Successful Enhanced Oil Recovery Research Articles

Application of power-law committee machine to combine five machine learning algorithms for enhanced oil recovery screening

One of the main challenges in screening of enhanced oil recovery (EOR) techniques is the class imbalance problem, where the number of different EOR techniques is not equal. This problem hinders the generalization of the data-driven methods used to predict suitable EOR techniques for candidate reservoirs. The main purpose of this paper is to propose a novel approach to overcome the above challenge by taking advantage of the Power-Law Committee Machine (PLCM) technique optimized by Particle Swam Optimization (PSO) to combine the output of five cutting-edge machine learning methods with different types of learning algorithms. The PLCM method has not been used in previous studies for EOR screening. The machine learning models include the Artificial Neural Network (ANN), CatBoost, Random Forest (RF), K-Nearest Neighbors (KNN), and Support Vector Machine (SVM). The CatBoost is used for the first time in this work for screening of EOR methods. The role of the PSO is to find the optimal values for the coefficients and exponents of the power-law model. In this study, a bigger dataset than those in previous studies, including 2563 successful worldwide EOR experiences, was gathered. A bigger dataset improves the generalization of the data-driven methods and prevents overfitting. The hyperparameters of the individual machine-learning models were tuned using the fivefold cross-validation technique. The results showed that all the individual methods could predict the suitable EOR method for unseen cases with an average score of 0.868. Among the machine learning models, the KNN and SVM had the highest scores with a value of 0.894 and 0.892, respectively. Nonetheless, after combining the output of the models using the PLCM method, the score of the predictions improved to 0.963, which was a substantial increase. Finally, a feature importance analysis was conducted to find out the most influential parameters on the output. The novelty of this work is having shown the ability of the PLCM technique to construct an accurate model to overcome the class-imbalance issue in EOR screening by utilizing different types of data-driven models. According to feature importance analysis, oil gravity and formation porosity were recognized as the most influential parameters on EOR screening.

A new approach based on VIKOR and Monte-Carlo algorithms for determining the most efficient enhanced oil recovery methods: EOR screening

Most of oil reservoirs in the world have faced decrease in production and they are in the second half of their life cycle. Therefore, tertiary and enhanced oil recovery (EOR) techniques are needed for continuous production from these reservoirs. As choosing the most appropriate EOR methods for a reservoir is a challenging task for reservoir engineers, screening of EOR approaches is of high importance before any full field simulation and experiments. Enhanced oil recovery screening is a multiple criteria decision-making (MCDM) problem and hence, a systematic statistical algorithm based on MCDM can be used for this purpose. In this study, for the first time, a new EOR screening method is proposed by using VIKOR and Monte-Carlo algorithms. The approach used a large database of successful EOR projects around the world and was applied to 12 various EOR methods including a wide range of conditions and properties. Pre-processing was performed on the gathered database and then based on reservoir engineering analyses and using a pairwise comparison matrix, initial weights were considered for the parameters in each EOR method. Afterward, these weights were used in the proposed VIKOR MCDM calculation algorithm and the corresponding numerical values of EOR techniques for each reservoir were obtained. Finally, the EOR method with the highest corresponding value was selected as the most suitable method. Results demonstrated that by using the presented approach, a high classification accuracy of 98% was obtained for different cases, which shows the proficiency and robustness of the developed screening algorithm. In addition, the reliability of the developed method was validated using data obtained from 11 oil reservoirs in the southwest of Iran. Also, the results were compared with the results of previous studies and they were in a very good match. The developed approach is less expensive and faster than full field simulation method and can be used as an efficient EOR screening approach for reservoirs with different properties in the world.

