Incremental Oil Recovery Research Articles

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 The paper has not been peer reviewed.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.

Permeability and heterogeneity adaptability of surfactant-alternating-gas foam for recovering oil from low-permeability reservoirs

As the traditional polymer stabilizer is eliminated to improve the injectability of foam in low-permeability reservoirs, the stability, plugging capacity, conformance control and oil recovery performance of the surfactant-alternating-gas (SAG) foam become significantly important for determining its adaptability to permeability and heterogeneity, which were focused and experimentally researched in this paper. Results show that the SAG bubbles are highly stable in micron-sized channels and porous media (than in the conventional unconstrained graduated cylinder), making it possible to use in enhanced oil recovery (EOR). Such bubbles formed in porous media could be passively adjusted to match their diameter with the size of the pore. This endows the SAG foam with underlying excellent injectability and deep migration capacity. Permeability adaptability results indicate a reduced plugging capacity, but, increased incremental oil recovery by the SAG foam with decreased permeability. This makes it a good candidate for EOR over a wide range of permeability, however, parallel core floods demonstrate that there is a limiting heterogeneity for SAG application, which is determined to be a permeability contrast of 12.0 (for a reservoir containing oil of 9.9 mPa s). Beyond this limit, the foam would become ineffective.

Optimal Horizontal Well Placement Technology to Improve Heavy Oil Production

Optimal horizontal well placement and production optimization have been highly scrutinized. Development adjustments, such as drilling new infill wells and changing the injection/production rates of wells, can improve the performance of mature fields and leading to incremental oil recovery. Infill wells are new wells added to an existing field within original well patterns. Infill drilling can hasten oil production in heterogeneous reservoirs. If well patterns alter, fluid flow paths and sweep to areas with high oil saturations would be increased. Of course, this plan is difficult to be examined because reservoir performance is affected by many different parameters. Compared to vertical or low inclination wells, horizontal wells can deliver higher production rates, higher recovery factors and more efficient use of steam in thermally enhanced recovery projects for heavy oil. Maximum oil production is achieved when horizontal wells are placed near the bottom of the reservoir. In addition, cumulative steam to oil ratio is lowest when wells are near the bottom of the reservoir, meaning that the least volume of steam will need to be generated to produce a particular volume of oil. In this paper, the optimal horizontal well placement technology to improve heavy oil production has been studied.

Modelling the effects of reservoir parameters and rock mineralogy on wettability during low salinity waterflooding in sandstone reservoirs

Low salinity waterflooding has been reported to yield incremental oil recovery from both field applications and laboratory experiments compared to regular waterflooding. Crude oil-brine-rock (COBR) interactions dictate wettability alteration during low salinity waterflooding in sandstones. In this work, triple-layer surface complexation modelling (TLM) is utilised to simulate the interactions at rock-brine and oil-brine interfaces, while accommodating the crucial role of sandstone mineralogy in surface chemistry. Derjaguin-Landau-Verwey-Overbeek (DLVO) theory is applied to characterise the COBR stability. Moreover, we propose the use of the maximum energy barrier (MEB) parameter, which is calculated from the DLVO theory's interaction potential, as an indicator of reservoir wettability.Correlating the MEB with the experimentally measured contact angles revealed an abrupt increase in contact angles as the MEB drops below the zero-value thereby leading to a less water-wet COBR system. Results analyses showed that the different clays affect the rock-brine zeta potential and wettability distinctly based on their surface site densities and specific surface areas. And the studied clays cause the zeta potential to become more negative in the order: smectite > montmorillonite > illite > chlorite > kaolinite. Subsequently, further investigation employing the developed TLM and MEB revealed that higher amounts of kaolinite will make the reservoir more oil-wet.Lastly, the sensitivity analysis performed on reservoir wettability indicated that the ionic composition is the most important factor to affect rock wettability followed by pH and temperature. Moreover, the presence of CaCl2 salt in the formation water significantly supresses the areas of strong water wettability under varying reservoir conditions compared to NaCl salt.The work conducted in this study presents a novel approach to model the individual and combined effects of sandstone minerals, specifically, quartz, kaolinite, chlorite, illite, montmorillonite and smectite, on the overall sandstone zeta potential behaviour. Furthermore, a new method was proposed to characterise reservoir wettability as a function of the maximum energy barrier which allowed us to obtain valuable insights into the most affecting reservoir parameters on COBR wettability. These findings will have practical implications to efficiently design the low salinity waterflooding processes for sandstone reservoir applications.

