Incremental Oil Recovery Factor Research Articles

Evaluation of the coupled impact of silicon oxide nanoparticles and low-salinity water on the wettability alteration of Berea sandstones

This study investigated experimentally the coupled effects of hydrophilic SiO2 nanoparticles (NPs) and low-salinity water (LSW) on the wettability of synthetic clay-free Berea sandstone. Capillary pressure, interfacial tension (IFT), contact angle, Zeta potential, and dynamic displacement measurements were performed at various NP mass fractions and brine salinities. The U.S. Bureau of Mines (USBM) index was used to quantify the wettability alteration. Furthermore, the NP stability and retention and the effect of enhanced oil recovery by nanofluid were examined. The results showed that LSW immiscible displacement with NPs altered the wettability toward more water wet. With the decreasing brine salinity and increasing NP mass fraction, the IFT and contact angle decreased. The wettability alteration intensified most as the brine salinity decreased to 4000 mg/L and the NP mass fraction increased to 0.075%. Under these conditions, the resulting incremental oil recovery factor was approximately 13 percentage points. When the brine salinity was 4000 mg/L and the NP mass fraction was 0.025%, the retention of NPs caused the minimum damage to permeability.

Review on Potential Application of Saponin-Based Natural Surfactants for Green Chemical Enhanced Oil Recovery: Perspectives and Progresses

Synthetic chemical surfactants deployed in the petroleum industry to improve oil recovery to meet growing global energy demand are described to have detrimental environmental impacts and are expensive. In recent times, the exploration of saponin-rich plants as a substitute for environmentally threatening synthetic surfactants has garnered significant interest from researchers. Saponin-based natural surfactants (SBNSs) are nontoxic, biodegradable, and possess desirable properties for use in the oil and gas industry. This paper reviews the potential application of saponin-based natural surfactants in enhanced oil recovery processes that coincide with the interests of the United Nations’ Sustainable Development Goal 7 for Affordable and Clean Energy. We reviewed the mechanisms of saponin-based natural surfactants in enhanced oil recovery (EOR), surfactant adsorption, and the recent advances in utilizing saponin-based natural surfactants for EOR purposes. We also provided a comprehensive analysis of the impact of salinity and temperature on the performance of SBNSs. Moreover, the study also presented the economic feasibility and limitations of SBNSs for field enhanced oil recovery applications. We identified that a good number of SBNSs can withstand harsh reservoir conditions, optimize interfacial tension by as high as 95.82% (although not to ultralow levels), and alter rock wettability from hydrophobicity to hydrophilicity, thereby reducing the contact angle by 3.64% to 87.5%. SBNSs also successfully yielded a high incremental oil recovery factor of up to 36% in the postsecondary recovery stage. The advent of techniques, such as alkali incorporation and nanotechnology, support the achievement of ultralow interfacial tension, mitigation of surfactant adsorption, and oil recovery improvement. Future studies can adopt the recommendations outlined in this study to minimize uncertainty in the utilization of SBNSs and enhance their design for “green” chemical enhanced oil recovery applications.

Remaining Oil Distribution Law and Development Potential Analysis after Polymer Flooding Based on Reservoir Architecture in Daqing Oilfield, China.

Polymer flooding has drawn more and more attention in the world for its high incremental oil recovery factor and relative low costs compared with water flooding and other chemically enhanced oil recovery techniques. However, for many oilfields, such as Daqing Oilfield, China, that have already been flooded with polymers, how to further improve recovery remains a big problem. Traditional intralayer, interlayer and plane heterogeneity studies cannot accurately characterize the remaining oil distribution after polymer flooding. To solve this problem, we established a method to quantitatively describe the reservoir's architecture. Then, the architecture elements were dissected hierarchically and the interface of each architecture level in Daqing Oilfield was identified. The distribution pattern and development potential of the remaining oil after polymer flooding under the influence of reservoir architecture was analyzed. The results show that, regarding the sedimentary process from north to south in Daqing Oilfield, the channel becomes narrower, the thickness decreases, the point bar's width increases and the thickness of the meandering river decreases. The braided bar scale becomes larger and the thickness becomes smaller in the braided river. According to the reservoir's architecture, the remaining oil was divided into four categories of plane remaining oil (abandoned channel occlusion type, interfluvial sand body occlusion type, inter-well retention type and well pattern uncontrollable type) and three types of vertical remaining oil (in-layer interlayer occlusion type, rhythm type and gravity type). About 40% of the original oil in place (OOIP) of Daqing Oilfield has not yet been produced, which indicates that there is great potential for development. This study is important for improving oil recovery in polymer-flooded reservoirs.

