Oil Recovery Mechanisms Research Articles

Enhanced oil recovery mechanism and recovery performance of micro‐gel particle suspensions by microfluidic experiments

AbstractMicro‐gel particle suspensions (MGPS) have been proposed for enhanced oil recovery (EOR) in reservoirs with harsh conditions in recent years, yet the mechanisms are still not clear because of the complex property of MGPS and the complex geometry of rocks. In this paper, the micro‐gel particle‐based flooding has been studied by our microfluidic experiments on both bi‐permeability micromodels and reservoir‐on‐a‐chip. A method for reservoir‐on‐a‐chip design has been proposed based on QSGS (quartet structure generation set) to ensure that the flow geometry on chip owns the most important statistical features of real rock microstructures. In the micromodel experiments with heterogeneous microstructures, even if the MGPS has the same macroscopic rheology as the hydrolyzed polyacrylamides (HPAM) solution for flooding, MGPS may lead to significant fluctuations of pressure field caused by the nonuniform concentration distribution of particles. In the reservoir‐on‐a‐chip experiments, clustered oil trapped in the swept pores can be recovered by MGPS because of pressure fluctuation, which hardly happens in the HPAM flooding. Compared with the water flooding, the HPAM solution flooding leads to approximately 17% incremental oil recovery, while the MGPS results in approximately 49.8% incremental oil recovery in the laboratory.

Detailed Assessment of Compositional and Interfacial Tension Effects on the Fluid Behaviour During Immiscible and Near-Miscible CO2 Continuous and WAG Displacements

This study seeks to improve numerical simulations of the key physics occurring in CO2 enhanced oil recovery (CO2-EOR) processes, with a particular focus on the transition from immiscible to miscible displacements. In the previous work, we have investigated interactions between compositional effects and the underlying heterogeneities of the flow field in near-miscible floods (Wang et al. in Transp Porous Media 129(3):743–759, 2019a). In this current study, we have further analysed the effects of reduction in interfacial tension (IFT) on the flow behaviour, as motivated by the study on the film-flow mechanism previously presented by Sorbie and van Dijke (SPE improved oil recovery symposium, Society of Petroleum Engineers, 2010). We identify two clear mechanisms of oil recovery that may occur in near-miscible CO2 (or other gas) injection processes, which we denote, MCE, as oil stripping or conventional compositional effects, and MIFT as lower IFT oil film-flow effects. The latter MIFT effects are described by an enhanced hydrocarbon relative permeability in the near-miscible three-phase relative permeabilities (3PRP). Various combinations between the MCE and MIFT mechanisms were tested by numerical simulations to evaluate the impact of each mechanism on the flow behaviour, i.e. their separate and joint effects on quantities such as the local oil displacement efficiency, phase flow vectors and the ultimate oil recovery. When acting in combination, the oil stripping and IFT effects can greatly improve the local displacement performance even when viscous fingering flow occurs. Viscous fingering is well known to lead to bypassed oil in the “non-preferential” flow paths between the main fingers. We show that the remaining oil in these non-preferential flow paths (i.e. bypassed oil) can be efficiently recovered by the combined MCE and MIFT mechanisms, but only with the application of water alternating gas (WAG). In contrast to oil stripping effects, the IFT effect is not dependent on continuous contact between oil and CO2. Instead, the remaining oil is mobilized by gas as the IFT is reduced and can be efficiently produced by subsequent water injection. This MIFT mechanism has much less impact in cases with continuous CO2 injection compared to its efficiency in WAG. This is because during continuous injection, gas fingers are dominant in the preferential flow paths, and therefore the local displacement efficiency is very good, but only in these preferential routes. On the other hand, WAG is able to make full use of the IFT effects because of its relatively stable displacing front, which allows the MIFT mechanism to contribute. In this study, the effects of using different three-phase relative permeability methods were investigated and, as expected, different methods yielded different results. However, an important observation is that when IFT effects (MIFT) were included, there was much less difference in the final oil recovery using the different 3PRP models; our analysis shows why this is the case.

