order of magnitude as HCl. This allows the SPRIAS to be pumped at higher rates than retarded emulsified acid. For the application discussed in this study, the SPRIAS was selected to improve the stimulation of the tighter part of the wellbore because the retarded-acid system can develop deep wormholes at low injection rates.

A Study of the Thin Film-Coated Swelling Retarding Particles in Fractured Carbonate Reservoirs for Water Plugging and Profile Control

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 104 mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, we selected XN-T from 27 kinds of swelling retarding particles by testing their swelling capacity, and coated a thin film to improve its retarding swelling capacity. The mechanisms of strong water absorption and water-holding abilities of particles were analyzed by infrared spectrometry and SEM. In the core flow experiment, the plugging rate was found to be 98.42%. Finally, the injection parameters of the coated particles were optimized to maximize the water plugging and profile control ability, resulting in an optimal particle size of 0.4–0.6 mm and a mass fraction of 10%.

Experimental Study of the Flow Mechanism of Deep Lacustrine Carbonate Reservoirs in the Yingxi Area of the Qaidam Basin

Many of the exploration and development theories derived for conventional clastic rock reservoirs are not applicable to pore-fracture lacustrine carbonate reservoirs. The fluid flow mechanisms under reservoir conditions are still unclear. Therefore, in this study, the rock samples were characterized using X-ray diffraction (XRD), porosity-permeability analysis, scanning electron microscopy (SEM), plain thin sections, and casting thin sections. The core samples were classified into two types (fractures and matrix pores) based on their reservoir spaces. The core flow experiments were performed under reservoir conditions using reservoir core plugs. The experimental results demonstrate that the cores, especially the fractured cores, have a strong stress sensitivity. The oil phase flow in the core has the characteristics of non-Darcy flow, and the threshold pressure gradient is 0.01–0.003 MPa/m. Additionally, for the oil-water two-phase flow in the fractured core, the water phase relative permeability of the residual oil is high. In contrast, the water phase relative permeability of the matrix core is less than 0.2. The nuclear magnetic resonance (NMR) transverse relaxation time ( T 2 ) spectra were used to analyze the differences between the water flooding characteristics of the two pore structures. The experimental results show that the peaks of the T 2 spectra after water flooding are lower than those before water flooding, and the matrix cores have a better oil displacement effect. The relaxation time of 0.1–10 ms makes the greatest contribution to the water flooding efficiency. The micropores smaller than 10 μm in diameter play an important role in the water flooding of the matrix core. These results will provide theoretical basis for solving the difficult problems of developing deep lacustrine carbonate reservoirs.

Analysis of nonlinear effects in fluid flows through porous media

This article examines the nonlinear effects of fluid flow in a porous medium, governed by a new semi-analytical equation, from three aspects: equation derivation, experimental verification, and macroscale simulation modelling. The rigorous derivation of the new equation is presented with a semi-analytical approach in which the gas slippage effect and inertial forces are described. The latter effect is controlled by Fochheimer number, which is defined as a product of tortuosity and Reynolds number. The new equation successfully predicts the deviations from Darcy’s law in low-permeability media when the gas slippage effect occurs. The Klinkenberg gas slippage factor is obtained as a function of porous media’s structural parameter (porosity and intrinsic permeability) and gas property (mean free path of gas molecules). The equation validations are performed by core flow experiments for a wide range of reservoir properties, which yield good matching relationship between modelled and observed values. In addition, the proposed semi-analytical equation is used to simulate gas flow in the radial model.

