Technology Focus: EOR Performance and Modeling (January 2011)

As a novel, economic, and environmentally friendly enhanced oil recovery (EOR) and carbon sequestration technology, non-chemical CO2 microbubble (MB) has potential applications in low permeability reservoirs. At present, there are only few studies available focusing on non-chemical MB EOR in low permeability reservoirs. Previous studies mainly focused on its storage efficiency in saline aquifers, and more research is needed to fully understand the EOR mechanism in low permeability. In this paper, the EOR performance and its mechanisms of non-chemical CO2 MB in low permeability reservoirs are experimentally investigated. For comparations, a series of CO2-based method were also included, such as CO2 injection, water altering gas and conventional foam. The results demonstrate that CO2 MB has competitive EOR performance to conventional foam injection. The increment oil recovery of microbubbles on 2.23×10−3 μm2 and 9.46×10−3 μm2 rock samples are 11.74% and 19.59% original oil in place (OOIP), respectively. In parallel coreflood experiment, the MB increased oil recovery by 10.73% and 17.92% of OOIP on core samples with the permeability of 9.43×10−3μm2 and 2.25×10−3μm2, respectively. The CT imaging shows that the core sample has lots of residual oil zones due to microheterogeneity. After MB flooding, the average residual oil saturation of the core sample is reduced from 42.15% to 33.5% and the horizontal and vertical residual oil zones are eliminated. The results of this study comprehensively evaluated the feasibility and EOR performance of non-chemical CO2 MB in low permeability reservoirs. Overall, the results suggest that non-chemical CO2 MB is an efficient EOR method which has better displacement efficiency and conformance control ability than other CO2-based non-chemical EOR method (CO2 injection and WAG).

The latest oil price decline simply increases the demand for enhanced oil recovery (EOR) and pushes research developers to keep improvements in oil recovery. The goal is always to recover as much oil as possible at the lowest possible cost. Low-salinity water flooding (LSWF) is an EOR method that operates at a lower cost than other EOR methods, which makes it a preferred area of interest for oil industry economists, who continue to call for EOR costs to come down. The objective of this study was to test the ability of low-salinity waterflooding to improve oil recovery from low permeability sandstone reservoirs. Four types of tests were conducted: imbibition, interfacial, core flooding, and zeta potential tests. Three key factors were studied: salinity of the injected water, type of salt, and aging time. Their influence on the amount of oil recovery, stabilized injection pressure, pH, and permeability reduction was determined. Berea sandstone was used in all experiments. Sodium chloride (NaCl) and calcium chloride (CaCl2) were used to prepare the brine. The imbibition test and core flooding results showed that the oil recovery increased as brine concentration decreased for both sodium chloride and calcium chloride. Sodium chloride resulted in higher oil recovery than calcium chloride at a certain salinity in both imbibition and core flooding tests. The oil recovery factor results during the second water flooding cycle (after aging for 24 hrs.) showed more oil recovered during low salinity waterflooding. The stabilized inaction pressure was higher for CaCl2 than NaCl injection at certain flow rate and brine concentrations. Effluent pH values became more basic during low salinity water flooding for both sodium and calcium chloride. The zeta potential results showed that decreasing the salinity of injected water resulted in a decrease of the zeta potential value for both injection cycles, before and after aging for 24 hours. Results also imply Low- salinity water flooding redistributes the flowing paths by releasing sand particles and some fine minerals causing the flow path to narrow. Thus, low salinity water flooding can create a new streamline (fluid flow diversion) and improve both displacement and sweep efficiency.