Laboratory Study of Enhanced Oil Recovery with Used Palm Oil Surfactant Injection

Currently the waste generated from public consumption in Indonesia is very high. One such waste is used palm oil from households and food companies. Utilization of this waste in this research is by recycling waste oil into surfactants which will be used in the Enhanced Oil Recovery (EOR) process. The surfactant concentrations used were 1.3%, 1.5%, 2%, 2.2% and 2.5%. The research began with refining used cooking oil with banana peels for 24 hours. In order to make surfactants, the oil is mixed with KOH and distilled water. Additionaly, brine was made with a salinity of 15,000 ppm. With the interfacial tension test, a solution with an optimum surfactant concentration of 2.2% was obtained. The core flooding test was carried out using waterflooding followed by surfactant flooding at a temperature of 70 oC. From the test results obtained an incremental oil recovery factor of 8.57% and a total oil recovery factor of 47.43%.

Aqueous formate solution for enhanced water imbibition in oil recovery and carbon storage in carbonate reservoirs

This paper presents an experimental study of the injection of aqueous formate solution into oil-wet carbonate porous media at different formate concentrations and acidity levels. The research was motivated by the potential use of aqueous formate solution as a wettability modifier in enhanced oil recovery and/or a carbon carrier in geological carbon storage in carbonate reservoirs. However, the wettability alteration of carbonate rocks by formate has not been tested at elevated concentrations of formate or in any coreflood. The experimental program in this research consists of aqueous stability, wettability alteration, and three dynamic imbibition experiments with fractured carbonate cores with varying formate concentrations up to 30 wt% and initial pH between 6 and 7.With an excess amount of calcite powder, the 20 wt% formate solution in 15000 ppm NaCl brine showed essentially the same pH history as the base NaCl brine, where calcite dissolution caused the solution pH to increase to a stable value near 9. None of the samples studied in this research showed solid precipitation. Material balance of dynamic imbibition data indicated that the imbibition of formate into the matrix was most significant in coreflood #1, in which 30 wt% formate solution was injected into a fractured carbonate core. A large gradient in formate concentration between the fracture and the matrix likely caused the rapid mass transfer. Then, calcite dissolution and the resulting formate species caused wettability alteration to enhance water imbibition, which in turn expelled the oil in the matrix.The incremental oil recovery factor was 9.1 % for 30 wt% formate (pH = 7; coreflood #1), 2.9 % for 5 wt% formate (pH = 7; coreflood #2), and 7.0 % for 5 wt% formate + HCl (pH = 6; coreflood #3). A greater oil recovery factor resulted from a greater concentration of formate and a reduced pH. This is the first time corefloods were performed with aqueous formate solution at elevated concentrations up to 30 wt%.

Improvement of oil recovery factor in tight reservoirs: A laboratory approach based on carbon dioxide enhanced oil recovery methods

Production from unconventional oil reservoirs has always been a critical issue for the oil industry. In this regard, we implemented a set of experimental scenarios containing CO2/N2 cyclic injection, the foams generated by nitrogen and carbon dioxide, cyclic carbon dioxide injection, and a combined effect of carbon dioxide and surfactant enhanced oil recovery methods. As water injection has reached a plateau around two pore volume injection, we continued the tests from two pore volume injection for different scenarios. It was observed that CO2/N2-foam has the highest oil recovery factor of 34.9%; however, CO2-foam, regarding more feasibility than N2, witnessed the highest oil recovery factor after CO2/N2-foam. On the other hand, the incremental oil recovery factor for surfactant flooding, carbonated water flooding, and carbonated water with surfactant flooding is measured at 4.9, 8.5, and 10.6%, respectively.