Surface functionalized Fe3O4‐polyacrylamide dispersion for improved oil recovery at harsh conditions

AbstractWith the growing demand for energy supply and the natural decline of oil reservoirs, the development of new enhanced oil recovery (EOR) techniques become more and more critical. Polymer flooding EOR is one of the most successful chemical EOR methods but suffers many drawbacks at high temperatures and high salinity (HT‐HS) conditions. Superparamagnetic nanoparticles (NPs) have been recently investigated for subsurface applications, including in EOR, due to their unique physicochemical properties. Their applicability under harsh reservoir conditions, however, is yet to be examined. In this work, a novel approach is developed to synthesize superparamagnetic Fe3O4 (NPs) with unique surface functionalization (SMag‐NPs) and to form stable polyacrylamide (PAM) dispersions (SMag‐NPs‐PAM). Both stability and core flooding experiment results demonstrate the promising future of the new dispersion. The SMag‐NPs‐PAM dispersion is not only stable at HT‐HS conditions, but also show excellent EOR capability at HT‐HS by recovering, 61.72% of the initial oil quantity, which is significantly higher than those from conventinal NPs‐PAM disperison and pure PAM fluid. These findings show the promising application potential of SMag‐NPs‐PAM for improving oil recovery in challenging HT‐HS reservoir conditions.

Modeling interfacial tension of surfactant–hydrocarbon systems using robust tree-based machine learning algorithms

Interfacial tension (IFT) between surfactants and hydrocarbon is one of the important parameters in petroleum engineering to have a successful enhanced oil recovery (EOR) operation. Measuring IFT in the laboratory is time-consuming and costly. Since, the accurate estimation of IFT is of paramount significance, modeling with advanced intelligent techniques has been used as a proper alternative in recent years. In this study, the IFT values between surfactants and hydrocarbon were predicted using tree-based machine learning algorithms. Decision tree (DT), extra trees (ET), and gradient boosted regression trees (GBRT) were used to predict this parameter. For this purpose, 390 experimental data collected from previous studies were used to implement intelligent models. Temperature, normal alkane molecular weight, surfactant concentration, hydrophilic–lipophilic balance (HLB), and phase inversion temperature (PIT) were selected as inputs of models and independent variables. Also, the IFT between the surfactant solution and normal alkanes was selected as the output of the models and the dependent variable. Moreover, the implemented models were evaluated using statistical analyses and applied graphical methods. The results showed that DT, ET, and GBRT could predict the data with average absolute relative error values of 4.12%, 3.52%, and 2.71%, respectively. The R-squared of all implementation models is higher than 0.98, and for the best model, GBRT, it is 0.9939. Furthermore, sensitivity analysis using the Pearson approach was utilized to detect correlation coefficients of the input parameters. Based on this technique, the results of sensitivity analysis demonstrated that PIT, surfactant concentration, and HLB had the greatest effect on IFT, respectively. Finally, GBRT was statistically credited by the Leverage approach.

Investigating Effects of Chelating Agents on Viscoelastic Surfactant Flooding at the Pore Scale Using Micromodels

Viscoelastic surfactants (VES) have proven their suitability for enhanced oil recovery (EOR) because they increase the viscosity and decrease the interfacial tension (IFT). In this work, we are proposing chelating agents to suppress the effect of salinity and maintain the required value to build the viscosity to optimize the amount of VES needed for a successful EOR job. Two different VES concentrations were investigated, 0.5 and 1.25 wt %. The chelating agents were diethylenetriaminepentaacetic acid (DTPA) and glutamic acid diacetic acid (GLDA), with different chelating agent concentrations ranging from 2 to 8% for each VES concentration. Rheology results showed that, for DTPA, the highest viscosity at the working shear rate of 1 s–1 is 717 cP achieved by 6% DTPA with 1.25% VES. While for GLDA, the highest viscosity at the working shear rate is 738 cP achieved by 8% GLDA with 1.25% VES. On the other hand, the IFT results for GLDA showed the lowest value of 0.0022 mN/m at 4% GLDA with 1.25% VES, and for DTPA, the lowest value was 0.0068 mN/m at 8% DTPA with 1.25% VES. The microfluidic recovery test was done for the selected best performance in IFT and rheology for each chelating agent with the pure VES. The ultimate recovery from 4% GLDA with 1.25% VES is 56% out of the original oil in place, while 43% using 8% DTPA with 1.25% VES. The pure VES at 1.25% gave 48% ultimate recovery. The chelating agent proved to be successful in suppressing the effect of salinity in reducing the IFT. Therefore, normal seawater without sweetening can be used with VES and GLDA and achieve promising recovery.

