Simulation Of Oil Recovery Research Articles

Experimental investigation of zwitterionic surfactant for enhanced oil recovery in unconventional reservoir: A study in the middle bakken formation

Some surfactants may not be effective in harsh reservoir environments because of their tendency to precipitate in high salinity and high temperature conditions. However, Zwitterionic surfactants are considered more tolerant to salinity and temperature. This study investigates the ability of zwitterionic surfactants to improve oil recovery in tight core samples obtained from the Middle Bakken (MB) Formation in North Dakota. The Laboratory tests to determine the efficacy of three betaine zwitterionic surfactants were carried out at a temperature of 90 °C and a high salinity formation brine of 29 wt% to simulate oil recovery under Bakken reservoir conditions. Before the imbibition experiment, the samples underwent petrophysical investigation, and the mineral compositions were determined using the XRD method. The three surfactant samples ME1, CD 2, and CG 3 applied in the study consistently changed the wetting condition of Bakken cores from contact angle of 143.2° to a range of 32°-42°, indicating changing from oil-wet to water-wet. The result obtained shows that the interfacial tension (IFT) between brine and crude oil was reduced from 34.5 mN/m to 8.9 × 10−1 mN/m, 1.19 mN/m, and 2.49 mN/m, respectively, at a critical micelle concentration (CMC) of 0.05 %. The surfactants demonstrated a significantly higher ability to recover oil from the core samples compared to the use of brine only. The imbibition experiments revealed an extra oil recovery of 16.4 % at CMC. Thus, the imbibition of surfactant formulations offers significant potential for enhancing oil recovery in the Bakken Formation.

Numerical simulation of CO2-enhanced oil recovery in fractured shale reservoirs using discontinuous and continuous Galerkin finite element methods

Introduction: This study explores the potential of enhancing shale oil recovery and reducing CO2 emissions through CO2 injection in fractured shale reservoirs. The importance of this approach lies in its dual benefit: improving oil extraction efficiency and addressing environmental concerns associated with CO2 emissions.Method: We employed a discrete fracture-matrix model to simulate CO2 flooding in fractured shale reservoirs, utilizing both discontinuous Galerkin (DG) and continuous Galerkin (CG) finite element methods. The DG-CG FEM’s accuracy was validated against the McWhorter problem, ensuring the reliability of the simulation results. Our model also considered various factors, including reservoir heterogeneity, fracture permeability, CO2 injection volume, and gas injection patterns, to analyze their impact on shale oil recovery.Result: Our simulations revealed that fractured reservoirs significantly enhance shale oil production efficiency compared to homogeneous reservoirs, with an approximate 48.9% increase in production. A notable increase in shale oil production, by 15.8%, was observed when fracture permeability was increased by two orders of magnitude. Additionally, a fourfold increase in CO2 injection rate resulted in a 31.5% rise in shale oil production. Implementing a step-by-step reduction in injection volume while maintaining the total CO2 injection constant proved to be more effective than constant-rate injections.Discussion: The study demonstrates the effectiveness of CO2 flooding in fractured shale reservoirs for enhancing shale oil recovery.