Experimental and Numerical Investigation on Infilled Vertical Well LASER-Assisted SAGD

In the SAGD process with dual horizontal wells in heterogeneous reservoirs, the injection pressure of steam huff-n-puff by infilled interwell vertical wells is too high, and the heat communication between SAGD wellpairs and infilled wells is too long, which leads to a series of problems. The solvent-assisted vertical well stimulation (LASER) technology is proposed to solve the problems above. The solvent formula was optimized, and its key mechanism was studied by viscosity reduction experiments, multicomponent phase behavior experiments at high temperature and high pressure, and scaled two-dimensional physical experiments. The experimental results show that when adding 10% 2# or 3# solvent oil, the viscosity reduction of crude oil can reach 96.65% and 96.73%, respectively. The HTHP visualized phase behavior experiment results show that the mixture of low flash point solvent oil 2# with high flash point solvent oil 3# (volumetric ratio 3 : 2) has excellent high temperature oil solubility stability and is similar to water vapor phase behavior, so it is determined as the ideal formula. The scaled two-dimensional physical experiment results show that the solvent-assisted vertical well huff-n-puff has the key mechanism of reducing injection pressure and porous flow resistance, expanding the sweep region of injected fluid and accelerating thermal communication. The cycle of huff-n-puff was reduced from 6 to 3, which greatly shortened the thermal communication time. From the scaled physical experiments, the oil rate and the oil recovery of SAGD were improved by 19.86% and 6.3%, respectively. Field-scale numerical simulation was performed, and the production performance compared with SAGD and conventional infilled CSS-SAGD was investigated, which shows that by adding solvent into steam stimulation, 6 cycles were reduced, and the incremental oil recovery factor was 27.3% and 13.2%, respectively. The performance of accelerating thermal communication and production improvement by LASER has been validated by 4 SAGD wellpairs in field practice, and its long-term prediction result shows significant potential in similar heterogeneous SAGD reservoirs.

Study Reviews Recent Polymerflooding Advances in China

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200084, “Recent Advances of Polymerflooding in China,” by Hu Guo and Kaoping Song, China University of Petroleum, and Yuming Wang, Daqing Oilfield Company, et al. The paper has not been peer reviewed. Polymerflooding is one of the more promising chemical enhanced oil recovery (EOR) techniques that features high incremental oil recovery factor, low cost, and wide reservoir applicability. This paper helps clarify ideas regarding polymerflooding implementation based on theory and practice in China. Introduction Laboratory studies aimed at increasing understanding of polymerflooding involve criteria for matching polymer with porous media, the polymer viscoelasticity effect on residual oil saturation (ROS), and displacement efficiency and synthesis of new polymers with better viscosifying capacity compared with typical partially hydrolyzed polyacrylamide (HPAM). The plugging of injectors in many oil fields is becoming increasingly common in many commercial blocks. This problem is especially serious for high-concentration polymer-injection blocks in fields such as Daqing, Xinjiang, and Henan. Understanding this phenomenon involves aligning the polymer and porous-media parameters such as permeability and pore size. Actual reservoir pressure distribution also must be considered. Because modern chemical EOR is based on ultralow interfacial tension (IFT) and minimum mobility ratio theory, the idea of combining the benefits of reducing IFT and increasing displacing-phase viscosity leads to a synthesis of amphiphilic polymers, which have features of both polymers and surfactants. This new type of polymer is sometimes called polymeric surfactant in China.

The Study of Flow Behavior and Performance of Polymer Injection in Homogenous Porous Media Using Etched Micromodel

The implementation of polymer injection on a field scale needs a preliminary laboratory test to analyze the performance and flow behavior of polymer injection in a porous media. Compared to coreflooding method, micromodel provides the visualization of oil displacement mechanism and facilitating a more detailed process description. Understanding the effect of polymer concentration on the incremental of oil recovery factor and its displacement mechanism are essential to know the polymer injection performance with the intention of avoiding failures in the implementation of polymer injection at field scale. We used dry etching technique for the fabrication of acrylic micromodel with homogenous characteristic. In this work, pre-flush (waterflooding) is performed first before doing the polymer injection to determine the incremental oil recovery factor and analyze the effect of polymer concentration on oil recovery factor enhancement in homogenous porous media. They were positioned horizontally then saturated with synthetic brine and light crude oil as the initial condition before starting the injection scenario. The experiment was conducted at room temperature. The entire process of micromodel flooding test was monitored by camera and then for the further analysis was done using Digital Image Analysis (DIA). According to the polymer rheology and aqueous stability test, it can be proven that polymer is a non-newtonian fluid indicated by shear thinning behavior and it can be observed that FP3630S polymer is a good candidate for micromodel flooding test. The micromodel flooding result confirmed that the increasing of polymer concentration will result in higher incremental oil recovery factor. In addition, based on the final condition of the micromodel after the polymer injection process, there is improvement of sweep efficiency due to the front stability resulted by the decreasing of mobility ratio between displacing fluid (polymer solution) and the oil bank.