Improvement of supercritical carbon dioxide foam performance for EOR in sandstone reservoirs: An experimental and optimization study

Carbon capture is a way of reducing CO2 emissions by capturing and storing CO2 in geological reservoirs, deep saline aquifers, or using it for enhanced oil recovery (EOR). EOR using CO2 is currently one of the most successful EOR techniques. Unfortunately, gas injection techniques suffer from high gas mobility and gravity override, which decrease the macroscopic sweep efficiency and ultimately the oil recovery. Foams may tackle these issues by decreasing gas mobility and gravity override; however, CO2 generates weak foam at its critical conditions, and most reservoirs exist at high pressures and temperatures that exceed CO2 critical conditions. In these conditions, these issues may be tackled by the partial replacement of CO2 with nitrogen, as mixtures of CO2 and N2 can produce strong foam compared to the weak foam generated by CO2 alone. Different core flooding experiments were conducted to investigate the effect of changing the CO2/N2 ratio, injection rate, and foam quality on the performance of the mixed foam. The results show that the foam quality, injection rate, and CO2/N2 ratio must be optimized for enhanced oil recovery. It was observed that increasing N2 content above 20% improved the foam properties; however, it did not result in higher recovery. In addition, decreasing N2 content below 10% did not help the recovery. The optimized foam quality appears to be approximately 80% with a CO2/N2 ratio of 4:1 and 0.5 cc/min injection rate to obtain the highest oil recovery. This study provides an effective and simple solution for improving and optimizing the parameters for mixed foam injection under reservoir conditions, which can produce more oil and store significant quantities of CO2 underground.

Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

This contribution introduces a new hybrid enhanced oil recovery (EOR) method which combines smart water-assisted foam (SWAF) flooding, known as the SWAF process. The concept of applying SWAF flooding in carbonate reservoirs is a novel approach previously unexplored in the literature. The synergy effect of the SWAF technique has the potential to mitigate a number of limitations related to individual (i.e., conventional water injection and foam flooding) methods encountered in carbonates. In general, carbonate rocks are characterized by a mixed-wet to oil-wet wettability state, which contributes to poor oil recovery. Hence, the smart water solution has been designed to produce a dual-improvement effect of altering carbonate rock wettability towards more water-wet, which preconditions the reservoir and augments the stability of the foam lamellae, which has for some conditions more favorable relative permeability behavior. Then the smart water solution is combined with surfactant (surfactant aqueous solution or SAS) and gas injection produces a synergy effect, which leads to more wettability alteration, and interfacial tension (IFT) reduction, and thus improves the oil recovery. Accordingly, to determine the optimal conditions of smart water solution with an optimal SAS, we conducted a series of experimental laboratory studies. The experimental design is divided into three main steps. At first, the screening process is required so that the candidates can be narrowed down for our designed smart water using the contact angle tests that employ calcite plate (i.e., Indiana limestone or ILS) as the first filter. Following this, the optimum smart water solutions candidates are blended with different types of cationic and anionic surfactants to create optimum SAS formulations. Subsequently, a second screening process is performed with the aim to narrow down the SAS candidates with varying types of gases (i.e., carbon dioxide, CO2 and nitrogen, N2) via the aqueous stability test (AST), foamability test (FT), and foam stability test (FST). We employed the state-of-the-art R5 parameter tests for rapid and accurate results in place of the conventional foam half-life method. The most effective combination of SAS and gas candidates are endorsed for the core-flooding experiments. In this work, two types of crude oils (Type A and B) with different total acid and base numbers (TAN and TBN). Results showed that the greatest wettability changes occurred for SW (MgCl2) solution at 3500 (ppm) for both crude oil types. This demonstrates the efficacy of our designed SW in the wettability alteration of carbonates, which is also supported by the zeta-potential measurements. The concentrations of both SW (MgCl2) and CTAB-based surfactants considerably affect the stability of the SAS (i.e., up to 90% foam stability). However when in the presence of crude oil, for the same SAS solution, the foam stability is reduced from 90% to 80%, which indicates the negative effect of crude oil on foam stability. Moreover, the core floods results showed that the MgCl2-foam injection mixture (MgCl2 + CTAB + AOS + N2) provided the highest residual oil recovery factor of SWAF process of 92% cumulative recovery of original oil in core (OIIC). This showcases the effectiveness of our proposed SWAF technique in oil recovery from carbonate reservoirs. Additionally, changing the large slug of 5 PVs to a small slug of 2 PVs of smart water solution was more effective in producing higher OIIC recovery and in reducing the fluid circulation costs (i.e., thereby, lowering CO2 footprint), making the SWAF process environmentally benign. Thus, it is expected that under optimum conditions (SW solution and SAS), the novel SWAF process can be a potentially successful hybrid EOR method for carbonate reservoirs, having both economic and environmental benefits.