Summary Shallow reservoirs on the Alaska North Slope (ANS), such as Ugnu and West Sak-Schrader Bluff, hold approximately 12 to 17 × 109 barrels of viscous oil. Because of the proximity of these reservoirs to the permafrost, feasible nonthermal enhanced oil recovery (EOR) methods are highly needed to exploit these oil resources. This study proposes three hybrid nonthermal EOR techniques, including high-salinity water (HSW) injection sequentially followed by low-salinity water (LSW) and low-salinity polymer (LSP) flooding (HSW-LSW-LSP), solvent-alternating-LSW flooding, and solvent-alternating-LSP flooding, to recover ANS viscous oils. The oil recovery performance of these hybrid EOR techniques has been evaluated by conducting coreflooding experiments. Additionally, constant composition expansion (CCE) tests, ζ potential determinations, and interfacial tension (IFT) measurements have been conducted to reveal the EOR mechanisms of the three proposed hybrid EOR techniques. Coreflooding experiments and IFT measurements have been conducted at reservoir conditions of 1,500 psi and 85°F, while CCE tests have been carried out at a reservoir temperature of 85°F. ζ potential determinations have been conducted at 14.7 psi and 77°F. The coreflooding experiment results have demonstrated that all of the three proposed hybrid EOR techniques could result in much better performance in reducing residual oil saturation than waterflooding and continuous solvent flooding in viscous oil reservoirs on ANS, implying better oil recovery potential. In particular, severe formation damage or blockage at the production end occurred when natural sand was used to prepare the sandpack column, indicating that the natural sand may have introduced some unknown constituents that may react with the injected solvent and polymer, resulting in a severe blocking issue. Our investigation on this is ongoing, and more detailed studies are being conducted in our laboratory. The CCE test results demonstrate that more solvent could be dissolved into the tested viscous oil with increasing pressure, simultaneously resulting in more oil swelling and viscosity reduction. At the desired reservoir conditions of 1,500 psi and 85°F, as much as 60 mol% of solvent could be dissolved into the ANS viscous oil, resulting in more than 31% oil swelling and 97% oil viscosity reduction. Thus, the obvious oil swelling and significant viscosity reduction resulting from solvent injection could lead to much better microscopic displacement efficiency during the solvent flooding. The ζ potential determination results illustrate that LSW resulted in more negative ζ potential than HSW on the interface between sand and water, indicating that lowering the salinity of injected brine could result in the sand surface being more water-wet, but adding polymer to the LSW could not further enhance the water wetness. The IFT measurement results show that the IFT between the tested ANS viscous oil and LSW is higher than that between the tested viscous oil and HSW, which conflicts with the commonly recognized IFT reduction effect by LSW flooding. Thus, the EOR theory of the LSW flooding in our proposed hybrid techniques may be attributed to low-salinity effects (LSEs) such as multi-ion exchange, expansion of electrical double layer, and salting-in effect, while water wetness enhancement may benefit the LSW flooding process to some extent. The LSP’s viscosity is much higher than the viscosities of LSW and solvent, so LSP injection could result in better mobility control in the tested viscous oil reservoirs, leading to improvement of macroscopic sweep efficiency. Combining these EOR theories, the proposed hybrid EOR techniques have the potential to significantly increase oil recovery in viscous oil reservoirs on ANS by maximizing the overall displacement efficiency.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 169071, ’CO2 Low-Salinity Water Alternating Gas: A New Promising Approach for Enhanced Oil Recovery,’ by Cuong T.Q. Dang, SPE, University of Calgary; Long X. Nghiem, SPE, Computer Modelling Group; Zhangxin Chen and Ngoc T.B. Nguyen, SPE, University of Calgary; and Quoc P. Nguyen, SPE, The University of Texas at Austin, prepared for the 2014 SPE Improved Oil Recovery Symposium, Tulsa, 12-16 April. The paper has not been peer reviewed. Significant advantages have been seen from combining low-salinity waterflooding (LSW) with other enhanced-oil-recovery (EOR) techniques. This paper proposes a novel concept of low-salinity-water-alternating- gas (LSWAG) injection with CO2 under CO2-miscible-displacement conditions. While LSW is an emerging EOR method based on alteration of wettability from oil-wet to water-wet conditions, water-alternating-gas (WAG) injection is a proven method for improving gas-flooding performance by controlling gas mobility. Therefore, LSWAG injection promotes a synergy of the mechanisms underlying these methods that enhances oil recovery further. Introduction LSW is receiving increasing attention in the oil industry and is currently identified as an important EOR technique because it shows more advantages than conventional chemical EOR methods in terms of chemical costs, environmental impact, and field process implementation. Although the benefits of LSW have been realized, the mechanism for incremental oil recovery by LSW is still a topic that is open for discussion. Among the proposed hypotheses, wettability alteration toward increased water-wetness during LSW is accepted widely as the cause for the EOR. It has been found experimentally that low-salinity brine has a significant effect on the shape and the endpoints of the relative permeability curves, resulting in a lower water relative permeability and higher oil relative permeability. The mechanisms of wettability alteration because of ion exchange and geochemical reactions have been implemented successfully in a compositional simulator for modeling LSW. Excellent agreements between simulation results and important measurements from coreflood experiments and pilot observations were obtained with this modeling approach.

Visual investigation of the effects of clay minerals on enhancement of oil recovery by low salinity water flooding

Simulation and evaluation on enhanced oil recovery for steam huff and puff during the later phase in heavy oil Reservoir—A case study of block G in Liaohe oilfield, China