Model Shows Computational Gains, Preserves Accuracy in Tight Rock EOR

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3834855, “Advanced Dual-Porosity and Dual-Permeability Model for Tight Rock Integrated Primary Depletion and Enhanced Oil Recovery Simulation,” by Daegil Yang, SPE, Tyler Do, and Changdong Yang, SPE, Chevron, et al. The paper has not been peer reviewed. _ Discrete fracture or dual-porosity modeling has been widely adopted for tight rock simulation. To represent the complex fracture heterogeneity and simplify its characterization, the authors present in the complete paper a new simulation model to holistically optimize the tight rock reservoir completion, primary depletion, and enhanced oil recovery modeling and retain the injection mechanism and simplify the complex fracture characterization to enhance computational efficiency. The model enables users to characterize different properties in multiple regions. This tool will have broad applications in supporting asset-development decisions. Introduction Traditional dual-porosity, dual-permeability (DPDK) simulation incorporates microscale fracture characterization through the shape factor (matrix/fracture coupling), which offers a significant contact area for the gas/oil mixture to represent the field response reliably. However, its homogeneous fracture network cannot be used to optimize the completion design. The authors have developed what they refer to as the advanced DPDK (A-DPDK) simulation work flow to maintain heterogeneous fracture characterization and to simplify microfracture characterization. The work flow contains the following features: - A newly derived shape-factor algorithm that can represent the scale and heterogeneity of the fracture network - Local grid refinement (LGR) that accelerates the speed of computation (five-times-faster acceleration) and improves accuracy - A fracture-characterization feature that serves as a helpful diagnostic tool to assign a flexible cutoff value for both propped fractures (PF) and unpropped fractures to enhance simulation speed and robustness - A connected PF feature that can label the effective fracture region to simplify completion design work flow and prioritize reservoir simulation The authors validated the new features implemented in the work flow systematically and demonstrated the benefits of the proposed work flow. The authors also applied the work flow in one gas-injection pilot and successfully history-matched the primary depletion and the gas-injection response. Modeling Approach The A-DPDK model design is aimed at modeling a complex fracture network using a structured grid system while maintaining the background natural fracture. In the modeling process, the main fracture network is screened and identified and its transmissibility calculated. Then, the microfracture is calculated to matrix mass transfer. This can be numerically modeled using a DPDK framework. The geometry of the hydraulic fracture network is preserved explicitly as grid cells in the fracture domain. Also, in the matrix domain, the enhanced permeability region (EPR), which represents the microfracture, is included. The mass transfer between matrix cells and the EPR is modeled as a grid-cell connection (transmissibility), and the mass transfer between the hydraulic fracture cells and the microfractures is modeled as a grid-cell connection as well. A new way of calculating the coupling term that models the mass transfer between the hydraulic fracture and the EPR and the matrix is introduced.

Research on pore structures of fine-grained carbonate reservoirs and their influence on waterflood development

Abstract Carbonate reservoir has complex pore structures. At present, the influence of pore structure on water flooding mechanism of carbonate reservoirs is insufficient. In this article, a systematic workflow was designed in combination with scanning electron microscope, particle size, physical properties, and water flooding experiments to study the effect of pore structure on water flooding mechanism of fine-grained carbonate rocks. Due to the small particle size and strong heterogeneity, the acid fracturing operations, rather than hydraulic fracturing alone, are necessary to achieve increased production and reservoir reconstruction of carbonate reservoirs. Through this study, the mathematical model of reservoir physical parameters (permeability and porosity) was proposed, and the accuracy of the model was verified by comparing the simulated oil recovery with the experimental results. According to the comparison results, the experimental results are consistent with the simulation results, and their oil recovery efficiency is 33.62 and 31.87%, respectively. Finally, the effect of injection rate on oil production was discussed. It is shown that with the increase in injection rate, the output of displaced oil increases significantly. The cumulative oil production increases from 62.5 to 256.31 mL when the injection rate increases from 100 to 400 mL/min. The findings of this study can help for better understanding of the influencing factors and mechanisms of the development efficiency of carbonate reservoirs.

Performance of a tight reservoir horizontal well induced by gas huff–n–puff integrating fracture geometry, rock stress-sensitivity and molecular diffusion: A case study using CO2, N2 and produced gas