Mechanisms of Miscible and Immiscible scCO‌2 Displacement Efficiency: Analytical Evaluation of Experimental conditions

CO2 injection has proven to be one of the most successful EOR (Enhanced Oil Recovery) methods, as compared with other injection gases CO2 miscibility with oil is easier to achieve. During gas injection into reservoirs, oil might be bypassed on either a micro- or macroscopic scale because of different types of heterogeneities. In this work, the performance of first-contact-miscible (FCM) and immiscible (IM) CO2 injections were investigated experimentally using outcrop sandstone core samples. Decane was also used as the hydrocarbon phase as it has a relatively low minimum miscibility pressure (MMP) with CO2 (12.4 MPa). Core flooding experiments were conducted at two pressures of 17.2 MPa and 9.6 MPa and the common temperature of 343 K. Furthermore, analytical calculations of dimensionless numbers are used to study the dominant forces and mechanisms which are correlated with the results of the core flooding experiments. The impacts of gravity, swelling and vaporization on the end results were inferred from the oil recoveries, variations in the pore pressure and dimensional analysis. For CO2 injection in homogeneous core samples, a maximum recovery of 93.5% and 76% was achieved for the FCM and IM displacements, respectively. The higher recovery results of FCM is attributed to the vanishing capillary pressure between displacing and displaced phases. Dimensional analysis showed that the flow is at the capillary-gravity equilibrium at immiscible conditions, while there is dominance of gravity-viscous forces at miscible conditions.

Wettability Alteration of Carbonate Reservoirs Using Imidazolium-Based Ionic Liquids.

