Enhanced Oil Recovery Chemicals Research Articles

CFD simulations of a bubble column containing enhanced oil recovery chemicals

AbstractChemical enhanced oil recovery (EOR) methods return produced water containing polymers and surfactants which poses a water treatment challenge at offshore facilities. The present work shows that numerical simulations of gas‐water systems containing these chemicals remain challenging. Computational fluid dynamics (CFD) was used to predict gas holdup in a laboratory bubble column containing brine and EOR chemicals. The synthetic produced water was treated as non‐Newtonian in the simulations to match the experimentally‐determined physical properties. Two‐ and three‐dimensional numerical simulations were performed, and the latter were shown to be more appropriate through statistical analysis. Three classical drag models were assessed, and the results indicated that none of them could account for the high liquid viscosities and low surface tensions encountered in the system. A modification to the drag model of Tomiyama et al. (1988) was proposed to account for drag increases at low bubble Reynolds numbers when liquid apparent viscosity is high and surface tension is low. The importance of considering the interaction between apparent viscosity and surface tension was also shown through statistical analysis. CFD predictions of gas holdup showed that the proposed drag modification reduced errors from approximately 30% to less than 10% when compared to the experimental data. Radial profiles of the axial liquid velocity were also assessed and are apparently related to gas holdup prediction.

Performance improvement of chemical enhanced oil recovery by divalent ion–complexing agents

The performance of chemicals used in chemical enhanced oil recovery (EOR) is sensitive to the local ionic environment. Divalent ions are in particular known to reduce polymer solution viscosity and mediate the adsorption of surfactants and polymers to the rock surface. Here, we study whether the addition of divalent ion–complexing agents can mitigate these interactions and thus improve the performance of EOR chemicals. The addition of sodium polyacrylate (NaPA) is found to be highly effective in reducing surfactant adsorption and increasing polymer viscosity. The reduction in surfactant adsorption is attributed to a combination of divalent ion complexation and the adsorption of polyacrylate to the rock surface. The increase in polymer viscosity is also attributed to complexation of divalent ions that would otherwise interact with the polymer. Polymer flooding experiments in a limestone core show that the addition of NaPA also significantly enhances solution injectivity and propagation, thus providing a host of benefits to chemical EOR performance.

De-Emulsification and Gravity Separation of Micro-Emulsion Produced with Enhanced Oil Recovery Chemicals Flooding

The present study investigates the effect of TiO2 nanoparticles on the stability of Enhanced Oil Recovery (EOR)-produced stable emulsion. The chemical precipitation method is used to synthesize TiO2 nanoparticles, and their properties were determined using various analytical characterization techniques such as X-ray Diffraction (XRD), High-Resolution Transmission Electron Microscopy (HRTEM), and Field Emission Scanning Electron Microscopy (FESEM). The effect of TiO2 nanoparticles is evaluated by measuring oil/water (o/w) separation, rag layer formation, oil droplet size, and zeta potential of the residual EOR produced emulsion. The laser scattering technique is used to determine the o/w separation. The results showed that spherical-shaped anatase phase TiO2 nanoparticles were produced with an average particle size of 122 nm. The TiO2 nanoparticles had a positive effect on o/w separation and the clarity of the separated water. The separated aqueous phases’ clarity is 75% and 45% with and without TiO2 nanoparticles, respectively. Laser scattering analysis revealed enhanced light transmission in the presence of TiO2 nanoparticles, suggesting higher o/w separation of the ASP-produced emulsion. The overall increase in the o/w separation was recorded to be 19% in the presence of TiO2 nanoparticles, indicating a decrease in the stability of ASP-produced emulsion. This decrease in the stability can be attributed to the improved coalescence’ action between the adjacent oil droplets and improved behavior of o/w interfacial film. An observable difference was found between the oil droplet size before and after the addition of TiO2 nanoparticles, where the oil droplet size increased from 3 µm to 35 µm. A similar trend of zeta potential is also noticed in the presence of TiO2 nanoparticles. Zeta potential was −13 mV to −7 mV, which is in the unstable emulsion range. Overall, the o/w separation is enhanced by introducing TiO2 nanoparticles into ASP-produced stable emulsion.