This work provides a comprehensive workflow with practical guidelines for integrating fracture-geometry, rock stress-sensitivity, and gas molecular diffusion to evaluate the performance of a tight reservoir horizontal well induced by gas Huff–n–Puff (HnP). The laboratory measurements and field results were integrated in numerical simulation. The stress-sensitivity led the permeabilities of the matrix and fractures to significantly decrease during primary depletion and HnP stages, thereby impairing well productivity. Rigorous characterizations of fracture-geometry and rock stress-sensitivity are crucial for history-matching and oil recovery simulation. During produced gas HnP, the cumulative oil production was reduced by 4.6% original oil in place (OOIP) because of the stress-dependent permeability. The hysteresis in fracture-permeability noticeably decreased the transport of mass and pressure but hardly affected the short-term production owing to the rapid closure of fractures during puff stage. The final oil recoveries induced by gas diffusion were 0.4%, 0.04% and 0.35% OOIP by CO2, N2 and produced gas HnP, respectively. The produced gas HnP process produced the highest efficiency of enhanced oil recovery than CO2 and N2 owing to its significant pressurizing effect and lower gas-oil ratio. Minimum-miscibility-pressure should not be the primary consideration for gas HnP in tight reservoirs.

Towards prediction of oil recovery by spontaneous imbibition of modified salinity brine into limestone rocks: A scaling study

Spontaneous imbibition is a key mechanism of oil recovery in naturally fractured reservoirs. Many enhanced oil recovery techniques, such as modified salinity brine injection, have been suggested to improve spontaneous imbibition efficiency. To predict oil recovery by spontaneous imbibition process, scaling equations have been developed in the literature where almost none of them include the effect of two critical aspects. One aspect is the different ionic composition of injecting brine from connate brine. Another aspect is the effect of combination/interaction of a lower salinity imbibing (injecting) brine with connate brine. This research takes into account these two aspects to propose a new empirical scaling equation to scale oil recovery by modified salinity imbibing brines in limestone rocks. For this purpose, the results of available 59 tests from 14 references performed on various limestone rock samples collected from different formations and regions were used. The tests had been performed at high temperatures and on aged cores, which makes the proposed scaling equation more realistic and applicable to reservoir conditions. For the first time, the imbibing and connate brines ionic strengths are included in the equation due to the mechanism of the modified salinity brine injection method. In addition, the scaled spontaneous imbibition recovery data by the new equation was matched using two mathematical expressions based on the Aronofsky model and Fries and Dreyer model which can be used to derive transfer functions for simulation of spontaneous imbibition oil recovery by modified salinity brine injection in fractured limestone reservoirs.

Molecular dynamics simulations of oil recovery from dolomite slit nanopores enhanced by CO2 and N2 injection

Shale oil reservoirs are dominated by micro-and nanopores, which greatly impede the oil recovery rates. CO2 and N2 injection have proven to be highly effective approaches to enhance oil recovery from low-permeability shale reservoirs, and also represent great potential for CO2 sequestration. Therefore, a better understanding of the mechanism of shale oil recovery enhanced by CO2 and N2 is of great importance to achieve maximum shale oil productivity. In this paper, the adsorption behavior of shale oil and the mechanism of enhancing shale oil recovery by CO2 and N2 flooding in dolomite slit pores are investigated by performing nonequilibrium molecular dynamics simulations. Considering the shale oil adsorption behavior, mass density distribution is analyzed and the results indicate that a symmetric density distribution of the oil regarding the center in the slit pore along the x-axis can be obtained. The maximum density of the adsorbed layer nearest to the slit wall is 1.310 g/cm3 for C8H18 , which is about 2.0 times of that for bulk oil density in the middle area of slit pore. The interaction energy and radial distribution functions (between oil and CO2 , and between oil and N2 ) are calculated to display the displacement behavior of CO2 and N2 flooding. It is found that CO2 and N2 play different roles: CO2 has strong solubility, diffusivity and a higher interaction energy with dolomite wall, and the oil displacement efficiency of CO2 reaches 100% after 1 ns of flooding; however, during N2 flooding, the oil displacement efficiency is 87.3% after 4 ns of flooding due to the lower interaction energy between N2 and dolomite and that between N2 and oil. Cited as: Guo, H., Wang, Z., Wang, B., Zhang, Y., Meng, H., Sui, H. Molecular dynamics simulations of oil recovery from dolomite slit nanopores enhanced by CO2 and N2 injection. Advances in Geo-Energy Research, 2022, 6(4): 306-313. https://doi.org/10.46690/ager.2022.04.05