Pore-scale study of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR and storage in oil reservoirs

SummaryCO2 injection in oil reservoirs has been widely accepted as an effective EOR and CO2 storage technique. While oil recovery and CO2 storage potential of this technique at the core scale has been widely studied, complex fluids flow and fluid-fluid interactions at the pore-scale during nearmiscible CO2 injection require further study. For this aim, a unique high-pressure and high-temperature microfluidic system was used to conduct experiments at 2,500 psi and 40°C using live reservoir crude oil.According to results, during tertiary CO2 injection, due to the positive value of spreading coefficient, CO2 flowed only inside the oil and oil spread over CO2 and prevented CO2 contact the water. Due to unfavourable mobility ratios and permeability heterogeneities, displacement during tertiary CO2 flooding was unstable and viscous fingering occurred which led to an early breakthrough of CO2 and bypassing of a large amount of oil. However, after CO2 breakthrough, CO2 gradually started to flow inside the bypassed oil zones in the transverse/backward directions which is a characteristic of capillary fingering. Due to the gradual diffusion of CO2 into the bypassed oil, IFT between oil and CO2 decreased which led to a reduction of threshold capillary pressure, thus CO2 (non-wetting phase) entered the bypassed oil-filled pores. As a result of this unique mechanism, oil recovery after CO2 breakthrough significantly increased and almost all the bypassed oil was produced. The extent of this oil recovery mechanism depends on the extent of CO2-oil IFT reduction which depends on injection pressure.During CO2 flow in pores, CO2 displaced the water through multiple displacement mechanism. CO2 displaced the oil in the open-end pores thorough bulk flow, and the spreading oil layers were gradually produced by film flow. Uniquely, CO2 produced the oil in dead-end pores through a mix of bulk flow and film flow.The outcomes of this study provide an in-depth understanding of fluids flow and fluid-fluid interactions during near-miscible CO2 EOR-storage.

The role of fines transport in low salinity waterflooding and hybrid recovery processes

Low Salinity Waterflooding (LSW) is a promising technology for improving oil recovery in secondary and tertiary stages over the conventional waterflooding (HSW). As widely reported in the literature, this emerging recovery approach has relatively low operating costs and is more environmentally-friendly than conventional Enhanced Oil Recovery (EOR) methods. In fact, LSW is a multi-physics recovery process; however, most of the previous studies focused on wettability modification as the sole mechanism for the incremental oil recovery by LSW. Unfortunately, these studies often ignored other crucial factors that importantly affect the performance of LSW, e.g., fines transport under a low salinity injection environment.This paper introduces a robust modeling workflow to capture important recovery mechanisms occurred in LSW by integrating fines migration, wettability alteration, and geochemistry. The results showed that fines transport including fines deposition, fines migration, and fines plugging plays an important role in LSW process. Fines plugging by LSW can cause formation damage, but it also can be used as a mobility control agent. The LSW model equipped with fines transport shows an excellent agreement for incremental oil recovery and pressure drop against laboratory coreflooding. Finally, a novel concept of hybrid low salinity assisted gas flooding was proposed to overcome the existing technical challenges associated with the conventional CO2 flooding.

Sulphate Ion Interference on Oil Recovery Mechanism of Low Salinity Waterflooding in Dolomite Reservoirs

This study focused on the sulphate ion concentration interference with different divalent cations ratio, used in low salinity water flooding in dolomite reservoirs by comparing the oil recovery with the altered amount of divalent cations dissolved in brine, occurred from rock surface equilibrium shifting. The oil recovery from injecting different potential determining ions concentration is measured by core flood experiment. The process of detecting the amount of divalent cations begins with establishing oil adsorption on the dolomite grain surface. Then, the grain is stirred in brine with different formula, which is later titrated in order to gather the desired data. Finally, the phenomena occurred during flooding with different potential determining ion concentration is described by combining the result of oil recovery with altered amount of divalent ions. The results showed that at high temperature (70°C), the oil recovery from each case is not much different because high amount of calcium sulphate precipitation can be compensated by high rate of rock dissolution and magnesium carboxylate complex formation. However, at low temperature (30°C), the oil recovery tends to be lower when the sulphate concentration is higher because calcium ion tends to form or precipitate with sulphate ion rather than forming the carboxylate complex. Due to low dissolution rate, the amount of calcium ion is insufficient for oil recovery mechanism, especially when the sulphate ion concentration exceeds the solubility limit. Furthermore, for the case that the ratio of magnesium to calcium ion is high, it is observed that some amount of magnesium ion can form the carboxylate complex to compensate the lost amount of calcium ion. From the result, it can be concluded that at low temperature, which the dissolution reaction occurs slowly, the effect of changing the divalent cation ratio, including sulphate concentration, is large because the formation of magnesium carboxylate complex is not much at this temperature, however calcium sulphate precipitation reduces the number of active calcium ions in oil recovery mechanism. On the other hand, because the dissolution reaction occurs faster and the formation of magnesium carboxylate complex is more favourable at high temperature, therefore the values of oil recovery, even at different concentration of potential determining ions, are not much different at this temperature. Furthermore, it is also found that the carboxylate complex formation can be induced by high concentration of either type of divalent ions when the sulphate ion concentration is not too high.