Enhancing Oil Recovery from Low-Permeability Reservoirs with a Thermoviscosifying Water-Soluble Polymer.

Water-soluble polymers, mainly partially hydrolyzed polyacrylamide (HPAM), have been used in the enhanced oil recovery (EOR) process. However, the poor salt tolerance, weak thermal stability and unsatisfactory injectivity impede its use in low-permeability hostile oil reservoirs. Here, we examined the adaptivity of a thermoviscosifying polymer (TVP) in comparison with HPAM for chemical EOR under simulated conditions (45 °C, 4500 mg/L salinity containing 65 mg/L Ca2+ and Mg2+) of low-permeability oil reservoirs in Daqing Oilfield. The results show that the viscosity of the 0.1% TVP solution can reach 48 mPa·s, six times that of HPAM. After 90 days of thermal aging at 45 °C, the TVP solution had 71% viscosity retention, 18% higher than that of the HPAM solution. While both polymer solutions could smoothly propagate in porous media, with permeability of around 100 milliDarcy, TVP exhibited stronger mobility reduction and permeability reduction than HPAM. After 0.7 pore volume of 0.1% polymer solution was injected, TVP achieved an incremental oil recovery factor of 13.64% after water flooding, 3.54% higher than that of HPAM under identical conditions. All these results demonstrate that TVP has great potential to be used in low-permeability oil reservoirs for chemical EOR.

Flue gas and nitrogen co-injection during cyclic steam stimulation in heavy oil reservoirs: a numerical evaluation

In this study, steam co-injection with flue gas or N2 was numerically reproduced to determine the best gas composition to be deployed in a Colombian heavy crude oil, using a commercial reservoir simulation software. The oil mixture was characterized via EoS parameters, withtuning average errors of 5%. Injection conditions were evaluated with thermal simulations to analyze the response in oil production, allowing to find a deployment strategy having the highest recovery with the lowest gas injection volume. Results agree with experimental observations regarding the starting times for co-injection and help to narrow the uncertainty range where gas and steam co-injection is asuitable recovery technique in heavy oil reservoirs. The study showed that the incremental oil recovery factor can be enhanced, at least, in 40% when optimizing the deployment of steam and flue gas co-injection for the well studied here

Analysis of Factors Affecting Polymer Flooding Based on a Response Surface Method.

Both polymer injection time and injection rate play an important role in the development of an offshore reservoir with a limited service life of the platform. To quantitatively and qualitatively investigate the influence of the formation packing sequence, injection rate, polymer injection timing, and their interaction on the performance of polymer flooding, a numerical reservoir model is simulated in this study based on the properties of offshore reservoir LD in China. Also, the polymer flooding experimental scheme is designed according to the response surface method and single-factor analysis method. Based on numerical simulation and statistical analysis, a regression model is established to predict the incremental oil recovery factor of polymer flooding. The analysis of variance (ANOVA) shows that the regression model fits well with the experimental data. The three factors’ influence capacities on the increased oil recovery factor from large to small are the injection rate, formation rhythm, and injection timing. From the analysis, it is also found that the improved polymer flooding performance can be achieved under an injection rate of 0.07–0.09 PV/a and an injection timing of 30% water cut for positive rhythm formation.