Development Of A Streamline-Based Heat Transport Model For Thermal Oil-Recovery Simulation

Fluid transport calculations based on streamlines have been used successfully for years to model two-phase in compressible flow simulations", The pressures for defining the streamlines are obtained by assuming that the reservoir fluids and rock are incompressible and that flow is in the steady state, which yields a time-independent equation that can be solved to define the fixed pressure distribution. Streamline tracking is performed with the pressure field to advance saturations or compositions. In this approach, the changing pressure field and the movement of fluids are not tightly connected, which results in inaccuracies in the solution.The streamline approach has recently been extended to various applications, such as compositional and black oil problems for updating the composition and saturation, In cases, a non-linear equation for the pressure is solved assuming unsteady-state flow but compressible fluids and rock, followed by solving the conservation equations in sequence or fully implicitly, i.e. the pressure and the saturation equations are solved together along each streamline. In this approach, most of the physical parameters that depend on the pressure changes are accounted for throughout the solution.The major limitation of the streamline method is that applicability is restricted to convective problems only. In practice, the contribution of physical diffusion due to gravitational and capillary forces must be considered in modeling a reservoir undergoing a displacement process. The model including diffusion cannot be solved using one dimensional (1D) streamlines. The operator splitting technique has been proposed to avoid this restriction, The idea is to isolate the convective flow from the diffusion due to gravity for separate solution. The first part is calculated along the common streamline trajectories and the second part is determined by the direction of gravity.Based on recent advances in streamline based simulation techniques, we have extended the methods to the thermal oil-recovery simulation. Modeling thermal processes is difficult due to the many complex mechanisms, high degree of non-linearity, and requirements for appropriate thermodynamic formulation to account for the changes in properties with temperature and pressure. The present study approached the problem from a different angle in the streamline framework. An operator splitting technique was applied to handle the heat diffusion due to gravity, capillary, and conduction effects, and the implicit method was used for solving the highly non- linear convective streamline and diffusive equations. A practical rule was introduced to select the time step for pressure updates to reduce the time-lag effects on the coefficients in the phase conservation equations.A sequential thermal simulator, which solves the pressure and heat equations sequentially, was developed and tested for simulations of hot water-flooding in heavy-oil reservoirs. First we performed simulation with a two dimensional (2D) heterogeneous reservoir to evaluate the main characteristics of the streamline method such as the number of streamlines, the grid refinement along the streamlines, and the time step size. Then we performed three-dimensional (3D) simulation to examine how the gravity mechanism affects the production performance. The solutions obtained using a commercial thermal simulator were used to compare and validate the developed model.

MODELING OF GRAVITY EFFECTS IN STREAMLINE-BASED SIMULATION FOR THERMAL RECOVERY

Gravity effects are more prominent in thermal recovery simulations due to larger densitydifference between phases. Historically, the streamline method has been unable toaccount for gravity effects. This is a result of assuming that the fluid path follows thestreamline path and therefore no communication among streamlines. However with gravity,a fluid pathline is different from a fluid streamline. Each phase can move vertically asa result of the gravity segregation effect in addition to the flow along streamline.Gravity effects are accounted in the streamline method by an operator splitting technique.The idea is to isolate the convective flow from diffusion due to gravity for separatesolutions. The convective part is calculated along the common streamline trajectories andthe diffusion part is determined by the direction of gravity. While this has been done successfullyfor isothermal problems, it is still a challenge to obtain both accuracy and efficiencyfor non-isothermal flow. This paper further examines the mixed streamline methodwith an operator splitting technique for this class of problems. The pressure equation fordefining streamlines was derived by summing up the mass conservation equations. Then,the mass and heat transport equations in terms of the streamline time-of-flight coordinatewere solved for each streamline. A gravity step will be followed by solving the segregationequations over the dimensional grid. For simplification of modeling, heat was assumed totransfer by convection only, of which direction is parallel with the flowing phases and theinfluence of temperature in the simulation model is through changes in fluid viscosity only.The proposed approach was tested through simulation of heavy oil recovery by means ofhot waterflooding. The results were verified with those of a commercial fully implicit thermalsimulator.

