EOR Methods Research Articles

A multi-scale experimental study of hydrophobically-modified polyacrylamide flood and surfactant-polymer flood on enhanced heavy oil recovery

A large amount of residual oil remained in heavy oil reservoirs after water flood due to its viscosity nature. And it has been validated that chemical flood, if applied appropriately, is an efficient and economical EOR method for deeply buried or thin heavy oil reservoirs. A multi-scale experimental evaluation workflow was designed to explore the mechanisms behind the production of residual oil in heavy oil reservoirs by chemical flood. And we conducted three multi-scale experiments to evaluate the performance of hydrophobically-modified polyacrylamide (HMHPAM) flood, surfactant-polymer (SP) flood and their combination. Based on the results of corefloods and medical CT scans, we demonstrated the EOR potential of HMHPAM flood (HPF) synergy with SP flood (SPF). After each coreflood, two samples were drilled from the heterogenous core used in the macro-scale experiment. And the micro-CT scan results of these samples visualized the distribution of oil phase and aqueous phase in each coreflood at the pore scale, and further quantified the decrease of continuous oil clusters caused by the HMHPAM solution and following injected fluids. Besides, we also observed the linear relationship between the volume of each oil cluster against its surface area and the logarithmic relationship between the volume of discontinuous oil cluster and its cumulative contribution to total oil volume. Moreover, a simple method to calculate the oil-water proportion in pores was developed to correlate the relationship between the displacement efficiency of each pore and its pore size. Results showed that the relationship between oil saturation in each pore and its pore size followed the power law correlation. Moreover, the pore-scale analysis also validated that the residual oil in most pores after water flood was effectively mobilized by the synergy of HPF and SPF.

An experimental investigation on enhancing water flooding performance using oil-in-water emulsions in an Iranian oil reservoir

Emulsions are extensively prevalent in the oil industry in both advantageous and disadvantageous ways. In the literature, conventional water flooding in high permeability oil reservoirs has confronted with water channeling and poor sweep efficiency. In this paper, the remedial application of O/W emulsions as an EOR method in improving water performance is discussed. To this purpose, a series of flooding experiments were carried out in one of the Iranian oil reservoirs in reservoir condition of 75 C and 2000 psi. Then, visual stability measurements were conducted to inspect the stability characterization of the emulsion. Sodium dodecyl sulfate was applied helping simple dispersion of the gasoil into the water phase, and emulsions with water percentage of 90, 80, 70 and 60 were developed to introduce into the porous media. It was found out from flooding experiments that emulsion injection after conventional water flooding can lead to additional oil recovery (up to 20%). Besides, the emulsion with 80% water cut was determined as the optimum emulsion for injection in this reservoir considering financial aspects. Moreover, results of the stability test revealed that the aqueous phase with one wt% surfactant or higher had formed emulsions which have been stable during a long period of 6 months.

Experimental Study on EOR Performance of Natural Gas Injection in Tight Oil Reservoirs

Gas injection is an effective enhanced oil recovery method in tight oil reservoirs. In the case of tight oil fields with sufficient natural gas supply, natural gas injection can significantly reduce the cost of operation, leading economic benefit. Natural gas flooding might be a promising EOR method for tight oil development. Based on the material and reservoir condition of a tight formation in Changqing Oilfield, this study conducted a series of natural gas injection experiments to evaluate the feasibility of natural gas injection after water flooding and analysed the influence of gas injection rate to EOR performance. Experiment results shows that natural gas injection can recover 20.8% more oil after water flooding. Sensitivity analyses indicates that natural gas injection had a higher oil recovery with low injection rate.