Investigation of Brine pH Effect on the Rheological and Viscoelastic Properties of HPAM Polymer for an Optimized Enhanced Oil Recovery Design.

A novel approach to improve viscous and viscoelastic properties by exploiting the pH and salinity sensitivity of HPAM polymer is proposed in this paper. Polymer flooding is a well-developed and effective enhanced oil recovery technique. The design of the makeup brine is one of the most critical phases of a polymer flood project, since the brine composition, salinity, and pH directly influence the polymer viscosity and viscoelasticity. However, the viscoelastic properties of hydrolyzed polyacrylamide polymers have not been given much consideration during the design phase of polymer flood projects. Our experimental study focuses on the optimization of the makeup water design for polymer flooding by evaluating the optimum solution salinity and pH for better stability and improved viscoelastic behavior of the polymer. Initially, the brine salinity and ionic composition is adjusted and then hydrolyzed polyacrylamide (HPAM) polymer solutions of varying pH are prepared using the adjusted brine. Rheological experiments are conducted over a temperature range of 25–80 °C and at different aging times. Polymer thermal degradation as a function of pH is assessed by examining the solutions at 80 °C for 1 week. Amplitude sweep and frequency sweep tests are performed to determine the viscoelastic properties such as storage modulus, loss modulus, and relaxation time. A 15–40% increase in the polymer solution viscosity and a 20 times increase in relaxation time is observed in the pH range of 8–10 in comparison to the neutral solution. This can be attributed to the low-salinity ion-adjusted environment of the makeup brine and further hydrolysis and increased repulsion of polymer chains in an alkaline environment. These results indicate that the viscoelastic properties of a polymer are tunable and a basic pH is favorable for better synergy between the brine and the polymer. Alkaline low-salinity polymer solutions have exhibited 60% higher thermal stability in comparison to acidic solutions and thus can be successfully applied in high-temperature reservoirs. The results of this study show that polymer solutions with an optimum pH in the basic range exhibit a higher viscoelastic character and an increased resistance toward thermal degradation. Hence, the polymer solution salinity, ionic composition, and pH should be adjusted to obtain maximum oil recovery by the polymer flooding method. Finally, this study shows that more effective polymer solutions can be prepared by adjusting the pH and designing a low-salinity water/polymer recipe to get the additional benefit of polymer viscoelasticity. The optimized low-salinity alkaline conditions can reduce the residual oil saturation by stronger viscous and viscoelastic forces developed by more viscous polymers. The findings of this study can be employed to design an optimum polymer recipe by tuning the brine pH and salinity for maximum incremental oil recovery, particularly in high-temperature and high-salinity formations.

The ternary combination of polymer gel, microsphere and surfactant for conformance control and oil displacement to improve oil recovery in strong heterogeneous reservoir

The reservoir heterogeneity of Suizhong 36-1 oilfield is very obvious, the average permeability reaches 2000mD. Long-term water injection development leads to serious water channeling in high permeability layers, resulting in ineffective circulation of injected water and reduction of oil recovery. It is urgent to form an effective EOR method. In this paper, the oil displacement effect of different combination slugs including polymer gel, polymer microsphere and surfactant is evaluated by means of conformance control and chemical flooding. Three-layer heterogeneous 3-D plate model is used for oil displacement experiment. The experimental results show that the combination slug sequentially composed of polymer gel, polymer microspheres and surfactant have the best oil displacement effect with the oil recovery increment by 21.2% after the first water flooding. In addition, using the best slug combination for two rounds flooding, the recovery factor increased by 28.2% compared with the first water flooding. This paper provides some new insights for enhanced oil recovery in strong heterogeneity reservoir.