Three-Dimensional Rock Core-Like Microstructure Fabricated by Additive Manufacturing for Petroleum Engineering.

To improve the recovery rate of oil in the formation, oil recovery technology has been continuously studied. Considering the experimental cost and data measurement in oil recovery research, laboratory oil recovery is the most effective method. The rock core model used in the simulation directly affects whether the research results are credible. However, the current three-dimensional rock core model manufacturing methods and corresponding models lack of reproducible, customizable, and visualized characteristics. In this study, a reproducible rock core model of microsphere accumulation based on the structure of natural rock core was designed and manufactured by microstereolithography. Oil recovery experiments and simulation studies show that the rock core model has similar flow characteristics to natural rock cores. In addition, resin rock core models with different structures and hydrogel rock core models with deformability are also manufactured by microstereolithography and used for simulation analysis. This research provides an effective and reproducible rock core structure model for the experiment of oil recovery research.

Pore-resolved volume-of-fluid simulations of two-phase flow in porous media: Pore-scale flow mechanisms and regime map

Two-phase flow through porous media is important to the development of secondary and tertiary oil recovery. In the present work, we have simulated oil recovery through a pore-resolved three-dimensional medium using volume-of-fluid method. The effects of wettability and interfacial tension (IFT) on two-phase flow mechanisms are investigated using pore-scale events, oil-phase morphology, forces acting on oil ganglia surfaces, and oil recovery curves, for Capillary numbers (Ca) in the range of 1.2 × 10−3 to 6 × 10−1. We found that the two-phase flow through oil-wet medium is governed by pore-by-pore filling mechanism dominated by the Haines-jumps. At low Ca values, a change in the wettability from oil- to neutrally wet resulted into the change of pore-by-pore filling mechanism to co-operative pore filling and as the medium wettability changes from the neutrally to the weakly water-wet, the corner flow events begin to emerge. At low Ca values, the invasion through weakly water-wet porous medium is dominated by co-operative filling and results into an increased oil recovery, whereas the two-phase flow through strongly water-wet medium is governed by corner flow events resulting in a low oil recovery. The corner flow events are found to be a function of not only the medium wettability, but also of Ca and are a characteristic of controlled imbibition. Further, we show that a substantial decrease in the IFT results in a fingerlike invasion at pore-scale, irrespective of the medium wettability. Finally, a two-phase flow regime map is proposed in terms of Ca and contact angle based on the two-phase interface morphology.

Simulation of imbibition in porous media with a tree-shaped fracture following the level-set method

Imbibition is an important mechanism for enhancing oil recovery in low-permeability reservoirs, such as shale and tight sandstone, and a tree-shaped network has been successfully used to characterize fracturing fracture. Therefore, understanding the imbibition mechanism in porous media with a tree-shaped fracture (TFPM) is important for developing low-permeability reservoirs. In this study, a simulation model for imbibition in TFPM was established based on the level-set method, and the model was verified by comparing it with an analytical solution. The influences of the fracture width, bifurcation angle, tortuosity, and water flow rate on imbibition in TFPM were then discussed. Based on the results, the following points have been established: (1) During the early stage, the imbibition in TFPM included countercurrent and a combined imbibition, and only countercurrent imbibition occurred during the later stage. (2) At a constant fracture width ratio, increasing the primary fracture width could reduce the residual oil in the TFPM, thereby improving the oil recovery factor. (3) At a fracture bifurcation angle ranging from 0° to 45°, the oil recovery factor increased as the bifurcation angle increased. (4) At a fracture tortuosity of 1.0 to 1.24, changes in tortuosity had little effect on the oil recovery factor during the early stage of imbibition, while it significantly affected the distribution of the residual oil. (5) At a water flow rate of 5 mm/s, the simulated oil recovery factor in the TFPM was highest. This investigation can provide a reference for the development of low-permeability reservoirs.