From Atoms to Pre-salt Reservoirs: Multiscale Simulations of the Low-Salinity Enhanced Oil Recovery Mechanisms

The goal of this review paper is two-fold: bringing an updated survey on the literature of the proposed mechanisms behind the low-salinity enhanced oil recovery (EOR) and propose ways to model them based on simulations coupling atomic to reservoir scales. The low salinity water injection (LSWI) presents some advantages over other EOR techniques since it is a cost-effective method, has no inherent environmental damage and does not affect the subsequent stages of crude oil treatment and refinement. The LSWI is particularly interesting for exploration and production on pre-salt carbonate reservoirs. We couple the LSWI mechanisms with molecular modeling methodologies, addressing their use to describe the EOR via LSWI. From the molecular modeling, one can obtain parameters for the large-scale reservoir simulators, thus, improving their accuracy. Therefore, the molecular modeling approaches are complementary tools to optimize the EOR via LSWI. Among all the involved mechanisms on the LSWI, the wettability alteration is pointed out by several authors as the fundamental one, to explain the EOR. However, there are controversies related to its cause: salting-in effect, multi-component ionic exchange, pH alteration, electric double layer expansion, fines migration, limited release of particles and osmotic pressure are among the main proposals. In this sense, several molecular modeling techniques have been explored to foster theories that explain the possible mechanisms and optimize the oil production combining the molecular dynamics simulations and Ab initio calculations with reservoir simulators.

Comparison of modified effective-medium approximation to pore-network theory for relative permeabilities

Pore-network models have been used to derive relative-permeability and capillary-pressure relations, which are important for oil-recovery predictions and processes. Here, we show that relative-permeability and capillary-pressure relations on large scales can be obtained much faster with the effective-medium approximation. Our approach differs from previous work in that we use various shapes of non-circular pores and combinations of different shapes. We use a finite-element approach to compute the hydraulic conductivity of arbitrarily shaped prisms, which are partly filled with oil and water. Our present interest is confined to water-wet media. Striking features of the obtained constitutive relations are that the water relative permeabilities show a marked reduction below a critical water saturation—at which there is no infinite cluster of completely filled water pores—but the water relative permeabilities continue to be finite even at very low water saturations because of corner flow. The capillary pressure remains finite even at low water saturations. Primary-drainage oil relative permeabilities are non-zero at low oil saturations, which is in line with early gas breakthrough for the solution-gas drive oil-recovery mechanism. We compare the results obtained with the effective-medium approximation to the results obtained with a pore-network model consisting of a simple-cubic lattice of prisms. The comparison shows that the pore-network generated relative-permeability curves are completely dissimilar to the effective-medium approximation derived relative-permeability curves. Furthermore, below and near the percolation threshold, the pore-network results differ significantly from one realization to another and/or from one network size to another network size. The network-model results show discontinuous behavior at the percolation threshold. This implies that pore-network results are scale dependent and the pore-network sizes up to 301 × 301 × 301 (the limitation determined by the available computer power) studied here are still far from a representative elementary volume (REV).