Laboratory data integration and grading viscosity assessment for polymer flooding by simulation

Polymer flooding improves the mobility ratio by mainly increasing the injected water viscosity. Typically, these projects minimize the volume of polymer due to economic aspects since the polymer cost significantly affects operation expenditures. However, the injection of a single slug sometimes produces an abrupt viscosity transition at the slug tail, and the chase water forms fingers that can bypass the slug, destroying its integrity. Injecting gradually more dilute slugs mitigates viscous fingering and reduces polymer mass. The scarce field applications, scarce testing at laboratory scale, and the absence of simulations discussion drove the interest in the subject. This study implements and evaluates a numerical simulation by integrating laboratory scale data – bulk rheology, single- and two-phase core floodings – and then history matching graded viscosity core flooding. The results were compared using performance indicators and validated with three laboratory experiments from the literature. The experiments consist of one continuous injection core flood and two core floods using grading viscosity with similar polymer injected mass, one with two slugs and another with three polymer slugs. Experimental and simulated history data for oil recovery and cumulative water matched with less than 5% of normalized error. Events such as water and polymer breakthroughs were well represented. The performance indicators revealed the three slugs test showed the best polymer utility factor for oil/water and best injectivity. On the other hand, the two slugs test reached higher final incremental oil recovery. This work contributes to data integration and extended discussions necessary to enable tailoring and motivating applications of polymer viscosity grading, to save polymer mass and reduce the produced water.

The Performance of Engineered Water Flooding to Enhance High Viscous Oil Recovery

Low salinity/engineered water injection is an effective enhanced oil recovery method, confirmed by many laboratory investigations. The success of this approach depends on different criteria such as oil, formation brine, injected fluid, and rock properties. The performance of this method in heavy oil formations has not been addressed yet. In this paper, data on heavy oil displacement by low salinity water were collected from the literature and the experiments conducted by our team. In our experiments, core flooding was conducted on an extra heavy oil sample to measure the incremental oil recovery due to the injected brine dilution and ions composition. Our experimental results showed that wettability alteration occurred during the core flooding as the main proposed mechanism of low salinity water. Still, this mechanism is not strong enough to overcome capillary forces in heavy oil reservoirs. Hence, weak microscopic sweep efficiency and high mobility ratio resulted in a small change in residual oil saturation. This point was also observed in other oil displacement tests reported in the literature. By analyzing our experiments and available data, it is concluded that the application of standalone low salinity/engineered water flooding is not effective for heavy oil formations where the oil viscosity is higher than 150 cp and high oil recovery is not expected. Hence, combining this EOR method with thermal approaches is recommended to reduce the oil viscosity and control the mobility ratio and viscous to capillary forces.

Experimental and simulation study of surfactant flooding using a combined surfactant system for enhanced oil recovery

Oil recovery potential of surfactant flooding is restricted due to the inability of single surfactant to achieve ultra-low interfacial tension (IFT) and strong water-wet conditions. To overcome these limitations, surfactant mixtures are employed to achieve the desired enhanced oil recovery (EOR) properties. In this study, the efficacy of a combined bio and synthetic surfactants system as a potential means of enhancing oil recovery was examined. The surface, interfacial, and wettability alteration properties of biosurfactant, synthetic surfactant, glycerol, and their combined mixture were investigated. The results revealed that the combined surfactant system had a more pronounced effect on oil-water IFT and wettability alteration compared to the individual solutions separately. Ultralow IFT (0.005 mN/m) was obtainable using the combined surfactant system. The core flooding experiments conducted on Gray Berea sandstone cores using Assam crude oil showed that an additional 15–20% of original oil in place (OOIP) could be recovered with the combined surfactant system. Additionally, simulation studies showed that on a field-scale incremental oil recovery of 12–15% OOIP could achieve depending on the injection mode. Thus, the study revealed that through the unique combination of bio and synthetic surfactants with glycerol, a competent EOR fluid could be developed.