The Role of Microbial Products in Green Enhanced Oil Recovery: Acetone and Butanone.

Green enhanced oil recovery is an oil recovery process involving the injection of specific environmentally friendly fluids (liquid chemicals and gases) that effectively displace oil due to their ability to alter the properties of enhanced oil recovery. In the microbial enhanced oil recovery (MEOR) process, microbes produce products such as surfactants, polymers, ketones, alcohols, and gases. These products reduce interfacial tension and capillary force, increase viscosity and mobility, alter wettability, and boost oil production. The influence of ketones in green surfactant-polymer (SP) formulations is not yet well understood and requires further analysis. The work aims to examine acetone and butanone’s effectiveness in green SP formulations used in a sandstone reservoir. The manuscript consists of both laboratory experiments and simulations. The two microbial ketones examined in this work are acetone and butanone. A spinning drop tensiometer was utilized to determine the interfacial tension (IFT) values for the selected formulations. Viscosity and shear rate across a wide range of temperatures were measured via a Discovery hybrid rheometer. Two core flood experiments were then conducted using sandstone cores at reservoir temperature and pressure. The two formulations selected were an acetone and SP blend and a butanone and SP mixture. These were chosen based on their IFT reduction and viscosity enhancement capabilities for core flooding, both important in assessing a sandstone core’s oil recovery potential. In the first formulation, acetone was mixed with alkyl polyglucoside (APG), a non-ionic green surfactant, and the biopolymer Xanthan gum (XG). This formulation produced 32% tertiary oil in the sandstone core. In addition, the acetone and SP formulation was effective at recovering residual oil from the core. In the second formulation, butanone was blended with APG and XG; the formulation recovered about 25% residual oil from the sandstone core. A modified Eclipse simulator was utilized to simulate the acetone and SP core-flood experiment and examine the effects of surfactant adsorption on oil recovery. The simulated oil recovery curve matched well with the laboratory values. In the sensitivity analysis, it was found that oil recovery decreased as the adsorption values increased.

Simulation of Steam-flooding Thermal Heavy Oil Recovery Process with Sequential Implicit Method

Numerical simulation of steam-flooding thermal heavy oil recovery is studied in this paper. Although the traditional full implicit scheme has high stability, it needs to calculate the huge sparse matrix and the computation cost is super expensive; so it cannot meet the needs of practical oil industry production. In this paper, sequential implicit scheme is applied to numerical computation of steam-flooding thermal heavy oil recovery. A quasi-one-dimension numerical example is tested to verify the validity and high efficiency of the proposed method against using traditional fully implicit scheme.

A reusable Fe3O4/GO-COOH nanoadsorbent for Ca2+ and Cu2+ removal from oilfield wastewater

Oilfield wastewater contains a large number of metal ions (such as Ca2+ and Cu2+). Reinjection in oil wells without treatment would affect oil recovery. To remove Ca2+ and Cu2+ ions, we prepared a reusable Fe3O4/GO-COOH nanoadsorbent by the magnetization and carboxylation of graphene oxide (GO). The Ca2+ and Cu2+ removal percents of the nanoadsorbent reached 78.4% and 51% at 60 min, respectively. After five adsorption/desorption cycles, the nanoadsorbent retained high recovery rates (82.1% for Ca2+ and 91.8% for Cu2+) and removal percents (72.3% for Ca2+ and 49.33% for Cu2+). In the simulated indoor oil recovery test, oilfield wastewater treated with Fe3O4/GO-COOH could enhance oil recovery (EOR) by 11.0% compared with untreated oilfield wastewater. The novel magnetic nanoadsorbent could not only adsorb metal ions in oilfield wastewater effectively to enhance oil recovery (EOR) but could also be quickly recycled and reused, which shows promising application prospects in oil exploitation.