The wettability of the rock–oil–brine system plays a major role in enhanced oil recovery (EOR), particularly in the harsh environments of carbonate reservoirs. Most of these formations were identified as strongly oil-wet, and sometimes a few are intermediate-wet. Hence, it is highly necessary to alter such an oil-wet rock matrix to a water-wet matrix in order to improve the oil production. Consequently, it is important to investigate the wetting and wettability dynamics of the rock–oil–brine system for both static and dynamic cases. Thus, in this study, we investigated the effect of four various imidazolium-based ionic liquids (ILs) on the wettability alteration of the rock–oil–brine system by measuring the contact angles. Herein, we have screened various parameters, such as the rock type (brine-saturated and oil-saturated), type of IL, IL concentrations (0–1000 ppm), temperature (25–100 °C), pressure (14.7–3000 psi), and salinity (TDS: 67,500–240,000 ppm). The measurement of the static contact angle was found to be altered from 85.5 to 49.4° with the addition of 500 ppm of ILs in the brine-saturated sample, and for the oil-saturated sample, it was altered from 150.9 to 99.2°. This indicates that ILs have a huge influence on shifting the rock wettability more toward water-wet, which in fact is more favorable for the EOR operation. Later, we studied the dynamic wettability alteration of the rock–oil–brine system, in which we measured the transient changes in the contact angle while displacing the brine with an IL solution in situ. It was observed that the oil droplet deformed slightly and was dragged toward the base fluid (IL solution) with time, and this implied the changes in the contact angle from 150.9 to 118.5° with 500 ppm of IL, [C12mim]+[Cl]−. Though this has a relatively lesser impact as compared to the static experiment, this could be considered to be more realistic to correlate with coreflood experiments. Further, to understand the mechanism of this wettability dynamics, we have measured the oil–water interfacial tension and the ζ-potential of various systems and observed that their results were backed up by our wettability studies. Overall, the combined forces of interfacial tension reduction, capillary alterations, and IL interactions with rocks and oils have caused this wettability alteration. Conclusively, the results of various experiments that are performed in this study are more meaningful, and it is evident that ILs favor the successful EOR implications.

Effects of nanocomposite polymer flooding on Egyptian crude oil recovery

In this work, a laboratory study of enhanced oil recovery (EOR) was carried out using Egyptian crude oil of 37°API extracted from a reservoir in the Western Desert to identify the optimum conditions for the application of locally prepared nanocomposite polymer flooding under harsh reservoir condition. In contrary to the other studies, we tested the ability of nanocomposite polymer where nanoparticles are involved in the polymer matrix during polymerization process. Measurements of viscosity and shear rate of several solutions were taken. Displacement runs were conducted at different conditions of nanocomposite polymer salinities (10,000, 20,000, 30,000, 40,000, 50,000, 60,000 and 65,000 ppm), concentrations (1, 1.5, 2, 2.5, 3, 3.5 and 4 g/L) and slug sizes (0.2, 0.4, 0.6 and 0.8 PV). A linear sandpack (length of 62.5 cm and diameter of 2″) was prepared and wrapped with thermal jacket to simulate several reservoir temperatures. It was filled by selected sand size to produce linear sandpack model with reasonable porosity (22%) and permeability (129–157 mD) values. The model was used to perform several displacements runs for waterflooding and nanocomposite polymer flooding. The results of the flood runs are analyzed using the water–oil relative permeability curves. The measurements of the solutions properties showed that the critical concentration of the used nanocomposite polymer in the solution is 2 g/L. Also, it was observed that the used nanocomposite polymer solution could withstand a salinity of 60,000 ppm. As a result of the flooding, it was found that the optimum economical slug size of the used nanocomposite polymer is 0.4 PV at reservoir temperature of 40 °C. The results indicated also that the used nanocomposite polymer could withstand a reservoir temperature of 90 °C. The water–oil relative permeability curves showed an enhancement of oil relative permeability and a decrease in the water relative permeability using nanocomposite polymer over waterflooding. The cost of the used nanocomposite polymer with a concentration of 2 g/L and slug size of 0.4 PV is 0.626 $ for each barrel of the incremental oil recovery. Based on the results of this work, it is clear that involving nanoparticles such as silica in the polymer matrix composition improves its properties, thermal and salinity resistivity. Such study is an original contribution to carry out successful nanocomposite polymer EOR projects.