Functional characteristics and dominant enhanced oil recovery mechanism of polymeric surfactant

There are more than 40% remaining oil trapped in the reservoir in the mature oilfield even after second and tertiary recovery processes. High performance chemical agent was required for the trapped oil further mobilization. Polymeric surfactant was synthesized by grafting the active ground into the polymer skeleton. It has the advantages of surfactant polymer (SP) flooding and overcome the chromatographic separation during SP flooding. However, it is still unclear how the supramolecular molecular structure of polymeric surfactant affects its properties. Two kinds of polymeric surfactants named HB and HD with different molecular structures were characterized in this paper. Their molecular structure, static properties and enhanced oil recovery (EOR) efficiency were examined and compared via a series of experiments. The results showed that HD was dominated by amide group with hydrophobic association structure, and exhibited the supramolecular characteristics of space network; while HB mainly consisted by ring groups, showing a straight chain structure. HD featured with a better thickening, shear-resistance and salt-resistance ability, while HB can easily emulsify oil. In the microfluidic and three parallel core flooding experiments, HD both presented a higher recovery factor due to its good mobility control performance. Cluster remaining oil obviously declined and film-liked remaining oil slightly increased during HB and HD flooding stage. The incremental oil recovery of HD after water flooding was 26.6%, which was 5.5% higher than that of HB. This work indicates the molecular structure of spatial network is preferred in the design of polymer molecular structure towards EOR in the heterogeneous reservoir.

Preliminary Carbon Untilization And Storage Screening Of Oil Fields In South Sumatra Basin

Carbon utilization in oil fi elds as EOR project has becomes main issue nowdays. Therefore preliminary CO2-EOR screening has been done for the oil fi elds laid on South Sumatra Basin, where CO2 emission arise from a number different sources of activities in South Sumatra area. Around 103 oil fi elds and consisting 581 reservoirs have been analysis to select which of those fi elds fulfi ll CO2 injection criteria. The criteria applied of the selection are based on EOR Screening Criteria Revisited papers introducing by J.J Taber at. All. 1977. The results of the screening are categorized as miscible, immiscible and failed for CO2 injection. Afterward, CO2 storage and incremental oil recovery due to CO2 injection were calculated using equation normally used in the oil industries. The incremental oil recovery due to CO2-EOR has been assumed as high as 12% of OOIP at miscible process and only 5% for immiscible displacement. The calculation of CO2 storage is based on the ultimate primary recovery for each fi eld in addition of the additional recovery due to CO2-EOR. Both primary and tertiary recovery have been used as the basic of calculating the CO2 storage. The results of the screening whether reservoir categories in immiscible, miscible injection and failed to fulfi ll EOR-CO2 injection criteria can be summarized as follow: 18 fi elds immiscible, 77 miscible, and 7 failed. Total incremental oil recovery estimate from CO2-EOR is approximately 480.5 MMSTB. While the total CO2 storages estimate are about 70 MMton for voidage replacement due to production at ultimate recovery and 22 MMton at EOR-recovery, so the total CO2 storage is approximately 92 MMton.

Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms

Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or drawdown management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.