Pore scale experimental and numerical study of surfactant flooding for enhanced oil recovery

Surfactant flooding is a traditional method to enhance oil recovery. The surfactant flooding experiment based on glass etching model allows researchers to observe directly how the remaining oil is displaced by surfactant through microscope, so as to explore the mechanism of surfactant enhanced oil recovery. However, microscopic experiments mostly stay at the level of physical experiments, and the operation of physical experiments is too complex and cumbersome. This study is the first to combine surfactant flooding experiment with numerical simulation in glass etching model. Firstly, based on the real pore and throat structure of the real low permeability reservoir core, the glass etching model was developed, and the micro-oil-water displacement experiment was carried out. Through microscopic observation and analysis, combined with testing and image processing technology, the effect of water flooding was quantitatively investigated. Then the surfactant flooding was carried out. Three surfactants were used for displacement. It was found that residual oil in pore network was greatly reduced. The recovery factor has been greatly improved. Finally, numerical simulation of water flooding and surfactant flooding based on micro-physical experiment was carried out. The results of numerical simulation were compared with the experimental results. It is found that the recovery factor and the form of residual oil are basically the same. By analyzing the results of numerical simulation of oil recovery, it is found that the extent of surfactant enhancing oil recovery is different under different interfacial tension. The results showed that the surfactant with interfacial tension of 0.22 mN/m has the highest ability to enhance oil recovery. This work provides a reference for surfactant selection in oilfield development. It can select the best surfactant according to the factors of time, efficiency and cost.

Multi-level delumping strategy for thermal enhanced oil recovery simulations at low pressure

We present a multi-level delumping method suitable for thermal enhanced oil recovery processes. At low pressures, the temperature variable is the most critical factor impacting the displacement process through viscosity reduction and evaporation/condensation effects. Hydrocarbon components are vaporized under high temperatures, move downstream in the gas phase and condense back to the liquid phase. That process is governed by the K-values of the components, evaporating out of the liquid phase sequentially with increasing temperatures. To reduce the computational cost, it is standard practice to reduce the number of (pseudo-) 6 components used in thermal reservoir simulation. Depending on the number and type of hydrocarbon pseudo-components retained in the simulations, we may not be able to capture the correct displacement due to large errors in the lumped phase behavior (flash) computations. We address that problem through a multi-level method: we use data obtained from a short simulation using the most detailed fluid description available, and leverage that information to guide a delumping process. We use temperature as a proxy variable for composition, and select reference temperatures. We extract the corresponding reference compositions from the detailed run and use them to extend the lumped pseudo-components to an approximate detailed composition. We compute the phase mole fractions as well as the gas compressibility factor. We test our method using six heavy oil samples, and under two different recovery processes: hot nitrogen injection and in-situ combustion (air injection and exothermic oxidation reactions). The average error on the liquid mole fraction is reduced by 4–12 times (depending on the oil samples) compared to the flash using pseudo-components, and the maximum error by 6–48 times. We illustrate that the method is amenable to manually adding more information about the physics of some oil samples. We also discuss how to efficiently pick the reference temperatures. For uniformly sampled temperatures (between a minimum and maximum temperature), we conduct a sensitivity study which led us to use six temperatures. We ran both local (Pattern Search, PS) and global (Particle Swarm Optimization, PSO) gradient-free optimization methods. PS is able to find the closest local minimum to the uniform set, giving a limited improvement of 6.5%. The known increased cost for PSO is worth the investment in at least one of the cases we considered, leading to a 67% improvement.