Stable foam systems for improving oil recovery under high-temperature and high-salt reservoir conditions

Foams have high apparent viscosity when flowing in porous media, therefore foam flooding could significantly improve unfavorable mobility ratios, increase sweep efficiency, and enhance oil recovery. However, the applications of foam flooding in high-temperature and high-salt reservoirs are seriously restricted as foam systems often have inferior foamability and stability in these reservoirs. In this study, to improve foam flooding effectiveness in high-temperature and high-salt reservoirs, novel foam systems with excellent stability and plugging capacity are developed by combining surfactants, additives, and polymers. The performance of bulk foam, physical properties of the solutions, and properties of foam systems in core-flow experiments are investigated to determine the synergistic effects among the components of the foam systems and their foamability and plugging effect in cores. In foam systems with sodium alcohol ether sulfate (AES) and dodecylhydroxypropyl sulfobetaine (DHSB) as surfactants, and dodecanol as additive, the combination of the components makes surface tension decreased and surface dilatational modulus increased, therefore the foamability and stability of the systems are improved. The results of core-flow experiments under high-temperature and high-salt conditions show that these combined systems require low injection rate for foam generation in reservoirs, which is beneficial for foam regeneration in reservoirs. Moreover, to further improve the foam performance, a hydrophobically associating water-soluble polymer (HAWP) is employed. The interactions between HAWP and the surfactants reduce the critical association concentration of HAWP, and result in the increase of solution apparent viscosity and foam stability. The results of core-flow experiments under high-temperature and high-salt conditions show that polymer-enhanced foam systems could significantly increase the sealing pressure, widen the sealing permeability range, and deal with the gas-channeling problem of foam flooding. These foam systems could provide a potential technical pathway for improving the effectiveness of foam flooding in high-temperature and high-salt reservoirs.

Flow Physics of Profile Control Fluids in Porous Media and Implications for Enhanced Oil Recovery: A Microfluidic Study

Novel profile control agents are constantly emerging in the field of enhanced oil recovery, contributing to the extension of a stable production period. However, evaluation performed through conventional core flow experiments is usually inadequate to reveal the in-depth mechanism of profile control agents. Besides, due to different operation and production modes, there is an urgent need for a specific experimental method applicable to horizontal wells in bottom water reservoirs. In this context, this paper describes two models tailored to bottom water reservoirs and investigates the flow characteristics and mechanisms of three water-shutoff agent types. At the pore scale, further study was carried out on the water-shutoff synergism between a gel and an emulsifier. The results show that the gel is present at the edge of the pore body, while the emulsion is blocked in the center of the pore body. Hence, gel that enters a water channel (main flow and accumulation area of emulsion) can cooperate with an emulsion to achieve high-strength water shutoff, making the bottom water that re-invades mainly break through at oil-rich areas. Compared with water shutoff with gel alone (randomly distributed in the breakthrough area), the synergism improves the gel’s ability to select flow channels, inhibits emulsifier channeling, and achieves a remarkable EOR effect.

Using Direct Numerical Simulation of Pore-Level Events to Improve Pore-Network Models for Prediction of Residual Trapping of CO2

Direct numerical simulation and pore-network modeling are common approaches to study the physics of two-phase flow through natural rocks. For assessment of the long-term performance of geological sequestration of CO2, it is important to model the full drainage-imbibition cycle to provide an accurate estimate of the trapped CO2. While direct numerical simulation using pore geometry from micro-CT rock images accurately models two-phase flow physics, it is computationally prohibitive for large rock volumes. On the other hand, pore-network modeling on networks extracted from micro-CT rock images is computationally efficient but utilizes simplified physics in idealized geometric pore elements. This study uses the lattice-Boltzmann method for direct numerical simulation of CO2-brine flow in idealized pore elements to develop a new set of pore-level flow models for the pore-body filling and snap-off events in pore-network modeling of imbibition. Lattice-Boltzmann simulations are conducted on typical idealized pore-network configurations, and the interface evolution and local capillary pressure are evaluated to develop modified equations of local threshold capillary pressure of pore elements as a function of shape factor and other geometrical parameters. The modified equations are then incorporated into a quasi-static pore-network flow solver. The modified model is applied on extracted pore-network of sandstone samples, and saturation of residual trapped CO2 is computed for a drainage-imbibition cycle. The modified model yields different statistics of pore-level events compared with the original model; in particular, the occurrence of snap-off in pore-throats is reduced resulting in a more frontal displacement pattern along the main injection direction. Compared to the original model, the modified model is in closer agreement with the residual trapped CO2 obtained from core flow experiments and direct numerical simulation.