A Pore-Scale Investigation of Residual Oil Distributions and Enhanced Oil Recovery Methods

Water flooding is an economic method commonly used in secondary recovery, but a large quantity of crude oil is still trapped in reservoirs after water flooding. A deep understanding of the distribution of residual oil is essential for the subsequent development of water flooding. In this study, a pore-scale model is developed to study the formation process and distribution characteristics of residual oil. The Navier–Stokes equation coupled with a phase field method is employed to describe the flooding process and track the interface of fluids. The results show a significant difference in residual oil distribution at different wetting conditions. The difference is also reflected in the oil recovery and water cut curves. Much more oil is displaced in water-wet porous media than oil-wet porous media after water breakthrough. Furthermore, enhanced oil recovery (EOR) mechanisms of both surfactant and polymer flooding are studied, and the effect of operation times for different EOR methods are analyzed. The surfactant flooding not only improves oil displacement efficiency, but also increases microscale sweep efficiency by reducing the entry pressure of micropores. Polymer weakens the effect of capillary force by increasing the viscous force, which leads to an improvement in sweep efficiency. The injection time of the surfactant has an important impact on the field development due to the formation of predominant pathway, but the EOR effect of polymer flooding does not have a similar correlation with the operation times. Results from this study can provide theoretical guidance for the appropriate design of EOR methods such as the application of surfactant and polymer flooding.

Ketone solvent as a wettability modifier for improved oil recovery from oil-wet porous media

The main objective of this research is to investigate a novel class of oxygenated solvents that can enhance the oil recovery from oil-wet rocks by multiple mechanisms, such as wettability alteration, oil-viscosity reduction, and oil swelling, in the presence of brine (connate water and/or fracturing water). The compound studied for the first time in this research is 3-pentanone (3p), a symmetric short ketone that can partition into both oil and brine at reservoir conditions. It can act as a solvent by itself, but this paper is focused on the potential mechanisms of oil recovery when an aqueous solution of 1.1 wt% 3p in reservoir brine (3pRB) is in contact with oil and oil-wet rock.Results show that the average contact angle of oil droplets on oil-aged calcite surfaces was rapidly reduced to 26° with 3pRB, in contrast to 123° with RB, without affecting the oil/brine interfacial tension. Spontaneous imbibition results show that the oil recovery factor reached 50.0% with 3pRB and 10.0% with RB at Day 3. The final recovery factor was 51.0% with 3pRB and 12.0% with RB. The subsequent forced imbibition determined the Amott index to water of 0.76 with 3pRB and 0.23 with RB, indicating a clear, positive impact of 3pRB on oil recovery by water imbibition in the cores tested. The main mechanism of oil recovery by 3pRB in this research is the wettability change as demonstrated by the contact-angle experiment.

Oil phase displacement by acoustic streaming in a reservoir-on-a-chip

This article presents a reservoir-on-a-chip study of acoustic streaming as an enhanced oil recovery mechanism. Microfluidic devices with different porosities are fabricated using photolithography to serve as reservoir-on-a-chip micromodels. We use microparticle image velocimetry to characterize acoustic streaming-induced pumping as a function of frequency and amplitude. A scaling model applied to the velocity distribution is used to construct a state diagram that connects acoustic pressure to field frequency and amplitude. Optical video fluorescence microscopy is used to track the invasion of a water phase through the oil-saturated porous micromodel. Based on these measurements, we calculate the Blake number as a function of frequency to show that our system exhibits a narrow band dynamic response consistent with a system operating near resonance. Our observations are compared to a general model for Blake number as a function of frequency, porosity and voltage amplitude that was derived from a force balance model of the micromodel undergoing forced oscillation. The results from this paper are broadly applicable to systems beyond enhanced oil recovery, including separations, bio-analytical instruments, additive manufacturing and flow control.

Microorganisms\u2019 effect on the wettability of carbonate oil-wet surfaces: implications for MEOR, smart water injection and reservoir souring mitigation strategies