Study on EOR method in offshore oilfield: Combination of polymer microspheres flooding and nitrogen foam flooding

Nitrogen foam flooding and polymer microsphere flooding have been applied for improving the developmental effect of the high water-cut period in offshore oilfields in recent years. The combination of polymer microsphere flooding and nitrogen foam flooding as a novel technology for enhanced oil recovery was developed in offshore oilfields, due to their injectability, propagation and in-depth plugging property. The goal of the current research was to evaluate the performance of polymer microspheres, screen the appropriate nitrogen foam system, determine the displacement effect of the combination technology by performance measurements and displacement experiments in a laboratory, then the mechanism of profile control and oil displacement was concluded. The experimental results indicated that the polymer microspheres were suitable to inject into the formation due to their swelling and plugging abilities, and the plugging rate of polymer microspheres could reach 96% at 2000 mg/L. The foam system was composed of a 5000 mg/L foaming agent, S2, and a 1000 mg/L stabilizer, P1, the optimal gas-liquid ratio was 1:1, and the best foam slug combination was alternating injections with multiple slugs. In addition, the oil recovery increment of the combined technology (24.65%) was larger than those of the microsphere flooding (12.35%) and foam flooding (18.3%) alone, especially for the low permeability layer. According to the laboratory results, a pilot test was conducted at well group W1 in the Bohai A oilfield, and the test showed that the combined technology can attain the oil increment of 64461 bbls. Therefore, the combination of polymer microsphere flooding and nitrogen foam flooding can help to enhanced the oil recovery more efficiently.

Viscous oil recovery and in-situ deasphalting in fractured reservoirs – Part 2: Effect of solvent type and temperature

This paper advances the understanding of the solvent-based EOR methods from our previous work by investigating the effect of solvent type and temperature on the recovery of viscous oil by liquid extraction using sandstone cores with an artificial fracture. The production mechanisms were identified through the analysis of oil production rate, ultimate recovery, and in-situ deasphalting in different sections of the core. The use of dichloromethane (DCM) was introduced as the reference to study the production without in-situ deasphalting whereas n-pentane injection was compared to that of n-butane injection to study the effect of paraffin length on production with in-situ deasphalting. Sustained high production rates, which deviate from the behavior of typical gravity drainage processes, were observed in the cases with in-situ deasphalting. This discrepancy was attributed to the enhanced convection in the matrix due to the alteration of fracture aperture by asphaltene precipitation and deposition. Temperature has a significant impact on oil production through its effect on mass diffusivity as well as asphaltene rheology. The result of this work indicates that solvent selection is a key factor in the optimizing solvent EOR process and potential asphaltene deposition should be taken into consideration.

Research on the 3-D Oil Saturation Variation of the Oil Sand at 45° Stratigraphic Dip Angle with Hot-Water-Flooding

Most of oil sands mineral distributed in the slope and upheaval of the basin's edge, and hot water flooding is one of EOR methods for the high-viscosity oil. In this paper the 3-D physical model for oil sands reservoir of angle 45° was studied, and the flooding way of this experiment was hot water flooding.

Geochemical performance evaluation of pre-flushing of weak and strong acids during pH-triggered polymer flooding

Implementing pH-triggered polymer is an efficient way to improve the conformance control of hydrocarbon formations. pH-triggered polymer solutions have high mobility in low pH conditions, while due to their high swelling capacity in higher pH values, their viscosity increases with pH increment. Therefore, they can fill high permeability zones/strata and consequently improve the efficiency of enhanced oil recovery. To achieve the desired viscosity of a pH-triggered polymer, the pH of porous media is regulated by implementing an appropriate acid pre-flushing. In this study, we develop a mathematical model to predict the acid pre-flush behavior before the main pH-triggered polymer flooding. Convection, diffusion, and homogeneous/heterogeneous geochemical reactions for a slightly compressible fluid flow in porous media is formulated. This model consists of three non-linear conservation equations (i.e., mass balance, species concentration balance, and Darcy law), which are solved simultaneously in a global implicit approach. We discretize the transport and geochemical reaction terms with a finite difference method by implementing the benefit of the Newton-Raphson method. Moreover, the code vectorization programming approach of the Python language is applied to decrease the computation time. The introduced model is validated against the experimental data available in the literature. This EOR method is mostly implemented on sandstones and there are very limited investigations on the applicability of this method on carbonate rocks. Hence, we simulate the injection of several acids (strong and weak acids) into a carbonate rock under different flow conditions (i.e., different Damkohler numbers). The obtained pH values reveal that weak acids can provide better results for acid pre-flushing in carbonate formations. Therefore, implementing these acids can be a more efficient way to increase the acid residence time as well as to improve the conformance control during a pH-triggered polymer flooding project.