Recent Advances in Polymer Flooding in China: Lessons Learned and Continuing Development

SummaryPolymer flooding is one of the most promising chemical enhanced-oil-recovery (EOR) techniques. It offers a high incremental-oil-recovery factor (IORF), low cost, and wide reservoir applicability. The first large commercial polymer-flooding application began in Daqing Oil Field and remains the largest polymer application in the world. However, encouraged by the success of previous field applications and new findings regarding the viscoelasticity of polymers in the reduction of residual oil saturation (ROS), high-concentration high-molecular-weight (MW) polymer-flooding (HCHMW) field tests have been conducted in many oil fields in China. Although some of these field tests in Daqing are well-documented, subsequent progress has seldom been reported. Moreover, recent references about the latest polymer-flooding applications in China reveal that HCHMW has only a limited application in Daqing. This is not in agreement with previous reports and expectations, especially given that viscoelasticity has been drawing increased attention. This paper explains why HCHMW is not currently widely used. New types of amphiphilic polymers are also field tested in China. Lessons learned from polymer-flooding practices in offshore reservoirs, heavy-oil reservoirs, and conglomerate reservoirs are given to help reduce risks and costs of polymer flooding in the low-oil-price era. EOR techniques in post-polymer-flooding reservoir field tests are also compared. In addition to providing useful information for engineers, this paper helps clarify some misconceptions—such as injecting the most viscous polymer possible—in polymer-flooding implementations, according to polymer-flooding practice in China. Annual oil production using polymer flooding as well as polymer utility factors (UFs) are given. Various technical parameters, such as polymer slug, viscosity, IORF, oil-increase factor (OIF), and water-cut decrease, are provided to better understand polymer-flooding evaluation as well economics.

Alkali Effect on Alkali-Surfactant-Polymer (ASP) Flooding Enhanced Oil Recovery Performance: Two Large-Scale Field Tests’ Evidence

Alkali-surfactant-polymer (ASP) flooding is very promising chemical enhanced oil recovery (EOR) technology which can make an incremental oil recovery factor (IORF) of 30% original oil in place (OOIP). How to choose alkali in ASP flooding remains a question for a long time. As the world’s only and largest ASP flooding application place, Daqing Oilfield has always adhered to the strategy of parallel development of strong alkali ASP flooding (SASP) and weak alkali ASP flooding (WASP), but SASP is in a dominant position, indicated by more investments and more project numbers. This leaves an impression that SASP is better than WASP. However, WASP is drawing more interest than SASP recently. Moreover, as the ASP flooding in Daqing went from field tests to commercial applications since 2014, how to comprehensively consider the benefit and cost of ASP flooding has become a new focus at low oil prices. This paper compares two typical large-scale field tests (B-1-D SASP and B-2-X WASP) completed in Daqing Oilfield and analyzes and discusses the causes of this difference. The injection viscosity and interfacial tension (IFT) for the two field test areas are substantially equivalent under the conditions of Daqing Oilfield, and WASP is better than SASP when reservoir geological conditions are considered. WASP exhibits the same IORF of 30% as SASP while having a much better economic performance. For the SASP field test, the injected strong alkali NaOH makes the test behave unlike a typical strong ASP flooding due to the presence of CO2 in the formation fluid, which well explains why IORF is much higher than all the other SASPs but scaling is less severe than others. This paper confirms that under Daqing Oilfield reservoir conditions, it is the alkali difference that caused the performance difference of these two tests, although some minor uncertainties exist. WASP is better than the SASP providing the same conditions . In addition, the detailed information of the two ASP field tests provided can give reference for the implementation of ASP flooding in other oilfields. After all, the study of ASP flooding enhanced oil recovery technology under low oil prices requires great foresight and determination.

Recent Advances of Surfactant-Polymer (SP) Flooding Enhanced Oil Recovery Field Tests in China