In upstream oil industry, microorganisms arise some opportunities and challenges. They can increase oil recovery through microbial enhanced oil recovery (MEOR) mechanisms, or they can increase production costs and risks through reservoir souring process due to H2S gas production. MEOR is mostly known by bioproducts such as biosurfactant or processes such as bioclogging or biodegradation. On the other hand, when it comes to treatment of reservoir souring, the only objective is to inhibit reservoir souring. These perceptions are mainly because decision makers are not aware of the effect microorganisms’ cell can individually have on the wettability. In this work, we study the individual effect of different microorganisms’ cells on the wettability of oil-wet calcite and dolomite surfaces. Moreover, we study the effect of two different biosurfactants (surfactin and rhamnolipid) in two different salinities. We show that hydrophobe microorganisms can change the wettability of calcite and dolomite oil-wet surfaces toward water-wet and neutral-wet states, respectively. In the case of biosurfactant, we illustrate that the ability of a biosurfactant to change the wettability depends on salinity and its hydrophilic–hydrophobic balance (HLB). In distilled water, surfactin (high HLB) can change the wettability to a strongly water-wet state, while rhamnolipid only changes the wettability to a neutral-wet state (low HLB). In the seawater, surfactin is not able to change the wettability, while rhamnolipid changes the wettability to a strongly water-wet state. These results help reservoir managers who deal with fractured carbonate reservoirs to design a more effective MEOR plan and/or reservoir souring treatment strategy.

Optimal Zwitterionic Surfactant Slug for an Improved Oil Recovery in Oil Wet Carbonate Rocks - Silurian Dolomite

The increase in energy demand has led to extensive research and development on economically, environmentally and technically feasible ways of improving the ever-growing energy demand. A common derivative of energy is from hydrocarbons, specifically oil. The process of oil recovery can be divided into primary, secondary, and tertiary recovery (also known as enhanced oil recovery). Once the internal pressure of a reservoir has depleted enough during primary and secondary recovery, more advanced techniques in enhanced oil recovery mechanisms are used to recover 50-80% of oil in the reservoir. Tertiary recovery includes the use of surfactants to reduce interfacial tension (IFT) or alter wettability. In this work, a zwitter ionic surfactant at two different concentrations is evaluated for its ability to reduce the interfacial tension between oil and water, as well as altering wettability in silurian dolomite. To achieve this, fluid-fluid analysis was done by a compatibility test, phase behavior test and interfacial tension measurements. Rock-fluid analysis was also completed by means of floatation test, carried out with carbonate rock particles to analyze the surfactant’s ability to alter wettability. Solution pH measurements were taken to validate the qualitative floatation test results. Results show that the surfactant, chembetaine C surfactant, is compatible with all ranges of salinities investigated, though was not able to produce a winsor type III micro-emulsion. The results of the interfacial tension measurements are in line with the phase behavior test, as none of the measurements were at ultra-low values. Surfactant retention is likely to occur with the analyzed zwitterionic surfactant based on the fluid-fluid analysis. Qualitative results from the floatation test show that the wettability of the carbonate rock particles cannot be significantly altered to more water-wet conditions. The pH of the solution remains at alkaline values, which can be beneficial in enhanced oil recovery in producing soap in situ, also known as saponification. Overall, tests conclude that this zwitterionic surfactant at 1% concentration would be most effective at 10,000 ppm salinity brine, though overall is not suitable for chemically enhanced oil recovery.

Experimental application of functionalized N-doped graphene for improving enhanced oil recovery

Recently, application of nanofluids in enhanced oil recovery (EOR) has become a demanding quest for academic studies since applying nanofluids has been supported by promising results of experimental studies in laboratories. Combining a bunch of available laboratory results with recent theoretical studies led to development of an experimental-simulation package, which could be used for scaling up and pilot tests in EOR planning of hydrocarbon fields, the results of which can be proposed for larger scales of EOR scenarios. In this experimental survey, potential of functionalized nitrogen-doped graphene in enhanced oil recovery was investigated experimentally. The first part of this experimental research deals with the synthesis and characterization of nitrogen-doped graphene including FTIR analysis and FESEM imaging. In the next section, the enhanced oil recovery mechanisms including interfacial tension reduction and wettability alteration were thoroughly investigated. Finally, an extensive core flooding test was performed on a sandstone core sample to study the application of the prepared nanofluid in oil recovery improvement. At the end, Microscopic phenomena such as interfacial tension and wettability were investigated by pressure drop and recovery plot during the core flooding test.

Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale.