SmartWater based synergistic technologies for enhanced oil recovery

Enhanced oil recovery (EOR) technologies based on chemicals and solvents require significant volume of source injection materials, and have limited applicability in difficult environments and harsh reservoir conditions. Synergizing injection water compositions in terms of salinity and ionic content (SmartWater) with existing recovery methods can become a game changer to overcome these limitations.The main objective is to explore the synergistic effects of SmartWater as a potential optimization avenue for achieving more efficient and economic EOR applications. To achieve this objective, a range of multiscale experimental data from macro- to core-scale were analyzed to demonstrate and quantify the benefits of water chemistry synergies with different recovery methods. The multiscale experimental data analyzed comprised of polymer rheology, contact angles, core floods, foam stability and rheology, besides evaluating the zeta potential results obtained from surface complexation modeling (SCM).The dilute concentrations of polymer ranging from 250 to 500 ppm in SmartWater increased the injection water viscosities by 2 to 4 times to provide better mobility control for light oil recovery. The tailored water chemistry reduced the polymer consumption requirements by one-third (from 3000 ppm to 2000 ppm) and increased the oil recovery by 5–7% in polymer flooding processes used for viscous oil recovery. Synergizing water chemistry with surfactant-polymer flooding resulted in an incremental oil recovery of about 4% besides lowering the surfactant and polymer concentrations by 50% (from 2000 ppm to 1000 ppm). SmartWater has also been found to synergistically combine with carbonated waterflooding to increase the CO2 dissolved volumes by 25–30% for effectively lowering the pH and develop favorable wettability alterations towards water-wet conditions. The tailored water chemistry increased the foam stabilities by resulting in 2–3 times higher foam half-lifes in addition to raising the foam apparent viscosities by 1.5 times. SmartWater foams also increased the pressure drops in porous media by 50% to confirm higher foam apparent viscosities and more resistance to gas flow.The benefits of different SmartWater based synergistic EOR technologies demonstrated in this study can be significant. They can deliver higher oil recoveries in addition to lowering the volume requirements of different EOR agents such as chemicals and gas. These findings will have a practical impact to result in more practical, efficient and economical EOR projects in the field.

Wettability alteration and improved oil recovery in unconventional resources

The ultimate recovery factor in tight and shale resources is limited and is usually in the range of 5–10%. Although high-intensity fracturing and refracturing can increase recovery, an enormous amount of oil will remain in place, hence the desirability of enhanced oil recovery methods. Many of the shale reservoirs are oil-wet with negligible water uptake. By altering the wettability, water can spontaneously imbibe into the formation matrix, creating a counter-current flow that forces the oil out. Here, we assess the likelihood of increased oil recovery by modifying the fracturing-fluid composition (salinity and ion concentration) that transforms the formation wettability into a more water-wet state.Oil wetting of tight formations is usually controlled by the adhesion of oil droplets on the surface of clay minerals. When clay minerals are not predominant, the oil attached to carbonate minerals can significantly control rock wettability. In this study, we first identify the primary reactions that define the initial wettability of the rock depending on the formation mineralogy, formation water composition, and oil type. Second, we build a geochemical model considering the surface complexation of various minerals to mimic the wettability state of the reservoir. Third, we validate our method on zeta-potential, contact angle, and imbibition data from a previously published study using different fluids with different salinities. Finally, we present a mechanistic approach to model the wettability-alteration impact on spontaneous imbibition and compute the incremental oil recovery contributed by different fracturing fluid compositions.Based on the studied case, the oil adhesion to clay can be reduced by tuning the fracturing fluid salinity. The ionic concentrations of 2.5 wt % of NaCl and 5.0 wt % of CaCl2 induced the smallest contact angles of 44.7 and 51.2°. We observe that further brine dilution increases the contact angle. For example, distilled water shows the most oil-wet condition with a contact angle to 93.4°. We argue that the main factors that maximize water wetting for the reported optimum salinities are the contrast in the rock and oil surface potential and the sodium concentration. Spontaneous-imbibition simulations indicate that the low salinity fluids promote a change in water-oil capillary pressure, leading to increased water uptake in the cores and improved oil recovery compared to distilled water. The agreement between the developed model and experimental data implies that the wettability in shale and tight formations can be quantitatively predicted and regulated.