Techno-economic analysis of intermediate hydrocarbon injection on coupled CO2 storage and enhanced oil recovery

This study proposes economic evaluation of CO2 geological storage with enhanced oil recovery. The procedures consider capital expenditures and operating costs of infrastructures and revenues from oil recovery and carbon tax credits. Extensive CO2 geological storage with enhanced oil recovery simulations was conducted to determine the most promising scenario among cases, where miscibility was controlled by the addition of liquefied petroleum gas. The addition of liquefied petroleum gas into a CO2 injection stream can accelerate reduction of oil viscosity, interfacial tension, and oil density, which cause improved displacement efficiency. The larger was the amount of liquefied petroleum gas injected, the greater was the miscibility due to minimum miscibility pressure reduction, resulting in higher oil recovery and less CO2 sequestration. Although liquefied petroleum gas addition enhances the performance of CO2 enhanced oil recovery, economic analysis should be conducted for CO2 geological storage with enhanced oil recovery due to the higher price of liquefied petroleum gas than that of CO2. Net present value decreased from liquefied petroleum gas mole fraction of 0–2% and started to increase from mole fraction 2–13% due to the miscibility effect. Then, net present value started to decrease, because the purchasing and injecting prices of the required liquefied petroleum gas exceeded that of the oil produced. Economic evaluation showed that addition of 13% liquefied petroleum gas was the most promising scenario, with a net present value of 91 MM$. Thus, we confirmed an optimum liquefied petroleum gas concentration in the CO2 geological storage with enhanced oil recovery process.

Effect of Pore Size Heterogeneity on Hydrocarbon Fluid Distribution, Transport, and Primary and Secondary Recovery in Nano-Porous Media

In this paper, we investigate the effect of pore size heterogeneity on fluid composition distribution of multicomponent-multiphase hydrocarbons and its subsequent influence on mass transfer in shale nanopores. The change of multi-contact minimum miscibility pressure (MMP) in heterogeneous nanopores was investigated. We used a compositional simulation model with a modified flash calculation, which considers the effect of large gas–oil capillary pressure on phase behavior. Different average pore sizes for different segments of the computational domain were considered and the effect of the resulting heterogeneity on phase change, composition distributions, and production was investigated. A two-dimensional formulation was considered here for the application of matrix–fracture cross-mass transfer and the rock matrix can also consist of different segments with different average pore sizes. Both convection and molecular diffusion terms were included in the mass balance equations, and different reservoir fluids such as ternary mixture syntactic oil, Bakken oil, and Marcellus shale condensate were considered. The simulation results indicate that oil and gas phase compositions vary in different pore sizes, resulting in a concentration gradient between the two adjacent pores of different sizes. Given that shale permeability is extremely small, we expect the mass transfer between the two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix–fracture component mass transfer as a result of confinement-dependent phase behavior. Therefore, the molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection enhanced oil recovery (EOR) simulation of heterogeneous shale reservoirs.

Prediction of the surface tension of gas-based nanofluids + model oils system by CPA EoS: Implementation in the simulation of by-passed oil recovery from a single block matrix of fractured reservoirs fully-immersed in the nanofluids

By increasing oil drainage from the gas-invaded zone of fractured reservoirs, the capillary force resists and a huge volume of the in-place oil is by-passed in the matrix blocks where the main recovery mechanism is gravity drainage. In this work, the effectiveness of the injection of gas-based nanofluids for the recovery of the by-passed oils is analyzed. Asphaltene was extracted from a dead oil sample and characterized. Model oils of asphaltene in n-heptane/toluene (heptol) solutions were prepared and the surface tension of the model oils + air was measured by pendant drop tensiometry. Cubic plus association equation of state (CPA EoS) with tuned parameters exhibits precise predictions of the surface tension data. The asphaltene self-association energy in the gas-liquid interface is found to be lower than that in the bulk of the liquids. This implies that the configuration of the asphaltene molecules in the bulk and the interface is not the same. The CPA EoS exhibits reasonable predictions of the surface tension of gas-based nanofluids + air system. Using the CPA EoS and the principles of the gravity displacement, a mathematical model was developed for the simulation of the by-passed oil recovery from a single matrix block fully-immersed in the gas-based nanofluids. It is found that, although the oil recovery is enhanced slowly by the nanofluids injection, no plateau is observed in the recovery factor curves in short injection times. The diffusion coefficient of the nanoparticles in the matrix block plays a key role in the by-passed oil recovery by the injection scenario.