Recently, there are increasing interests in chemical enhanced oil recovery (EOR) especially surfactant-polymer (SP) flooding. Although alkali-surfactant-polymer (ASP) flooding can make an incremental oil recovery factor (IORF) of 18% original oil in place (OOIP) according to large-scale field tests in Daqing, the complex antiscaling and emulsion breaking technology as well as potential environment influence makes some people turn to alkali-free SP flooding. With the benefit of high IORF in laboratory and no scaling issue to worry, SP flooding is theoretically better than ASP flooding when high quality surfactant is available. Many SP flooding field tests have been conducted in China, where the largest chemical flooding application is reported. 10 typical large-scale SP flooding field tests were critically reviewed to help understand the benefit and challenge of SP flooding in low oil price era. Among these 10 field tests, only one is conducted in Daqing Oilfield, although ASP flooding has entered the commercial application stage since 2014. 2 SP tests are conducted in Shengli Oilfield. Both technical and economic parameters are used to evaluate these tests. 2 of these ten tests are very successful; the others were either technically or economically unsuccessful. Although laboratory tests showed that SP flooding can attain IORF of more than 15%, the average predicted IORF for these 10 field tests was 12% OOIP. Only two SP flooding tests in (SP 1 in Liaohe and SP 7 in Shengli) were reported actual IORF higher than 15% OOIP. The field test in Shengli was so successful that many enlarged field tests and industrial applications were carried out, which finally lead to a commercial application of SP flooding in 2008. However, other SP projects are not documented except two (SP7 and SP8). SP flooding tests in low permeability reservoirs were not successful due to high surfactant adsorption. It seems that SP flooding is not cost competitive as polymer flooding and ASP flooding if judged by utility factor (UF) and EOR cost. Even the most technically and economically successful SP1 has a much higher cost than polymer flooding and ASP flooding, SP flooding is thus not cost competitive as previously expected. The cost of SP flooding can be as high as ASP flooding, which indicates the importance of alkali. How to reduce surfactant adsorption in SP flooding is very important to cost reduction. It is high time to reevaluate the potential and suitable reservoir conditions for SP flooding. The necessity of surfactant to get ultra-low interfacial tension for EOR remains further investigation. This paper provides the petroleum industry with hard-to-get valuable information.

Numerical simulation of CO2 huff-and-puff process in a hydraulically fractured horizontal well in a tight oil reservoir

A numerical reservoir model was built using Computer Modeling Group's GEM simulator to study the process of carbon dioxide (CO2) huff-and-puff in the Bakken tight formation. The influences of injection rate, production time, and soaking time on the incremental oil recovery factor (IORF) were studied systematically, as was the utilization efficiency of CO2 during the whole production process. The results showed that higher injection rates are preferable to lower ones, and the huff-and-puff process works best with a soaking time of 0 days. The production time of each cycle could be optimized for a specific case to maximize IORF, and CO2 efficiency was found to decrease with increasing number of cycles. This study may shed light on how to optimize the CO2 huff-and-puff process and therefore achieve the best enhanced oil recovery performance.

Role of Alkali Type in Chemical Loss and ASP-Flooding Enhanced Oil Recovery in Sandstone Formations

Summary Chemical combination flooding techniques, particularly alkali/surfactant/polymer (ASP) flooding, have proved to be effective in enhanced oil recovery (EOR). The development of this flooding technique in the Daqing Oil Field (China) shows that it can prevent production declines and help oil companies increase profits. However, ASP chemical loss and the resulting chromatographic separation in sandstone formations remain as limitations in the practice of ASP flooding. Laboratory investigations have analyzed the behavior and characteristics of chemical loss in sandstone reservoirs recently subjected to strong-base [sodium hydroxide (NaOH)] and weak-base [sodium carbonate (Na2CO3)] ASP flooding. A set of experiments were reasonably designed to study how formulation compositions, slug combination patterns, and heterogeneity affected the chromatographic separation and consumption loss characteristics of chemicals in sandstone reservoirs subjected to ASP flooding. Our investigations determined chemical-loss ratios through various experiments, described the underlying mechanism behind the discovered consumption loss characteristics, and discussed the effects of comparative ASP flooding processes. Furthermore, the incremental oil recovery factor and degree of permeability damage in heterogeneous sandstone reservoirs subjected to strong-base and weak-base ASP flooding processes were assessed and compared. Then, the role of alkali type in chemical loss, EOR efficiency, and reservoir flow assurance in sandstone formations were ascertained for the first time. The results indicated that chemical-loss behaviors and chemical chromatographic separation could be alleviated in a weak-base ASP flooding. In particular, in heterogeneous sandstone reservoirs, the average loss ratios of alkalis and surfactants could be reduced by 9.61% and 15.67%, respectively, compared to the strong-base ASP flooding. A profitable EOR of 20% or more could also be obtained with a weak-base ASP flooding. Moreover, a reduction of approximately 15% in the permeability-damage ratio could be realized in weak-base ASP flooding compared with the strong-base system, and the reservoir flow-assurance issues related to chemical loss could be addressed. The optimal designs for ASP formulations and slug combination patterns could technically and sustainably achieve high oil recovery in sandstone reservoirs with a weak-base ASP flooding. The results help illustrate the chemical combination flooding mechanism and can contribute to the existing knowledge regarding the additive effects of chemicals during the EOR process. Moreover, they are significant for further improving oil displacement efficiency and reducing the injection cost in heterogeneous sandstone reservoirs subjected to the weak-base ASP-flooding process.