Numerical study of Low Salinity Water Alternating CO2 injection for enhancing oil recovery in a sandstone reservoir: Coupled geochemical and fluid flow modeling

The combination of low salinity water with gas in the form of water alternating CO2 injection (CO2-LSWAG) is a promising EOR method that could simultaneously benefit from gas mobility control and also rock wettability alteration to more water-wet as consequence of geochemical interaction between rock and reservoir fluids. This paper aims to investigate the EOR potential of CO2-LSWAG under miscible conditions in a sandstone oil reservoir by coupling fluid flow and geochemical modeling. The wettability alteration of the rock surface was described by a series of relevant geochemical reactions between rock and low salinity water in a compositional simulator. The concept of ion equivalent fraction was used as the wettability index during CO2-LSWAG injection. It consists mainly of the effects of ion exchange and clay properties on oil-water relative permeability functions. Also, the effect of calcite mineral dissolution was studied as result of interaction with low salinity water and CO2 gas using relevant geochemical reactions. Results showed that salinity difference between injected and formation water triggers ion exchange processes between water and rock. Also, the rate of calcite dissolution increased due to the CO2 partitioning into the aqueous phase. The calcite dissolution caused the increase of calcium ions in the reservoir leading to more water-wet condition. However, results indicated that the rate of calcite dissolution decreased far from the injection well most likely due to reduced interaction time between low salinity water with dissolved CO2 and the reservoir rock. The oil recovery results showed that CO2-LSWAG is capable of producing incremental oil as much as 10% of the initial oil in place on top of high salinity CO2-WAG. The results of this numerical study support the potential application of CO2-LSWAG as an efficient EOR method in sandstone reservoirs.

Injection parameters optimization of crosslinked polymer flooding by genetic algorithm

The crosslinked polymer flooding, which is developed on the basis of polymer flooding, is a new type of flooding technology. As an EOR method, cross-linked polymer flooding has become a research hotspot. In the process of cross-linked polymer flooding, if the concentrations of the polymer and the crosslinking agent are small, the viscosity of the solution is low, and it will not achieve the oil displacement effect. Meanwhile, if the concentrations of the polymer and crosslinking agent are large, the viscosity of the solution is high, it needs high pressure to drive it flowing in the formation. Further, with the increasing injection of chemical agents, the contradiction between reduced production and increased cost has presented. The performance of crosslinked polymer flooding depends on the interaction of these two factors. Therefore, the concentrations of polymer and crosslinking agent should be optimized. In this paper, an optimal design method is proposed by using genetic algorithm with global optimization characteristics algorithm, combining with the chemical flooding numerical simulation software UTCHEM, the concentrations of the chemical agents are optimized. Firstly, the cumulative oil production is calculated by numerical simulation software UTCHEM, then the concentrations of the chemical agents are randomly generated by the genetic algorithm in the encoding process, and the fitness function takes the profit of cross-linked polymer flooding. Given a set of initial values, through crossover and mutation of population, optimized injection concentrations of the polymer and cross-linking agent are obtained by the multi-generational calculation. Cited as : Lian, P., Li, L., Duan, T. Injection parameters optimization of crosslinked polymer flooding by genetic algorithm. Advances in Geo-Energy Research, 2018, 2(4): 441-449, doi: 10.26804/ager.2018.04.08

On the impact of Co3O4 nanoparticles on interaction of heavy oil and brine mixtures