Oil Recovery Mechanisms During Sequential Injection of Chelating Agent Solutions Into Carbonate Rocks

Chelating agent solutions have been proposed as effective fluids for enhancing oil production. Different recovery mechanisms are reported for increasing the oil recovery during chelating agent flooding. The aims of this work are to identify the possible recovery mechanisms during chelating agent flooding in carbonate reservoirs and to investigate the in situ CO2 generation as a potential recovery mechanism during the injection of chelating agent solutions into carbonate reservoirs. The contribution of CO2 on enhancing the oil recovery was determined using experimental measurements and analytical calculations. Several measurements were conducted to study the contribution of each mechanism on enhancing the oil recovery. Coreflooding tests, zeta potential measurements, CO2 generation, and interfacial tension (IFT) experiments were carried out. Also, analytical models were utilized to determine the impact of the injected chemicals on reducing the capillary pressure and improving the flow conditions. In flooding tests, two chemicals (EDTA and GLDA) were injected in a sequential mode and the chemical concentration was increased gradually. In addition, a comparative study was performed to evaluate the effectiveness of EDTA and GLDA solutions to enhance oil recovery. Several parameters were investigated in this paper including incremental oil recovery, in situ CO2 generation, hydrocarbon swelling, IFT, wettability alteration, permeability enhancement, productivity index, and chemical cost. The obtained results show that GLDA chelating agent has better performance than EDTA solutions for enhancing the oil recovery when the same concentrations are used. Also, the in situ generation of CO2 shows a significant impact on improving the oil recovery from carbonate reservoirs during chelating agent flooding. In the literature, the reported recovery mechanisms of using chelating agents are the IFT reduction, wettability alteration, and rock dissolution. Based on this work, injecting chelating agent solutions at low pH can lead to involve additional recovery mechanisms due to the CO2 generation, the additional mechanisms are hydrocarbon swelling, viscosity and density reduction, and oil vaporization.

Laboratory Investigation Targets EOR Techniques for Organic-Rich Shales

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2890074, “Laboratory Investigation of EOR Techniques for Organic-Rich Shales in the Permian Basin,” by Shunhua Liu, SPE, Vinay Sahni, and Jiasen Tan, SPE, Occidental Oil and Gas, and Derek Beckett and Tuan Vo, CoreLab, prepared for presentation at the 2018 Unconventional Resources Technology Conference, Houston, 23–25 July. The paper has not been peer reviewed. Commercial production from light oil, organic-rich shales in the Permian Basin has largely come from a solution-gas-drive recovery mechanism as a result of horizontal drilling and multistage hydraulic fracturing. These onshore, capital-intensive developments feature steep production declines and low expected ultimate recoveries. This paper involved laboratory experiments introducing miscible gases into core samples to investigate enhanced oil recovery (EOR) mechanisms for Permian Basin shales to provide information to design field tests for a huff ’n’ puff (HNP) recovery process. Introduction The average recovery factor in the un-conventional resources is typically less than 10% with very steep decline rates, indicating enormous potential for EOR. In recent years, research efforts and field pilots of unconventional EOR have targeted the Bakken and Eagle Ford shales. Most focused on miscible-gas (either CO2 or produced gas) injection, while others investigated water-based chemical injection. This paper provides EOR fluid and core analyses in Permian Basin organic-rich shale, an unconventional hydrocarbon growth play with different geological, rock, and fluid properties from those of the Bakken and Eagle Ford plays. The experimental results from this paper were used to calibrate the operator’s unconventional EOR reservoir simulation and field pilot design. Fluid Experiments Fluid properties such as equation-of-state (EOS) and minimum miscibility pressure (MMP) are extremely important because they are the fundamental designing parameters for any gas EOR project. In this study, oil and gas samples were collected in the well from perforations inside the Wolfcamp formation of the Permian organic-rich shale. A gas/oil ratio (GOR) of 1230 scf/bbl was chosen to recombine the separator oil and gas on the basis of observed solution GOR values before any increase caused by the flowing bottomhole pressure falling below the bubblepoint pressure. The pressure/volume/ temperature (PVT) laboratory-testing program consisted of a constant-composition-expansion (CCE) test and a series of swelling tests with CO2. Using the recombined reservoir fluid (with a GOR of 1230 scf/bbl), a CCE test was performed at the reservoir temperature of 162°F to measure the bubblepoint pressure, single-phase oil density, and compressibility. The swelling test results were performed to tune an EOS to be used to calculate oil properties with increasing CO2 concentration during a CO2 flood. EOS Modeling An EOS model was generated to match the CCE data, viscosity data, and CO2 swelling-test data. To use this EOS for CO2 reservoir simulation, the reported system components were grouped, but the CO2 component was left ungrouped. Otherwise, it would be grouped with component C2. The minor component N2 was grouped with C1. All C4s and C5 were grouped together, as were the C6s. The C7+ components were divided into three pseudocomponents.