Gas holdup and flow regime in a bubble column that includes enhanced oil recovery chemicals

Chemical enhanced oil recovery (EOR) methods are alternatives to increase oil production in mature reservoirs. However, the presence of EOR chemicals in the produced water may impact the separation of gas-water systems in oil platforms. The present work aims to evaluate the impact of polymers, surfactants, inorganic salts, and their interactions on gas holdup in a 32.1-cm-diameter semi-batch bubble column over a range of superficial gas velocities ranging from 0 to 19 cm/s. It has been confirmed through physical-chemical analysis that synthetic produced water containing salts, polymers and organic surfactants is non-Newtonian with low surface tension. Results have shown that both salt and surfactants increase gas holdup regardless of superficial gas velocity, while the effect of polymers depends on superficial gas velocity. This work also innovates by showing how interactions between EOR chemicals and salinity affect transition gas holdup and superficial gas velocity between different flow regimes. Overall results shed some light on how the chemical composition of EOR effluents affect gas holdup and flow regime as a function of a wide range of superficial gas velocities and therefore contributes to the development of gas-liquid systems.

Influence of natural L-amino acids on the interfacial tension of an oil-water system and rock wettability alterations

The cost and environmental effects of most conventional surfactants have increased the search for a greener and cheaper alternative for enhanced oil recovery (EOR) applications. The natural L-amino acids are amphoteric compound with excellent surface properties that have found versatile applications in the pharmaceutical, cosmetic, and food industries. These amino acids exhibited amphipathic nature due to their hydrophobic alkyl chain and charged head. Hence, they could form contacts with both polar and non-polar surface ligands simultaneously. In this study, four amino acids, namely L-arginine, L-lysine, L-methionine, and L-tryptophan, were investigated to access their ability to reduce the interfacial tension (IFT) and alter the wettability of oil-wet sandstone rock. The pendant/rising drop and sessile drop method were employed in IFT and contact angle measurements. The stability of amino acids in brine and the compatibility with other EOR chemicals were tested through visual observation of the precipitates and cloudiness. With the exception of L-tryptophan, the compatibility and stability results revealed that all the amino acids have high salt tolerance above 25 wt% sodium chloride (NaCl). The solutions of amino acids and chemicals such as cetyltrimethylammonium bromide (CTAB), sodium dodecyl sulfate (SDS), hydrolyzed polyacrylamide (HPAM), alkali, and alkali-polymer were transparent even at 80 °C.The IFT test results showed that the amino acids significantly reduced the crude oil-water IFT compared to the IFT of n-decane-water system. The IFT between deionized water and crude oil decreased by 76.61% and 55.24%, 24.79%, 45.23% in the presence of L-arginine, lysine, methionine, and tryptophan solutions, respectively. Addition of 0.01 wt% L-arginine, L-lysine and L-methionine to 0.1 wt% SDS reduced the IFT by 28.3%, 15.6%, and 10.97% respectively. The contact angle test showed that L-amino acids have great potential as wettability modifying agents. The contact angles reduced with the decreasing pH (potential of hydrogen) and with increasing brine concentrations from 1 to 4 wt%. Specifically, the contact angle reduced from 92.3°, 91.42°, 89.81° and 92.95 to 47.24°, 53.9°, 58.9° and 59.0° for L-arginine, L-lysine, L-methionine and L-tryptophan, respectively at a pH of about 3. The study suggests that the L-amino acids could be a potential EOR agent in a high saline environment, mainly as a wettability modifier, as well as additives to improve the surface activity of the conventional surfactant and EOR chemicals.

Effect of Enhanced-Oil-Recovery Chemicals on Oil/Water-Separation Processes, from Laboratory Scale to Flow-Loop Scale