Among numerous EOR methods, the injection of brine with different salinities to oil reservoirs has gained attention where its performance would, in turn, depend on interfacial tension (IFT) of oil/brine mixture. The present study investigated the impact of Co3O4 nanoparticles with concentrations of 0.01, 0.1 and 1 wt% on IFT of brine solution (containing NaCl, KCl and CaCl2) and heavy crude oil system. The results confirmed that adding Co3O4 nanoparticles to water, compared to that without nanoparticles, reduced IFT at low (i.e. 0–5000 ppm) and high (i.e. greater than 5000 ppm) brine concentrations, although the propensity of IFT is different for various concentrations. Furthermore, the reduction of IFT for monovalent ions is greater than that for divalent ions. Properties such as high surface activity and higher surface to volume ratio of the Co3O4 nanoparticles should be accounted for profound adsorption of asphaltene onto the surface of nanoparticles. A high suspension of asphaltene at the brine/oil interface also avoided its precipitation in oil causing IFT to reduce in brine/crude mixtures with nanoparticles compared to that without nanoparticles. The extent of IFT reduction changed by using different concentrations of Co3O4 nanoparticles. For the oil/brine system attempted in this study, the optimum concentration of Co3O4 nanoparticles in term of IFT reduction was 0.1 wt%.

Influence of Styrene‐Butadiene Co‐Polymer on the Hydration Kinetics of SBR‐Modified Well Cement Slurries

Flexible cement sheath can eliminate the formation of cracks caused by the thermal recovery in the EOR methods. SBR‐modified slurries were fabricated by adding Styrene‐Butadiene Rubber (SBR) in latex to the cement matrix. In this article, the influence of this latex on the hydration kinetics of the cement slurry was investigated. SBR (≈83% of Styrene) was added by 6%, 10%, and 13% (V/V) to prepare the slurries and the kinetics in both fresh and hardened states were accompanied by UCA and isothermal calorimetry. The results indicated that in the very early ages of hydration, Ca(OH)2 was consumed by SBR (demulsification phenomenon). A retarding effect was observed and the percolation threshold values were increased by 18.05%, 19.44%, and 27.77% for the SBR‐modified slurries, whereas an overall higher accumulated heat could be observed in the isothermal calorimetry curves when compared to the reference slurry.

Sensitivity Study to Evaluate the Impact of Critical Parameters for Feasibility of Air-Injection in Light-Oil Reservoir

Objectives: Air injection has long been recognized as having the potential for being an economical for enhanced oil recovery processes. The oil recovery mechanisms for light oil reservoirs using air injection are yet not well described. Recovering remaining oil economically is always a challenge hence a simulation study was conducted in order to provide feasibility for pilot project implementation and execution. Methods: For improved understanding of injection of air for enhanced oil recovery, a sensitivity study conducted using the CMG simulation approach. The impact of air injection was assessed by considering the different operational constraints such as, permeability heterogeneity, oil viscosity, injection pressures, effect of injection temperatures and injection rate. The impact of various other parameters such as O2 concentration and N2 concentration on oil recovery efficiency were also analyzed. Findings: This study has determined the best possible production scenario, leading to better economic conditions. This study shows that the method of air injection results in more than 60% oil recovery. The results obtained from the simulation study show that the optimal values of operational parameters must be considered. Applications/Improvements: The operational parameters analysed during present study will help the improved efficiency of air injection for enhanced recovery. It is also found that the air injection process could be considered as an economical EOR method for light oil reservoirs. Keywords: Air Injection, CMG-Stars, Injection Constraints, Light Oil Reservoir, Numerical Simulation

Laboratory characterization of crude oil and sandstone reservoir for chemical enhanced oil recovery