Wettability alteration process at pore-scale during engineered waterflooding using computational fluid dynamics

Engineered waterflooding modifies chemistry of injected brine to efficiently and environmentally friendly enhance oil recovery. The common practice of engineered waterflooding includes low salinity waterflooding (LSW) and carbonated waterflooding. Among these oil recovery methods, wettability alteration has been perceived as a critical physicochemical process for additional oil recovery. While extensive work has been conducted to characterize the wettability alteration, the existing theory cannot explain the conflict oil recovery between secondary mode (injecting engineered water at the very beginning of flooding) and tertiary mode (injecting engineered water after conventional waterflooding), where secondary engineered waterflooding always gives a greater incremental oil recovery than tertiary mode. To explain this recovery difference, a preferential flow channel was hypothesized to be created by secondary flooding, which likely reduces sweep efficiency of tertiary flooding. To test this hypothesis, computational fluid dynamic simulations were performed with finite volume method coupled with dynamic contact angles in OpenFOAM to represent wettability characteristics (from strongly oil-wet to strongly water-wet) at pore scale to quantify the role of pre-existing flow channel in the oil recovery at different flooding modes. The simulation results showed that secondary engineered waterflooding indeed generates a preferential flow pathway, which reduces recovery efficiency of subsequent tertiary waterflooding. Streamline analysis confirms that tertiary engineered waterflooding transports faster than secondary engineered waterflooding, implying that sweep efficiency of tertiary engineered waterflooding is lower than secondary engineered waterflooding. This work provides insights for a greater oil recovery at secondary mode than tertiary mode during engineered waterflooding at pore scale.

Worksheet Screening Of Co2 Eor Sequestration Potential In Indonesia

CO2 injection into subsurface with the purpose to increase incremental oil production had been popularized in 1970s in US. Nowadays, this type of EOR methods not only offers more oil but also utilizing reservoir as CO2 storage in the context of CO2 emission abatement. The objective of this research is to produce simple and efficient worksheet on EXCEL base in order to asses and screen out quickly the potential of implementation of CO2 EOR sequestration in depleted oil fields in Indonesia.Key elements of this worksheet comprise engineering aspect and economical aspect. A sequence workflow of technical performance of CO2 flooding was done using streamline simulator in which outstanding output from simulator needs robust data preparation and cautious parameter set up. For the case studied here, total incremental oil recovery at the end of the project is 4.52% from original oil in place (IOIP) or about 6.23 MMSTB. “Prophet” was used to simulate CO2 sequestration during CO2 EOR incorporating residual trapping. The amount of CO2 trapped in reservoir was acquired by subtracting the total injected CO2 with CO2 produced. The total capital expenditure for sequestration CO2 EOR studied here is estimated $48.3 MM. It is expected that $16.5 MM will be placed in service by 1st year with the remaining $31.7 MM to be placed in service by 2nd year. Annual average operating cost was estimated to be $5.4 MM. As for fiscal terms, the following assumptions have been incorporated into the economic evaluations: (1) FTP 10%, (2) Investment Credit 17%, (3) Contractor Oil Split 26.6018%, (4) Government Split 73.3982%, and (5) Tax 44%. The economic analyses were carried out based on the project life time 7 years and the sales of incremental oil amount 5.6 MMSTB with an assumption that price for oil was $68 per barrel based on monthly average OPEC Basket Price during April-09 until March-10. Economic results of the development with discount factor 7 percent as indicated has a Contractor DCF Rate of Return 53.3 percent, Contractor Net Present Value $31.3 MM, and revenue to the Government of Indonesia $188.2 MM. With this economic indicator, the project of Sequestration CO2 EOR is economically feasible. The developed worksheet enables to do quick judgment on the viability a CO2 EOR sequestration project hence make it easier to someone who wants to screen out a large number of reservoirs rather than using detailed numerical simulator. It will much more saved time and decrease works intensity.

Numerical Trend Analysis for Factors Affecting EOR Performance and CO2 Storage in Tight Oil Reservoirs