An Evaluation of Rock Integrity and Fault Reactivation in the Cap Rock and Reservoir Rock Due to Pressure Variations

Cap rocks are dams which can prevent the upward movement of hydrocarbons. They have disparities and weaknesses including discontinuities, crushed areas, and faults. Gas injection is an effective mechanism for oil recovery and pore pressure. With increasing pore pressure, normal stress is reduced, and the integrity of impermeable boundaries (cap rock, fault, etc.) becomes instable. A successful strategy for reservoir development is the inevitable necessity of conducting geomechanical studies and modeling the reservoir. The construction of a comprehensive geomechanical model, including the stress state is a function of depth (direction and amount), physical properties of the reservoir rock and its formations (rock resistance and elastic moduli), pore pressure estimation, and description and distribution of fractures and faults. In this work, analytical and numerical methods have been used in geomechanical modeling, and the data used for modeling and petrophysical information are downhole tests. The geomechanical modeling of gas injection into the reservoir and, simultaneously, the operation of Asmari reservoir and Marun oilfield cap rock in the southwest of Iran were carried out. The threshold of reactivating faults and the critical pressure of induced fracture were calculated, and the results were presented as analytical and numerical models. Moreover, in addition to analyzing the stress field at depths, the resistance parameters of the formations were determined. The results showed that the most changes and instabilities were around the wellheads, fractures, and the edges of the field.

New insights into flow physics in the EOR process based on 2.5D reservoir micromodels

In this paper, a new fabrication method was reported for establishment of a 2.5D reservoir micromodel, which incorporated 3D geometry of porous media and visualization of 2D microfluidic chips. Flow physics such as imbibition, rison and rheon were visualized in the new 2.5D reservoir micromodel through water flooding experiments in water-wet and oil-wet 2.5D reservoir micromodels. Corresponding results demonstrated the strong capacity of the presented 2.5D reservoir micromodel to mimic the real 3D porous media. Besides, four theoretical patterns concerning residual oil distributions were obtained based on water flooding, surfactant flooding and polymer flooding experiments. Furthermore, imbibition of a Winsor I type surfactant system was investigated, accompanied by explanation and visualization of two major enhanced oil recovery (EOR) mechanisms, namely microemulsion imbibition and residual oil solubilization, which confirmed the assumptions made based on core imbibition experiments.

Sustainable production of hydrocarbon fields guided by full-cycle exergy analysis

To mitigate the negative impacts of hydrocarbon fuels on climate change complementary decision tools should be considered when selecting or evaluating the performance of a certain production scheme. The exergy analysis can give valuable information on the management of the oil and gas reservoirs. It can also be used to calculate the CO2 footprint of the different oil recovery mechanisms. We contend that the concept of exergy recovery factor can be used as a powerful sustainability indicator in the production of the hydrocarbon fields. The exergy-zero recovery factor is determined by considering exergy balance of full cycle of hydrocarbon-production systems and defines boundaries beyond which production of hydrocarbons is no longer sustainable. An example of the exergy analysis is presented in the paper.

Prospect of heat-treat of the reservoir for the active mechanism of oil recovery, due to the study of the geochemical composition of terrigenous rocks of the section of Karkali, South-East of Tatarstan

The present paper shows the thermal features of the treatment on the reservoir, geochemistry of sediments, and intensity of chemical weathering of terrigenous rocks of the Ufimian-Kazanian natural reservoir of the section of Karkali in the basin of the r. Sheshma and r. Inesh, to predict the efficiency forecast of the application of heat-treat at the object and decipher the genesis of sedimentary formations in the area. Changes in the main elements in rocks are represented in the variation diagram.