With the use of chemically based enhanced-recovery methods, water management, which has always been a major point in the production-operation processes, needs to be considered and adapted because the whole water cycle will be affected by the backproduced additives. Enhanced-oil-recovery (EOR) chemicals such as alkali molecules, high-molecular-weight polymers, or surfactant formulation will dramatically modify pH, viscosity, and phase behaviors of produced fluids. The main issues encountered in oil/water-separation processes are directly related to the risk of tight emulsion formation, which might considerably complicate the surface-water-treatment processes. The objective of this paper is to underline the effect of one of these chemicals, a surfactant formulation, on the produced-water cycle when they are backproduced first at a laboratory scale and second on a large-scale separation unit using an industrial-size flow loop and a well-instrumented separator. Our goal is first to investigate the impact of surfactant on the water/oil mixture separation efficiency, and second, to find an efficient demulsifier specific for this case. At the laboratory scale, the impact of surfactant within produced fluids on oil/water separation (regarding separation kinetics but also oil/water phase qualities) will be evaluated by performing bottle tests. Those laboratory bottle tests enabled us to screen different parameters, such as the surfactant concentration, the water cut that can strongly affect the type of formed emulsion [oil in water (O/W) or water in oil (W/O)], and its stability. The oil/water phase qualities were quantified and correlations with parameters related to the large-scale experiment were drawn, helping us in defining the key parameters for this campaign. Indeed, to get closer to a field case, a semi-industrial-scale test platform was used. The flow loop reproduces separation process conditions encountered in a field treatment facility, including the production separator, the controlled temperature, and the oilfield chemical injection rate. The main operating conditions are liquid flow rates and temperature. The influence of different parameters can be studied, such as the surfactant concentration, mixing conditions, residence time, water cut, and the presence of chemicals that will help the separation process. Different types of emulsions were formed depending on the conditions, and their stability was evaluated through the measurement of separation profiles using a single electrode capacitance probe (SECAP) within the separator. The results obtained show how the surfactant, as well as the demulsifier concentration, have led to different types of emulsions and have affected the oil/water separation processes. These tests have confirmed that separation is more difficult in the presence of surfactant and that water quality was degraded. It has also been shown that separation processes can be greatly improved by adding some EOR-compliant demulsifier to recover a better water quality compared with the surfactant case. Laboratory workflows, as well as experiments performed at large scale using an industrial size separator, could help to minimize risks of operations to mitigate these challenges in terms of separation issues. This work illustrates that water management is a major challenge for produced fluids containing EOR chemicals that need an integrated approach and should be studied beforehand.

Understanding the stability mechanism of silica nanoparticles: The effect of cations and EOR chemicals

We have investigated the conditions of colloidal stability of silica nanoparticles smaller than 100 nm for their applications in enhanced oil recovery (EOR), especially pertaining to chemical flooding processes. Using zeta sizer and dynamic light scattering techniques, the stability of silica nanoparticle (SNP) dispersions has been investigated by variation of the pH, composition of salt solutions, addition of surfactants and polyelectrolytes. Such conditions can be encountered in oil reservoirs. It was found that changing pH from 5 to 10 had a negligible effect on the size of SNPs, whereas its zeta potential increased with increasing pH. Aggregation of SNPs is a partially reversible process for low degrees of aggregation in 500 mM NaCl, whereas observed strong aggregation in 1000 mM NaCl was irreversible. A critical aggregation concentration (CAC) was defined for the different salts investigated, above which the SNP dispersion became unstable at a fixed pH of 9.5. The CAC for NaCl was approximately 200 times higher than for CaCl2 and MgCl2. Our observations could not be explained completely by the Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. Therefore, we have included non-DLVO interactions such as cation bridging, hydration forces, and steric effects. The additional presence of anionic alcohol alkoxy sulfate (AAS) surfactant slightly destabilized the SNP solution, but by the addition of polyacrylate (PA) was effectively stabilized. With increasing PA concentration, the CAC for both CaCl2 and MgCl2 increased. Upon addition of 100 ppm PA, the CAC increased by a factor of five compared to the situation in the absence of PA. Reducing the solution pH below 8.5, SNP can be stabilized in higher salinity in the presence of PA. The obtained results contribute to a better fundamental understanding of the SNP stability mechanism and a guide to optimize the SNP injection process with EOR chemicals.

Microscale Interactions of Surfactant and Polymer Chemicals at Crude Oil/Water Interface for Enhanced Oil Recovery