Efficient Oil Removal of Polymer Flooding Produced Sewerage Using Super-Hydrophobic Mesh Filtration Method

During the past 20 years, polymer flooding has become a successful enhanced oil recovery (EOR) technique for mature reservoirs with high water cut and recovery percent around the world. However, the high bulk viscosity of polymer solutions could slow down the separation rate of the crude oil emulsion and make it difficult to treat the produced fluid. Consequently, the efficient removal of oil from the polymer flooding produced sewerage has still drawn significant concern. In this research, a high flux super-hydrophobic copper mesh was prepared using two-stage processes to treat the sewerage from polymer flooding. The surface of the super-hydrophobic mesh was characterized using various techniques including scanning electron microscope (SEM), OCA 20-contact angle goniometer, etc. Accordingly, the static contact angle of the super-hydrophobic copper mesh reached up to 165°. Moreover, the performances of the mesh were systematically evaluated under different internal and external factors such as oil to water volume ratio, polymer concentration, shear rate, and pH. The corresponding configuration and separation mechanisms are further explained in detail. The prepared superhydrophobic mesh can be a potential candidate for sewerage with both a polymer solution and crude oil.

Screening Reservoir Candidates for Enhanced Oil Recovery (EOR) in Angolan Offshore Projects

The neuro-fuzzy (NF) approach presented in this work is based on five (5) layered feedforward backpropagation algorithm applied for technical screening of enhanced oil recovery (EOR) methods. Associated reservoir rock-fluid oilfield data from successful EOR projects were used as input and predicted output in the training and validation processes, respectively. The developed model was then tested by using data set from Block B of an Angolan oilfield. The results of the sensitivity analysis between the Mamdani and the Takagi-Sugeno-Kang (TSK) approach incorporated in the algorithm has shown the robustness of the TSK ANFIS (Adaptive Neuro-Fuzzy Inference System) approach in comparison to the other approach for the prediction of a suitable EOR technique. The simulation test results showed that the model presented in this study can be used for technical selection of suitable EOR techniques. Within the area investigated (Block B, Angola) polymer, hydrocarbon gas, and combustion were identified as the suitable techniques for EOR.

The Investigation of Silica Nanoparticles-CO2 Foam Stability for Enhancing Oil Recovery Purpose

Carbon dioxide (CO2) gas injection is one of the most successful Enhanced Oil Recovery (EOR) methods. But the main problem that occurs in immiscible CO2 injection is the poor volumetric sweep efficiency which causes large quantities of the oil to be retained in pore spaces of reservoir. Although this problem can be improved through the injection of surfactant with CO2 gas where the surfactant will stabilize CO2 foam, this method still has some weaknesses due to foam size issue, surfactants compatibility problems with rocks and reservoir fluids and are less effective at high brine salinity and reservoir temperature such as typical oil reservoirs in Indonesia. This research aims to examine the stability of the foams/emulsions, compatibility and phase behavior of suspensions generated by hydrophobic silica nanoparticles on various salinity of formation water as well as to determine its effect on the mobility ratio parameter, which correlate indirectly with macroscopic sweep efficiency and oil recovery factor. This research utilizes density, static foam, and viscosity test which was carried out on various concentrations of silica nanoparticles, brine salinity and phase volume ratio to obtain a stable foam/emulsion design. The results showed that silica nanoparticles can increase the viscosity of displacing fluid by generating emulsions or foams so that it can reduce the mobility ratio toward favorable mobility, while the level of stability of the emulsion or foam of the silica nanoparticles suspension is strongly influenced by concentration, salinity and phase volume ratio. The high resistance factor of the emulsions/foams generated by silica nanoparticles will promote better potential of these particles in producing more oil.

Low Salinity Polymer Flooding: Effect on Polymer Rheology, Injectivity, Retention, and Oil Recovery Efficiency

Synergism between different enhanced oil recovery (EOR) methods has always been a subject of paramount interest for oil industries as it led to the development of many successful EOR methods in the...