PurposeBecause of the increasing global oil demand, efforts have been made to further extract oil using chemical enhanced oil recovery (CEOR) methods. However, unlike water flooding, understanding the physicochemical properties of crude oil and its sandstone reservoir makeup is the first step before embarking to CEOR projects. These properties play major roles in the area of EOR technologies and are important for the development of reliable chemical flooding agents; also, they are key parameters used to evaluate the economic and technical feasibilities of production and refining processes in the oil industries. Consequently, this paper aims to investigate various important physicochemical properties of crude oil (specific gravity; American Petroleum Institute [API]; viscosity; pour point; basic sediment and water; wax; and saturate, aromatic, resins and asphaltenes components) and sandstone reservoir makeup (porosity, permeability, bulk volume and density, grain volume and density, morphology and mineral composition and distributions) obtained from Malaysian oil field (MOF) for oil recovery prediction and design of promising chemical flooding agents.Design/methodology/approachThree reservoir sandstones from different depths (CORE 1; 5601, CORE 2; 6173 and CORE 3; 6182 ft) as well as its crude oil were obtained from the MOF, and various characterization instruments, such as high temperature gas chromatography and column chromatography for crude’s fractions identification; GC-simulated distillation for boiling point distribution; POROPERM for porosity and permeability; CT-Scan and scanning electron microscopy-energy dispersive X-ray for morphology and mineral distribution; wax instrument (wax content); pour point analyser (pour point); and visco-rheometre (viscosity), were used for the characterizations.FindingsExperimental data gathered from this study show that the field contains low viscous (0.0018-0.014 Pa.s) sweet and light-typed crude because of low sulfur content (0.03 per cent), API gravity (43.1o), high proportion of volatile components (51.78 per cent) and insignificant traces of heavy components (0.02 per cent). Similarly, the rock permeability trend with depth was found in the order of CORE 1 < CORE 2 < CORE 3, and other parameters such as pore volume (Vp), bulk volume (Vb) and grain volume (Vg) also decrease in general. For grain density, the variation is small and insignificant, but for bulk density, CORE 2 records lower than CORE 3 by more than 1 per cent. In the mineral composition analysis, the CORE 2 contains the highest identified mineral content, with the exception of quarts where it was higher in the CORE 3. Thus, a good flow crude characteristic, permeability trend and the net mineral concentrations identified in this reservoir would not affect the economic viability of the CEOR method and predicts the validation of the MOF as a potential field that could respond to CEOR method successfully.Originality/valueThis paper is the first of its kind to combine the two important oil field properties to scientifically predict the evaluation of an oil field (MOF) as a step forward toward development of novel chemical flooding agents for application in EOR. Hence, information obtained from this paper would help in the development of reliable chemical flooding agents and designing of EOR methods.

Effectiveness of oil displacement by sequential low-salinity waterflooding in low-permeability fractured and non-fractured chalky limestone cores

Low-salinity waterflooding has been recognized as a method of enhancing oil recovery in low-permeability reservoirs. This method is relatively inexpensive and can be easily implemented in the field. Various mechanisms of low-salinity flooding have been proposed including interfacial tension reduction, wettability alteration (cation exchange), change in pH (increase), emulsion formation, and clay migration. Hydraulic fracturing has been known as a technique of stimulating hydrocarbon flow from low-permeability matrix into wellbores by creating high-conductivity fractures. The objective of this study is to evaluate the effectiveness of sequential low-salinity brine flooding process to enhance oil recovery in low-permeability fractured and non-fractured chalky limestone core samples. The low-salinity waterflooding tests were conducted with synthetic brines of five different salinity concentrations, namely, 157,662, 72,927, 62,522, 6252, and 1250 ppm. The properties of these brines have been thoroughly investigated in the laboratory. The crude oil and chalky limestone core samples, permeability range between 0.01 and 1.2 millidarcy, were gathered from a selected oil field in United Arab Emirates. When used as an opening move in a three-stage sequential brine flooding (SW/10→SW/50→SW 6xSO4− 2), sea water diluted ten times at 6252 ppm (SW/10) has been found to yield the highest oil recovery in fractured and non-fractured tests at the prevailing reservoir conditions, of 82.64 and 76% of OOIP, respectively. In all sequential brine flooding scenarios tested, sea water with sulfate concentration spiked six times (SW 6 × SO4− 2) only slightly increased oil recovery. The highest observed incremental recovery with sulfate spiking was 2.083% of OOIP. The effectiveness of oil displacement by sequential brine flooding has been attributed to mineral dissolution and fines migration which resulted in a favorable wettability alteration. This postulation of flow mechanism is confirmed by introducing a “flow resistance index” concept and measurements of key properties of the injected and effluent brines of each stage of the attempted sequential brine flooding scenarios. Results of this study could be consulted when selecting most efficient EOR method to develop tight carbonate oil reservoirs in the UAE and worldwide.

Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants

Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions.A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 °C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water.RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam.These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.

CO2-EOR mechanisms in huff-n-puff operations in shale oil reservoirs based on history matching results

Improved Oil Recovery (IOR) techniques in Unconventional Liquids Rich Reservoirs (ULR) are still a new concept because there is no commercial project for any IOR technique so far. Carbon dioxide (CO2) based EOR technique has been effectively applied to improve oil recovery in the tight formations of conventional reservoirs. Extending this approach to unconventional formations has been extensively investigated over the last decade because CO2 has unique properties which make it the first option of EOR methods to be tried. However, the applications and mechanisms for CO2-EOR in unconventional reservoirs would not necessarily be the same as in conventional reservoirs due to the complex and poor-quality properties of these plays.Since the first CO2-EOR huff-n-puff project was conducted in conventional reservoirs in Trinidad and Tobago in 1984, more than 130 additional projects have been put in operation around the world, mainly located in USA, Turkey, and Trinidad and Tobago. In this study, we combined Production Data Analysis (PDA) for the production data of these projects with numerical simulation methods to produce one typical graph accounts for the main mechanisms controlling CO2-EOR performance in conventional reservoirs. On the other hand, we have couple of CO2-EOR huff-n-puff pilot tests conducted in Bakken formation between 2008 and 2016. Two engineering-reversed approaches have been integrated to produce a unique type curve for the performance of CO2-EOR huff-n-puff process in shale oil reservoirs. Firstly, a numerical simulation study was conducted to upscale the reported experimental-studies outcomes to the field conditions. As a result, different forward diagnostic plots have been generated from different combinations for CO2 physical mechanisms with different shale-reservoirs conditions. Secondly, different backward diagnostic plots have been produced from the history match with CO2 performances in fields’ pilots performed in some portions of Bakken formation located in North Dakota and Montana. Finally, fitting the backward with the forward diagnostic plots was used to produce another unique type curve to represent CO2-EOR performance in shale oil reservoirs. This study found that the delayed response in the incremental oil production resulted from CO2 injection in shale reservoirs is mainly function of CO2 molecular diffusion mechanism. On the other hand, the CO2 diffusion mechanism has approximately no effect on CO2-EOR performance in conventional reservoirs which have a quick response to CO2 injection. This finding is very well consistent with the experimental reports regarding the role of diffusion in conventional cores versus shale cores. In addition, this study found that kinetics of oil recovery process in productive areas and CO2-diffusivity level are the keys to perform a successful CO2-EOR project in shale formations. This paper provides a thorough idea about how CO2-EOR performance is different in the field scale of conventional reservoirs versus shale formations.

An experimental study of the low salinity Smart Water - Polymer hybrid EOR effect in sandstone material

Previously reported experimental work has shown positive oil recovery effects by combining low salinity brine with polymer for injection into sandstone cores. The extra oil recovered by the combination of the two EOR methods was termed a “Hybrid EOR effect”.The experimental work performed in the present study assessed the potential of combining low salinity (LS) Smart Water injection with polymer (P) flooding; LSP flooding. Dramatic improvements in the EOR effect were observed when combining LS in secondary mode with polymer injection in tertiary mode.Secondary LS injection gave 59 %OOIP after 1 PV injected, which is an outstanding result compared to secondary formation water (FW) injection reaching only 35 %OOIP after 1 PV, and an ultimate recovery of 40 %OOIP after 2.5 PV. The ultimate recovery with seawater (SW) in secondary mode was 44% OOIP, showing only a slightly better performance than FW, but poorer efficiency than the ultimate LS brine recovery of 64 %OOIP.In comparison, the ultimate recovery with secondary LSP injection was 66 %OOIP. The displacement front was stable and fast, but it did not give a substantial increase in oil recovery in comparison to the secondary LS injection. Tertiary LSP injection after secondary LS injection gave the highest oil recoveries with a total hybrid EOR effect of 86 %OOIP. All tertiary LSP floods gave improved displacement stability with EOR effects of ∼20 %OOIP. The positive EOR effects are a result of redistribution of oil within the pore space after wettability alteration with the Smart Water. Oil attached to the mineral surface has low mobility, but at more water-wet conditions a new fraction of mobile oil, which is more easily mobilized with a polymer solution, is created (Wang et al., 2001).The combination of Smart Water with polymer flooding appears to have a huge potential for future EOR applications. Field development strategies for new sandstone reservoirs should include wettability alteration and redistribution of oil within the pores by Smart Water and improved displacement efficiency with polymer for optimized EOR to lowest cost.