Summary The conventional experimental techniques used for performance evaluation of enhanced oil recovery (EOR) chemicals, such as polymers and surfactants, have been mostly limited to bulk viscosity, phase behavior/interfacial tension (IFT), and thermal stability measurements. Furthermore, fundamental studies exploring the different microscale interactions instigated by the EOR chemicals at the crude oil/water interface are scanty. The objective of this experimental study is to fill this existing knowledge gap and deliver an important understanding on underlying interfacial sciences and their potential implications for oil recovery in chemical EOR. Different microscale interactions of EOR chemicals, at crude oil/water interface, were studied by using a suite of experimental techniques, including an interfacial shear rheometer, Langmuir trough, and coalescence time measurement apparatus at both ambient (23°C) and elevated (70°C) temperatures. The reservoir crude oil and high-salinity injection water (57,000 ppm total dissolved solids) were used. Two chemicals, an amphoteric surfactant (at 1,000 ppm) and a sulfonated polyacrylamide polymer (at 500 and 700 ppm) were chosen because they are tolerant to high-salinity and high-temperature conditions. Interfacial viscous and elastic moduli (viscoelasticity), interface pressures, interface compression energies, and coalescence time between crude oil droplets are the major experimental data measured. Interfacial shear rheology results showed that surfactant favorably reduced the viscoelasticity of crude oil/water interface by decreasing the elastic and viscous modulus and increasing the phase angle to soften the interfacial film. Polymers in brine either alone or together with surfactant increased the viscous and elastic modulus and decreased the phase angle at the oil/water interface, thereby contributing to interfacial film rigidity. Interfacial pressures with polymers remained almost in the same order of magnitude as the high-salinity brine. In contrast, a significant reduction in interfacial pressures with surfactant was observed. The interface compression energies indicated the same trend and were reduced by approximately two orders of magnitude when surfactant was added to the brine. The surfactant was also able to retain similar interface behavior under compression even in the presence of polymers. The coalescence times between crude oil droplets were increased by polymers, while they were substantially decreased by the surfactant. These consistent findings from different experimental techniques demonstrated the adverse interactions of polymers at the crude oil/water interface to result in more rigid films, while confirming the high efficiency of the surfactant to soften the interfacial film, promote the oil droplets coalescence, and mobilize substantial amounts of residual oil in chemical EOR. This experimental study, for the first time, characterized the microscale interactions of surfactant-polymer chemicals at the crude oil/water interface. The applicability of several interfacial experimental techniques has been demonstrated to successfully understand underlying interfacial sciences and oil mobilization mechanisms in chemical EOR. These techniques and methods can provide potential means to efficiently screen and optimize EOR chemical formulations for better oil recovery in both sandstone and carbonate reservoirs.

Effect of dynamic spreading and the disperse phase of crystalline starch nanoparticles in enhancing oil recovery at reservoir condition of a typical sarawak oil field

Nanofluid flooding has been proven to be very effective in enhanced oil recovery (EOR). The performance depends on the material and formulation process. Previous studies have focused only on the use of inorganic, metal and metal oxides nanoparticles. The use of nanofluids from natural sources has not been investigated to a reasonable extent for possible application in EOR. In this study, ascorbic acid was used for the first time to synthesize crystalline starch nanoparticles (CSNP). The physical properties of the CSNP including their size distribution and crystalline structures were investigated. The interfacial properties of the crystalline starch nanofluid (CSNF) at the interface of oil and water (O/W) were investigated at different concentrations and temperatures. The effect of the interaction between electrolyte and ultrasonic was determined. The wettability alteration efficiency of CSNF on oil-wet sandstone surface was investigated using the sessile drop method. A core flooding experiment was conducted at reservoir conditions to justify the effect of wettability alteration and dispersion of CSNF on additional oil recovery. The performance of the CSNF was compared with the conventional EOR chemical. The methods were effective in producing spherical and polygonal nanoparticles with a mean diameter of 100 nm and increased in crystallinity of 7%. The interfacial tension (IFT) decreased with increase in concentration of CSNF, electrolyte and temperature. The results show that CSNF can change the wettability of sandstone at low concentration, high salinity and elevated temperature. The pressure drops data show stability of CSNF at 120 °C. The formation of oil bank was enough to increase oil recovery by 23%. CSNF was effective in mobilizing residual oil at reservoir condition. It can, therefore, be concluded from this experiment work that the method applied herein is easier, cost-effective and can reduce energy consumption making the method economically advantageous compared to conventional methods.

Effects of EOR chemicals and superficial gas velocity on bubble size and gas holdup of a bubble column