Improved oil recovery from tight oil reservoirs to fulfill the fossil fuel requirements and the CO2 storage to meet the net carbon zero objectives are the two motivations of this work. CO2 is a major anthropogenic greenhouse gas and its emission to our plants’ atmosphere is hazardous, particularly causing global warming. Therefore, its injection in the sub-surface oil-bearing formations not only improves the oil recovery but also reduces the carbon footprint from the planet. In this study, a mechanistic numerical simulation model is built using typical U.S. tight oil reservoir rock and fluid properties. The reservoir model is equipped with a hydraulically fractured single horizontal well that is subjected to multiple sensitivities using the huff-n-puff technique. Detailed CO2 trapping and diffusivity mechanisms at the nanopore scale are discussed that numerically define the CO2 solubility in formation oil and it’s trapping phenomenon into the nanopore spaces. The results show that CO2 injection works predominantly to achieve significant incremental oil recovery. Also, the reservoir with lighter in-situ fluid composition and higher reservoir pressure further enhances the oil recovery due to improved diffusivity and the solubility of CO2 into the reservoir fluid. It is also found that the increased number of huff-n-puff cycles and the incremental CO2 injection volume in each cycle not only enhance the oil recovery performance but likewise help to trap a larger volume of CO2 into a reservoir. A few diagnostic contour plots are also presented in this study to demonstrate the simultaneous effect of multiple hydraulic fracture parameters and the CO2 injection volume for the directional EOR and CO2 trapping performance. The findings of this study can help for a better understanding of designing EOR operations in tight oil reservoirs to achieve both goals concurrently.

Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir

The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.

Visual investigation of the effect of clay-induced fluid flow diversion on oil recovery, as a low-salinity water flooding mechanism

Low-salinity water flooding (LSWF) is an EOR method applicable to both sandstone and carbonate reservoirs. In recent years, LSWF has become an attractive technique but still some uncertainties concerning the governing mechanisms exist in studies. Mechanisms such as wettability alteration, osmosis, and fluid flow diversion by fines migration are proposed to explain the incremental oil recovery by LSWF in sandstones. Flow diversion is still being debated as to whether this mechanism works and, if it does, to what extent. This mechanism occurs due to clay swelling and fines migration, which results in pores blockage, diversion of the fluid flow to unswept areas, and enhanced oil displacement. Hence, the presence of clays is claimed to be a necessity for the success of LSWF in sandstone reservoirs. Here we proposed a new approach to study effects of different mechanisms of LSWF alone and in combination of each other using micromodels to track fluid flow diversion and the reason behind it and its subsequent benefits in case of oil recovery, visually. In this paper micromodel tests in different wetting and clay presence conditions were designed and conducted to investigate the standalone fluid flow diversion mechanism and the combination of it with wettability alteration and osmosis effects during LSWF. Tests conducted in water wet and oil wet states showed that the presence of clays is not the main criterion for activating the LSWF effect and the initial wettability is more critical. Our studies showed that the fluid flow diversion share in oil recovery is only 30% of the total incremental oil displaced by LSWF, while about 70% of the oil is produced by wettability alteration and osmosis mechanisms. It is reasonable to say that, although flow diversion is an active mechanism, it is not the dominant one and on the other hand wettability alteration is.

Effects of thief zones on displacement efficiency: Microfluidic pore-scale and conformance control analysis

Thief zones are regions with high permeability, usually formed in mature or depleted reservoirs after water flooding, which can further reduce the overall recovery during subsequent EOR stages. While existing conformance control solutions alleviate the impact of thief zones, selecting an optimal solution based on current laboratory methods is challenging, since current methods fail to isolate the impact of thief zones, lack tight control of initial conditions, and use long evaluation times as well as large sample volumes. In this study, a microfluidic analogue is designed and fabricated with multiple permeability regions, representing thief zones in a reservoir, to evaluate the performance of polymer flood in a porous medium. The analogue contains four connected and distinct heterogenous zones of different permeability, in which the fluid dynamics and relevant conformance control are resolved during secondary and tertiary polymer floodings, once thief zones are apparent. The secondary water flooding did not exhibit an efficient displacement, with fingering and by-passing effects predominantly observed in higher permeability zones and minor oil displacement in the lowest permeability zone. Despite the fingers created by water flooding, polymer flooding showed much higher displacement efficiency throughout all four zones, resulting in significant incremental oil recovery. The secondary polymer flooding also produced more oil than the secondary water flood due to improvement in the mobility control. Lastly, pore-scale mechanisms such as viscous cross-flow between zones was observed during the polymer flood.