Smart Water injection strategies for optimized EOR in a high temperature offshore oil reservoir

Smart Water injection is an EOR technique that is both environmentally friendly and easily implementable to a fractional cost compared to other water-based EOR methods. EOR by Smart Water is a wettability alteration process towards more water-wet conditions, which induces increased positive capillary forces and increased microscopic sweep efficiency.The objective of this work was to evaluate the injection strategy for Smart Water in an offshore high temperature sandstone reservoir, and compare the efficiency of seawater-based injection brines with low salinity brines, which can behave as Smart Water in sandstone reservoirs. Oil recovery experiments have been performed at reservoir conditions using preserved reservoir cores and reservoir fluids.Secondary low salinity injection gave an average of 33.5 %OOIP extra oil produced, compared to modified seawater injection. The tertiary low salinity EOR effect after modified seawater flooding gave an average of 11.8 %OOIP extra oil. Significant changes in produced water pH from initially acidic to alkaline conditions during low salinity injection were observed, favoring wettability alteration towards more water-wet conditions.The results confirmed that low salinity brine behaved as a Smart Water, contributing with significant extra oil recovery in a high temperature sandstone reservoir. Introducing Smart Water from day one in a reservoir, i.e. in secondary recovery mode, is significantly more efficient, regarding both response time and ultimate oil recovery, than tertiary mode Smart Water injection.

Using Polymer Alternating Gas to Enhance Oil Recovery in Heavy Oil

CO2 has been used to recover oil for more than 40 years. Currently, about 43% of EOR production in U.S. is from CO2 flooding. CO2 flooding is a well-established EOR technique, but its density and viscosity nature are challenges for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. So water-alternating-gas (WAG) method was used to control the mobility of CO2 and improve sweep efficiency. However, WAG process has some other problems in heavy oil reservoir, such as poor mobility ratio and gravity overriding. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests a new EOR method--polymer-alternating gas (PAG) process. The process involves a combination of polymer flooding and CO2 injection. To confirm the effectiveness of PAG process in heavy oils, a reservoir model from Liaohe Oilfield is used to compare the technical and economic performance among PAG, WAG and polymer flooding. Simulation results show that PAG method would increase oil recovery over 10% compared with other EOR methods and PAG would be economically success based on assumption in this study. This study is the first to apply PAG to enhance oil recovery in heavy oil reservoir with highly heterogeneous. Besides, this paper provides detailed discussions and comparison about PAG with other EOR methods in this heavy oil reservoir.

Viscous Oil Recovery and In Situ Deasphalting in Fractured Reservoirs: Part 1. The Effect of Solvent Injection Rate

Steam-based EOR methods for viscous oil recovery from fractured reservoirs have significant challenges in both cost and energy efficiency. In response, solvent-based methods have been of interest because of their low energy intensity, low greenhouse gas emissions, and no fresh water consumption. Injection strategies for viscous oil recovery by solvent include liquid extraction and vapor oil gravity drainage. Understanding the mechanisms in each phase is of great value for the successful application and optimization of solvent EOR processes. The work presented here studies the effect of solvent injection rate on viscous oil recovery by liquid extraction with n-butane in vertically placed sandstone cores with an artificial fracture. The oil production rate, ultimate recovery, and in situ deasphalting in different sections of the core are analyzed. The oil production rate increased with solvent injection rate until it leveled off as the injection rate exceeded a critical value. The ultimate recovery factor i...