Chemical Enhanced Oil Recovery (EOR) can boost oil extraction in offshore operations, however one of the main concerns regarding its application is how the efficiency of flotation units for treating produced water is affected. The present work thus focuses on investigating the impact of EOR chemicals on the physical properties of EOR effluents and how this can affect flotation performance parameters such as bubble size and gas holdup. Design of experiments has been used to assess the influence of polymer, surfactant and sodium chloride concentrations on bubble size and gas holdup of a laboratorial bubble column. The influence of superficial gas velocity has also been assessed together with chemicals concentrations, yet at low levels in order to avoid clusters, swarms and foam. The characterization of the synthetic effluent containing polymer, surfactant and sodium chloride has indicated that the fluid behaves as a non-Newtonian fluid, what makes separation processes in flotation cells challenging. Results showed that polymer concentration of 2000 mg/L can lead to significant increases in fluid viscosity, promote a growth of more than 40% in bubble size and only increases gas holdup when surfactant is present at high concentration. Therefore, polymers are expected to be detrimental to produced water treatment. Surfactants decrease both fluid surface tension and bubble size, increasing gas holdup. For the range studied, superficial gas velocity favors gas holdup and sodium chloride concentration seems to weakly influence bubble size and gas holdup. This work highlights the fact that changes in physical properties of produced water do modify bubble size distribution and gas holdup and this must therefore be taken into account when flotation-like systems are designed to deal with EOR effluents.

A Step Change for Single-Well Chemical-Tracer Tests: Field Pilot Testing of New Sets of Novel Tracers

SummaryThe single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.

Laboratory study on efficiency of three calcium carbonate scale inhibitors in the presence of EOR chemicals

Chemical flooding has been widely used in the oil industry since the 1980s for enhanced oil recovery (EOR) process. Previous studies have shown that the effectiveness of calcium carbonate scale inhibitors is affected by many factors, such as water composition, system pressure, temperature, production rates, pH etc. The breakthrough of the EOR chemicals in the production well could also affect scale formation process and interfere with the scale treatment program as well. However, the studies on the impacts of injected EOR chemicals to scale inhibitor performances are very limited. This paper presents the comprehensive laboratory study on the impacts of the EOR chemicals on CaCO3 scale formation and prevention using static bottle and dynamic tube blocking methods. The EOR chemicals used in this study are a combination of surfactants and polymers. Three different types of inhibitors were evaluated: tri-phosphonate, penta-phosphonate, and polyacrylate based chemicals. Inhibition (%) from the bottle test and minimum effective dose (MED) based on the tube blocking method were determined for each inhibitor at 160 °F. Scale precipitates from the bottle tests were also characterized for morphology and polymorphs using environmental scanning electron (ESEM) and X-ray diffraction (XRD) techniques. Results suggest that the performance of scale inhibitors could be substantially affected by the EOR chemicals. In dynamic tube blocking tests, the MED values of inhibitors were increased roughly 10 times with the EOR chemicals. The static bottle tests showed considerable changes under the test conditions. The impact of EOR chemicals were also demonstrated by the remarkable ranges of crystal morphologies, changing from simple aragonite columns to nanorod, distorted spheroid, and flower-like superstructure in the presence of EOR chemicals and inhibitors.

Solution behavior of water‐soluble poly(acrylamide‐co‐sulfobetaine) with intensive antisalt performance as an enhanced oil‐recovery chemical

ABSTRACTIn the process of oilfield development, salt tolerance is an important property for enhanced oil‐recovery (EOR) chemicals. In this study, we synthesized two acrylamide‐based sulfobetaine copolymers containing 2‐hydroxy‐3‐[(3‐methacrylamidopropyl)dimethylammonio]propane sulfonate (SHPP) or 3‐(4‐acry‐loyl‐1‐methyl‐piperazinio)‐2‐hydroxypropane sulfonate (SHMP). The interactions between these two copolymers and inorganic salts were compared, and the apparent viscosity (ηapp) behaviors of copolymer–salt solutions at different shear rates and temperatures were investigated. We found that the ηapp of PAPP and PAMP showed intensive antisalt performance, exhibiting an excellent antipolyelectrolyte effect. The ηapp retention value of 30,000 mg/L PAMP in brine was 86.47 mPa s at 510 s−1, and when the temperature was increased to 90 °C, it was 99.73 mPa s; this was better than that of PAPP under the same conditions. Therefore, PAMP was more applicable as an EOR chemical that have outstanding salt tolerance and temperature resistance. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018, 135, 46235

Laboratory testing of enhanced biocide mitigation of an oilfield biofilm and its microbiologically influenced corrosion of carbon steel in the presence of oilfield chemicals