Wettability Alteration in Carbonate Reservoirs by Carbon Nanofluids

Wetting phenomena play a significant role in oil recovery from complex carbonate reservoirs under harsh conditions. The potential to being able to alter the rock wettability from oil-wet to water- or neutral-wet is often considered the pre-requisite to a successful Enhanced Oil Recovery (EOR) process. Hence, there arises the importance of understanding the (static) wetting and (dynamic) wettability alteration of the reservoir rock when the rock comes in contact with injected modified brines, oilfield chemicals, and/or nanofluids. In this study, we investigate the effect of three Carbon nanodots in high salinity brines with and without surfactant on static wetting and dynamic wettability alteration of carbonate reservoirs. Outcrop Indiana limestone and reservoir crude oil samples were used in these tests. The contact angle of the rock-oil-brine system is measured as a function of the nanodot concentration, saturating fluid in the rock matrix and aging, surfactant concentration, temperature, pressure, and brine salinity. The upper limits for the values for temperature, pressure, and salinity are set to be representative of the Saudi Arabian harsh reservoir conditions. The use of Carbon nanofluids demonstrated a clear shift in both static and dynamic measurements towards a more favorable water-wet condition for EOR. Statically, the contact angle of an oil-saturated carbonate rock exhibited a change from a strongly oil-wet condition to slightly water wet (with more than 50 % drop in the contact angle value) in 200 ppm (0.02 wt/v%) solution of carbon nanodot (CND) in seawater (SW) over 24 hours. Dynamically, a smaller but still remarkable change (a shift in the order of 20 %) in the contact angle is noted for a sister rock sample over the same period when a solution at the same concentration of CND in SW is introduced to replace the SW base fluid. Nanofluid spreading experiments on oil-coated glass slides supported our dynamic wettability studies. The spreading efficiency of the Carbon nanofluid was analyzed using optical and confocal microscopy with a clear and remarkable oil dislodging effect. Zeta potential measurements of the different systems were made to aid in the interpretations. The combined mechanistic actions of the various factors, including reservoir environment, disjoining pressure, interfacial tension, capillary pressure alterations and nanodots interactions with the oil/water interface, contributed to this change in wettability. Our study supports a strong and favorable EOR impact of CND as an effective and economically viable additive to waterflood operations in carbonate reservoirs.

Experimental and numerical study of surfactant solution spontaneous imbibition in shale oil reservoirs

Abstract Experimental and simulation studies have thus far demonstrated that surfactant-based Enhanced Oil Recovery (EOR) is a feasible method to improve recoveries from initially oil-wet or mixed-wet Unconventional Oil Reservoirs (UORs). The summarized principle is that surfactant triggers spontaneous imbibition by either Interfacial Tension (IFT) reduction or wettability alteration. Several related studies have focused on the effectiveness of different surfactants or their combinations on the final oil recoveries from selected rock/fluid samples. However, the relative significance of each mechanism is not clear yet. In this work, by following both experimental and numerical simulation approach, we attempt to separately investigate the effect of IFT reduction and wettability alteration on the performance of surfactant based EOR in UORs. Further, the relative importance of each function is addressed while determining the dominating mechanism. Both experimental and simulation results showed that achieving a water-wet status is crucial for higher oil recoveries in shale and tight reservoirs. The effects of IFT reduction could be detrimental to the recovery once the wettability is altered to water-wet due to a lower capillary driven force. Therefore, to design a successful surfactant EOR case in UORs, a surfactant must have the capability of altering the wetness to a more water-wet status. Meanwhile, maintaining a relatively high IFT is also significant. Results from this paper will provide a general suggestion on surfactant selection to enhance oil recovery in UORs.

Screening of enhanced oil recovery techniques for Iranian oil reservoirs using TOPSIS algorithm