A screening-level life cycle greenhouse gas analysis of CO2 enhanced oil recovery with CO2 sourced from the Shute Creek natural gas-processing facility

This life cycle analysis (LCA) evaluates life cycle greenhouse gas (GHG) emissions associated with a system that produces both natural gas and crude oil. Two systems are defined: System 1, which independently produces natural gas and oil, and System 2, which captures carbon dioxide (CO2) from the natural gas-processing plant and utilizes this captured CO2 for enhanced oil recovery (EOR). The LCA uses customized spreadsheet models with emission factors from peer-reviewed literature and publications of the National Energy Technology Laboratory of the U.S. Department of Energy. The modeling results show that the CO2 EOR scenario using captured CO2 produces both natural gas and oil with lower life cycle GHG emissions than alternative systems producing natural gas and oil independently. Sensitivity analyses show that the model results are most sensitive to the fraction of CO2 captured (or equivalently, the fraction of CO2 vented) at the natural gas-processing facility and the incremental oil recovery factor and net CO2 utilization factor of the EOR operations. The input variable driving the relative difference in life cycle GHG emissions between these two systems is the fraction of CO2 captured at the natural gas-processing facility (i.e., the capture rate). The results of this study highlight the necessity of linking processes in the life cycle modeling, as a change to one process can affect other processes within the coupled energy system comprised of natural gas and oil. In addition, this analysis shows, as prior work has also suggested, that CO2 EOR using captured anthropogenic CO2 provides a viable means for offsetting carbon emissions from oil production and combustion via the associated storage of CO2 that occurs incidentally during this tertiary method of oil recovery.

Lessons Learned From Alkali/Surfactant/Polymer-Flooding Field Tests in China

Summary Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention. Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits. Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10−3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue. Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.

Manipulation of star-like polymer flooding systems based on their comprehensive solution properties and flow behavior in porous media

In this study, novel star-like polymers (SLPs) with four-gradient molecular weight (Mw), consisting of nano-silica as the core and a layer of hydrophilic chains as the shell, were fabricated via mild water free-radical polymerization. The comprehensive properties of SLP flooding systems prepared with brine were investigated to elucidate their underlying applications by combining static measurements, filterable tests, two-serial cores displacement experiments, and polymer flooding tests for enhanced oil recovery (EOR). The specific injectivity index was proposed, for the first time, to demonstrate the flow behavior of SLP solutions in conglomerate rocks.The results indicated that the rigid core together with the three-dimensional microstructure bestowed SLPs with the desirable viscosification and long-term stability in harsh conditions, outperforming ultrahigh-Mw partially hydrolyzed polyacrylamide. The dynamic hydrodynamic size (Hd) of SLPs was a power function over concentration and significantly depended on Mw. Based on the limitation of specific injectivity index, the resistance factor and residual resistance factor of SLP solutions as a function of permeability were mathematically correlated. SLPs had sustainable mobility control capability with no face plugging or internal filter cake when the average pore size over Hd of SLP solutions was higher than 5.2. This is contradictory to the conventional rigid sphere packing theory. Considering permeability of conglomerate rocks, the SLP flooding systems were designed using polymer concentration and Mw. The incremental oil recovery factor (RF) achieved by the designed SLP flooding systems was 7.0% more than that achieved by the SLP flooding systems that were not well designed but had an equivalent viscosity.This study indicates that the comprehensive performance of polymer solutions associated with the compatibility between Mw and rock permeability is significant to formulate polymer flooding systems with high EOR efficiency.