Microbiologically influenced corrosion (MIC) is prevalent in the oil and gas industry. Problematic biofilms cause MIC and reservoir souring. A high biocide concentration is usually required to mitigate biofilms compared with planktonic cells. This causes economic and environmental concerns. A biocide enhancer can make a biocide more effective using the same or lower biocide dosage. In this work, an equimolar mixture of 100 ppm (w/w) of four D-amino acids (D-methionine, D-tyrosine, D-tryptophan, and D-leucine) labeled as D-mix enhanced 100 ppm tetrakis (hydroxymethyl) phosphonium sulfate (THPS) against a field biofilm consortium on C1018 carbon steel coupons. In order to test chemical compatibilities, D-amino acids were added together with THPS and enhanced oil recovery chemicals (a polymer, a surfactant, a corrosion inhibitor, and a scale inhibitor) to treat the mature biofilm consortium. After a 7-day biofilm removal test in 125 ml anaerobic vials, the cocktail of 100 ppm THPS +100 ppm D-mix achieved extra logs of reduction in sessile cell counts compared with the 100 ppm THPS alone treatment. The combination also achieved lower weight loss and smaller maximum pit depths. Electrochemical tests corroborated the weight loss and pitting data.

Technology Focus: EOR Performance and Modeling (January 2016)

Technology Focus Efforts to increase recovery factors in all types of oil reservoirs keep increasing, regardless of the fluctuations in oil prices. It is a historical fact that, when oil price drops, industry’s focus turns to produce/recover more oil where the oil is already found. In my career, this is the sixth oil-price crush I have seen, and the same behavioral change is happening again. The only difference between now and my first experience, in the 1980s, is that the need for enhanced-oil-recovery (EOR) applications today is a must, not a luxury. Luckily, activity in the world of EOR is continuing and for the better. Recovery-optimization efforts of the national oil companies are expanding with larger and well-designed EOR pilots and even with offshore chemical EOR projects. It is worth mentioning here that the EOR experience gathered by the international oil companies and service companies over the decades is definitely finding its way to provide a stable foundation to those new EOR projects. Additionally, new EOR projects are getting the benefit of the significant enhancements in reservoir characterization and evaluation, flow physics, EOR chemicals, modeling capabilities, conformance capabilities, and monitoring and control systems. All those are happening; therefore, it is safe to say the new EOR projects will be significantly more successful compared with the older ones from 1980s. Mitigating declining pressures in the 1970s and 1980s was basically handled by injection of water with simple vertical injectors with limited design. Now, companies think about low-salinity (LoSal) options every time pressure maintenance with water is considered. Alternatively, companies can design reliable water-alternating- gas (WAG) -injection schemes by placing the right-trajectory wells in the right locations of heterogeneous reservoir systems, which were already illuminated sufficiently with advanced reservoir characterization. Placing in-situ sensors and digital feedback mechanisms enables companies to optimize the new recovery process significantly. To start with, instead of just going with pressure maintenance, smart EOR screening systems that might have already been used may be more promising EOR options. Accessibility to fast EOR pilots suitable for the heterogeneity of the reservoir could be used, and the decision for field expansion takes place much faster and more reliably than it did in the 1980s. More-reliable modeling capabilities, coupled with cloud computing, are providing an environment in which refining EOR decisions in the presence of the uncertainties of the reservoirs is now possible. Limited design capability, smaller number of field tests, and lack of monitoring and control were the reasons most EOR projects did not perform in the past. All those issues are history now. Over the last year, irrespective of the inclement times in our industry, fundamental sciences, EOR physics, numerical modeling, monitoring and controlling capabilities, and EOR chemicals all demonstrated advancements. Ironically, fast exploitation of the unconventional liquids is considered to be one of the key reasons for the drop in oil prices; there are efforts to identify EOR potential for those reservoirs. The efforts consist of advancements in reservoir characterization suitable to those unique reservoir systems, smarter fracturing fluids, and EOR pilots. As a result of the continuing momentum in EOR efforts, many excellent technical papers were developed and, once again, selecting only a few was rather difficult. The following pages provide some insights on how EOR is being tested for “tight/light” reservoirs, CO2/LoSal WAG experimentation, and giant-field EOR applications. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 173322 A Four-Phase-Flow Model To Simulate Chemical EOR With Gas by Mohammad Lotfollahi, The University of Texas at Austin, et al. SPE 174648 Novel Visualization of Chemical EOR Flooding Using a Lab-on-a- Chip Setup Supported by an Extensive Rheological Characterization by J. Wegner, Clausthal University of Technology, et al. SPE 173205 Reduced-Order Models for Rapid EOR Simulation in Fractured Carbonate Reservoirs by S. Agada, Heriot-Watt University, et al.