In recent decades, parallel to amazing advances in the development of data mining methods, screening, as the first step of any enhanced oil recovery (EOR) project, has become an interesting subject of data mining methods. Screening of EOR methods is a multi-criteria decision making process, and the Multi-Criteria Decision Making (MCDM) method as a systematic statistical method, can be applied in this regard. In this paper, the Technique for Order of Preference by Similarity to Ideal Solution (TOPSIS) as one of the methods under the MCDM category was used to screen 65 Iranian oil reservoirs. The screening method was employed for 10 different EOR techniques using a wide range of properties and conditions. The analysis used a database including more than 800 successful EOR projects across the world and for 9 ideal reservoir parameter values. The relative importance of the reservoir parameters was determined based on the Analytic Hierarchy Process (AHP) at nine importance levels. The findings showed that among the considered screening parameters, to determine the best EOR technique, lithology of the reservoir is the most influencing parameter. Additionally, almost 74% of the oil reservoirs under study, as a first priority, were eligible for CO2 injection, either miscible or immiscible. Thermal methods were in the second stage of ranking. The first and second candidate choice for onshore oil reservoirs was immiscible CO2 and hydrocarbon gas injection, respectively. For offshore reservoirs, CO2 injection and steam flooding were the best choices. Also, miscible N2 injection was the least important technique, due to the huge difference of considered reservoir pressure with minimum miscibility pressure (MMP) of N2 injection. The proposed technique is computationally fast and less expensive than field simulation studies for ranking EOR projects for any oil reservoir in the world.

Molecular Simulation Study on the Volume Swelling and the Viscosity Reduction of n-Alkane/CO2 Systems

Carbon dioxide (CO2) injection is a successful enhanced oil recovery (EOR) technology that is being widely applied in North American oil fields. Studies have suggested CO2-based EOR is technically ...

CO2 Sequestration-EOR in a Tight Oil Reservoir: Estimation of Dynamic CO2 Storage Capacity Using a Two-Stage Well Test

Evaluation of an accurate CO2 dynamic storage capacity, ultimate recycled CO2 and enhanced oil recovery (EOR) are key factors for a successful CO2 EOR project. The Yanchang Petroleum Company (YP)’s low permeability oil field is located at Ordos Basin - China with a very short and inefficient primary and secondary oil recovery and, therefore, YP proposed CO2 EOR as a potential tertiary oil recovery approach. In this work, the Wuqi reservoir in the Yanchang field is selected to evaluate the feasibility of full-field CO2 sequestration-EOR. The Wuqi reservoir has been in production for over a decade with historical data that can be used for a history matching process. To acquire essential dynamic data for evaluation of the CO2 injectivity/dynamic storage capacity, a specific two-stage pilot well test is proposed to inject first water and then CO2. It will provide relatively accurate calculated permeability for water (test phase 1) and CO2 (test phase 2) at the injection well. Also, the test will qualitatively estimate the location of water and CO2 fronts in the reservoir over time. Using two monitoring wells simultaneously, significantly increases the radius of investigation (ROI) that can be achieved for a given injection scenario and will also describe directional heterogeneity in the reservoir. When informed by the pilot test data, the model can be used to estimate the CO2 injection rate, ultimate cumulative CO2 injection and oil production and CO2 injection well numbers over 15 years of CO2 sequestration-EOR, which can be utilised for further techno-economic analysis of the project.

Polymer Flow in Porous Media: Relevance to Enhanced Oil Recovery

Polymer flooding is one of the most successful chemical EOR (enhanced oil recovery) methods, and is primarily implemented to accelerate oil production by sweep improvement. However, additional benefits have extended the utility of polymer flooding. During the last decade, it has been evaluated for use in an increasing number of fields, both offshore and onshore. This is a consequence of (1) improved polymer properties, which extend their use to HTHS (high temperature high salinity) conditions and (2) increased understanding of flow mechanisms such as those for heavy oilmobilization. A key requirement for studying polymer performance is the control and prediction of in-situ porous medium rheology. The first part of this paper reviews recent developments in polymer flow in porous medium, with a focus on polymer in-situ rheology and injectivity. The second part of this paper reports polymer flow experiments conducted using the most widely applied polymer for EOR processes, HPAM (partially hydrolyzed polyacrylamide). The experiments addressed highrate, near-wellbore behavior (radial flow), reservoir rate steady-state flow (linear flow) and the differences observed in terms of flow conditions. In addition, the impact of oil on polymer rheology was investigated and compared to single-phase polymer flow in Bentheimer sandstone rock material. Results show that the presence of oil leads to a reduction in apparent viscosity.