A novel α-aminophosphonic acid-modified acrylamide-based hydrophobic associating copolymer with superb water solubility for enhanced oil recovery

Here we report a novel α-aminophosphonic acid-modified acrylamide-based hydrophobic associating copolymer. The copolymer exhibits significant potential as an enhanced oil recovery chemical for high-temperature and high-mineralization oilfields.

Technology Focus: EOR Performance and Modeling (January 2015)

Technology Focus We can easily state that incorporating enhanced-recovery focus into field- management practices as early as possible is finally becoming the norm. No longer is enhanced oil recovery (EOR) something operators procrastinate about and not act on until the end of the life of a field. Growing recovery challenges of maturing fields definitely are one of the reasons for this historical change in focus. We should also acknowledge the effect of growing unconventional oil operations and, more importantly, their severe recovery challenges. Increasing recovery factors in tight, light reservoirs is one of the more prominent research topics in the oil industry in recent years. Last but not least, EOR is being implemented in offshore operations. This new paradigm—caring for production and recovery, optimizing production rates and recovery factors simultaneously—is being realized with significant help from new technologies. Significant enhancements in reservoir characterization, EOR chemicals, modeling capabilities (EOR software and computational power), conformance capabilities, and monitoring and control systems, along with improved understanding of flow physics, are making EOR easier for our industry. Ongoing EOR research is bringing complex EOR schemes to the industry; some of the examples are low-salinity CO2 water-alternating-gas (WAG) injection, CO2/steam injection, steam/ solvent injection, and microbial EOR. Integration for successful EOR projects is also maturing. Historically, with steam-assisted gravity drainage, we all recognized the effect of well trajectory on recovery. More recently, we have identified the relationship between massive fracture architecture and EOR in tight, light reservoirs. It is worth mentioning that unconventionals have been pushing reservoir characterization, drilling, and completions to yet another level. All that effort not only improves the performance of those special reservoirs but also makes EOR easier for conventionals. As a result of the focus on enhancing recovery for all types of reservoirs, many great technical papers were available for this feature this year. The following pages will provide some insights into how EOR is being tested for tight, light reservoirs; into low-salinity CO2 WAG experimentation; and into giant-field EOR applications. More papers can be found in the OnePetro online library, including those listed for recommended additional reading. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 169076 Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery by Mojtaba Kiani, Tiorco, et al. SPE 169170 Assessment of Three-Phase Relative Permeability and Hysteresis Models for Simulation of Water- Alternating-Gas Injection in Water- Wet and Mixed-Wet Systems by Omid Shahrokhi, Heriot-Watt University, et al. SPE 169102 Low-Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts by B.M.J.M. Suijkerbuijk, Shell, et al. OTC 24483 Relative Permeability Effects on the Miscible CO2 WAG Injection Schemes Through Compositional Simulations of Brazilian Small-Scale Water-Wet Synthetic Presalt Reservoir by S.F. Mello, Universidade Estadual de Campinas, et al.

Efficiency of ionic liquids for chemical enhanced oil recovery

Substantial amount of crude oil remains in the reservoir after primary and secondary production. Chemical flooding is one of the enhanced oil recovery (EOR) methods; however, chemicals (i.e., Surfactant) used are sensitive to the harsh environment characterizing the local reservoirs. The current study aimed at investigating the utilization of ionic liquids (ILs), known as environment friendly salt with good solubility, thermal stability and effective surface activity, as an alternative to conventional organic surfactants in enhanced oil recovery process. In this work, screening tests of nine ILs were performed. These ILs were diluted in different brine solutions of different salt compositions at 10 % (w/w) salinity and their solubility, thermal stability and surface activity in presence of Saudi medium crude oil were tested. Tetra alkyl ammonium sulfate known as Ammoeng 102 was found to be the ionic liquid of choice. Further investigations on Ammoeng 102 solutions at 10 and 20 % (w/w) salinity were conducted and IFT measurements indicate enhanced surface activity of Ammoeng 102 with increasing solution salinity. Effects of pressure and temperature on interfacial tension (IFT) were also tested and the results indicate minor effects. Adsorption test indicates high Ammoeng 102 adsorption tendency with more adsorption for higher salinity solution. Different flooding scenarios were conducted in sandstone rock samples to investigate the effectiveness of Ammoeng 102 IL as an EOR chemical. The findings indicate promising results for ionic solution flooding in secondary mode at irreducible water saturation (S wirr). Ultimate recovery obtained is higher than that obtained with combined secondary brine flooding followed by tertiary ionic solution flooding at residual oil saturation (S or). Injection of slug of ionic solution in secondary mode provides lower recovery compared to that recovered with continuous ionic solution injection in the same mode. Rock water content affects recovery efficiency indicating higher oil recovery for secondary brine and tertiary ionic solution flooding at low S wirr. Contact angle and relative permeability measurements demonstrate the role of wettability alteration behind the extra oil recovery which is very much affected by ionic liquid concentration that can be altered by dilution with formation and injected brines.

Technology Focus: EOR Performance and Modeling (January 2014)

Technology Focus This is the most exciting time for enhanced oil recovery (EOR) in recent memory. At last, almost everyone is talking about increasing recovery factors, and improved oil recovery (IOR) and EOR are being considered natural components of reservoir management. Furthermore, many traditional philosophies are being openly challenged. EOR planning is happening as part of field-development plans. Proven technologies are being adapted in new, smart ways, and new technologies are constantly evolving from research to commercial applications, making EOR projects more economical. These new directions are the result of the following factors: Most fields, including the giant ones, are maturing, and producing liquid hydrocarbons is becoming more difficult in all types of reservoirs (conventional and unconventional). Leaving approximately 70% of the in-place reserves unrecovered has been challenged. There have been developments on many fronts (e.g., advanced reservoir characterization, multiphase-flow physics, smart-well and intelligent completions, recovery research, monitoring and control technologies, EOR chemicals, EOR pilot concepts, and observation-well concepts); the collective effect of all of those is going to make new EOR projects more successful. Increasing recovery factors has been considered a fully integrated multidomain activity (from pore space to separator and everything in between). Severe production decline in tight/light (unconventional) reservoirs is making the industry think about recovery challenges. EOR has been considered during field-development planning in most recent offshore oil developments. We lived through the most active period of EOR—between the mid-1970s and the mid-1980s—and learned about recovery fundamentals then. However, if we look back at that era carefully, most of the wells were single and vertical; reservoir characterization was very elementary, with no digital geological modeling capabilities; and there were no concepts such as monitoring systems or intelligent completions. All of those factors created a significant gap between what was planned in the EOR laboratory and what was achieved in field application. Other than those implemented in extremely viscous oils (heavy-oil EOR operations), projects recovered far less than planned. Overall, such recovery gave a stigma to EOR as inherently difficult and expensive. Most of the factors that made EOR difficult and expensive are gone today. That is why we will see more fields using EOR operations in upcoming years. Broadening the scope of recovery challenge to all domains will make realizations of new reserves more likely, but this change will bring additional challenges. Recommended additional reading at OnePetro: www.onepetro.org. SPE 162701 Geomechanics Considerations in Enhanced Oil Recovery by Tadesse Weldu Teklu, Colorado School of Mines, et al. SPE 166597 BP North Sea Miscible Gas Injection Projects Review by Pinggang Zhang, BP, et al. IPTC 17157 The Development of a Workflow To Improve Predictive Capability of Low-Salinity Response by B.M.J.M. Suijkerbuijk, Shell, et al. SPE 166075 The Upscaling of Discrete Fracture Models for Faster, Coarse-Scale Simulations of IOR and EOR Processes for Fractured Reservoirs by Mun-Hong Hui, Chevron, et al.

Tracer monitoring of enhanced oil recovery projects

In enhanced oil recovery (EOR), chemicals are injected into the oil reservoir, either to increase macroscopic sweep efficiency, or to reduce remaining oil saturation in swept zones. Tracers can be used to identify reservoirs that are specifically suited for EOR operations. Injection of a selection of partitioning tracers, combined with frequent sample analysis of produced fluids, provides information suited for estimation of residual oil saturation. Tracers can also be used to evaluate and optimize the application of EOR chemicals in the reservoir. Suitable tracers will follow the EOR chemicals and assist in evaluation of retention, degradation or trapping. In addition to field applications, tracers also have a large potential as a tool to perform mechanistic studies of EOR chemicals in laboratory experiments. By labelling EOR chemicals with radioactive isotopes of elements such as H, C and S, detailed studies of transport mechanisms can be carried out. Co-injection of labelled compounds in dynamic flooding experiments in porous media will give information about retention or separation of the unique compounds constituting the chemical formulation. Separation of such compounds may be detrimental to obtaining the EOR effect expected. The paper gives new information of specific methods, and discusses current status for use of tracers in EOR operations.