Carbonate reservoirs hold vast oil reserves, but their complex properties make traditional enhanced oil recovery (EOR) methods challenging. This study explores the application of low-salinity water flooding (LSWF) as a novel EOR method for India’s largest offshore carbonate oil field. Conventional EOR techniques were deemed unsuitable due to reservoir heterogeneity, pressure decline, high temperature, and the offshore location. Favorable factors for LSWF included successful seawater flooding history, medium-weight crude oil, and existing infrastructure. Following core flooding experiments demonstrating a 6–16% increase in oil recovery, a multi-pronged evaluation process was implemented. Single-well chemical tracer tests (SWCTT) and reservoir simulations confirmed the potential of LSWF. A specific target area was chosen based on reservoir characteristics, production data, and available facilities. Simulations predicted a 1.5% incremental oil recovery using diluted seawater (25% salinity) at 30% pore volume injection. After a positive techno-economic analysis, the first offshore LSWF project in India was completed within 3 years. Initial monitoring results are encouraging. This study highlights the successful journey of LSWF from concept to field deployment in a challenging carbonate reservoir, showcasing its potential for revitalizing such fields. Furthermore, this work provides valuable data relevant to Indian offshore environments, where factors like salinity, mineralogy, and crude oil composition pose unique challenges compared to other LSWF applications. These detailed data fill a critical gap in the existing literature.

Chemical Enhanced Oil Recovery (EOR) techniques have recently seen a new revival owing to high oil consumption and favorable conditions that drove the oil price in a range where use of chemical is becoming economically viable. Advancements in technologies and understanding of past failures also contribute to this revival. However it appears that there is a lack of a comprehensive tool which allows exploration and assessment of combined chemical EORs at the field scale, and which can be driven dynamically to simulate realistic field applications. In this paper we propose a set of integrated models for polymer-brine, surfactant, alkaline and foam including ions exchange for calculating effective salinities. These models can be driving by a set of flexible field management functionalities which allow a dynamic optimization of the use of the chemicals to maximize oil contact and ultimately its recovery. A work flow to assess the balance of viscous, capillary and gravity forces involved in the EOR process is proposed to pre-screen the type of chemicals needed to modify the force balance. This approach will precede and guide the dynamic optmization. Introduction Exploration for hydrocarbons is reaching global frontiers, and the short- and long-term challenges will be to maximize recovery from existing fields. As an important subset of the enhanced oil recovery (EOR) offering, chemical EOR techniques have developed as an economical and viable alternative for increasing oil recovery. Their success though relies heavily on a thorough understanding and ne-tuning of the chemical interactions between the injected chemicals, the fluids in place, and the rock. These interactions eventually determine optimal injection and production scenarios and ultimately the total increment in oil recovery. Modeling of processes such as alkaline-surfactant-polymer (ASP) flooding, low salinity water flooding, solvent flooding, and foam injection for gas mobility control require a detailed description of the EOR agent interaction with the rock and reservoir fluids. This includes flexible modeling of solution viscosities, non-Newtonian behavior, permeability reductions due to adsorption (e.g. in polymer flooding), capillary de-saturation effect due to decreasing oil-water interfacial tension, chemical losses to the formation due to adsorption, change of wettability characteristics, and chemicals degradation, to mention just a few. However, the success and cost-effective design of EOR projects relies on the ability to model complex combinations of these processes in realistic reservoir settings while taking into account limitations in surface equipment, project economics, and consistency in the numerical solution. Being able to monitor the chemicals within the reservoir and being able to adapt the injection and production schedule automatically become key elements in optimizing chemical EOR processes.

Conventional enhanced oil recovery (EOR) approaches are inefficient in unconventional reservoirs. This paper provides a novel approach to enhance oil recovery from unconventional oil reservoirs through synchronous inter-fracture injection and production (SiFIP) and asynchronous inter-fracture injection and production (AiFIP). The compartmental embedded discrete fracture model (cEDFM) is introduced to simulate complex fracture geometries to quantitatively evaluate the performance of SiFIP and AiFIP. EOR performances using multiple producing methods are investigated (i.e., depletion, fluid flood, fluid Huff and Puff, SiFIP, and AiFIP). Higher cumulative oil production rates can be achieved by AiFIP and SiFIP. AiFIP yields the highest oil recovery factor, two times higher than depletion. Compared with SiFIP, AiFIP may be a preferred method when CO2/water resources are short. The impacts of fracture and injection parameters on oil production are discussed. The feasible well completions for AiFIP and SiFIP are provided. AiFIP (CO2) achieves the best EOR performance among different producing methods. This paper demonstrates the feasibility of SiFIP and AiFIP to improve oil recovery. The proposed methods improve flooding performance by transforming fluid injection among wells to among hydraulic fractures from the same multi-fractured horizontal well (MFHW), which is a promising EOR approach in unconventional oil reservoirs. The proposed EOR method (AiFIP-CO2) can improve oil recovery and mitigate the emission of CO2 as well as reduce the waste of water resources.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Surfactant-polymer (SP) flooding has been demonstrated to be an effective method to recover oil in the enhanced oil recovery (EOR) stage when water flooding is no longer relevant. Theoretically, adding surfactant causes the reduction of the interfacial tension between oil and water in pores, therefore reducing the residual oil saturation, whereas the sweep efficiency will be significantly improved by the polymer injection as a result of proper mobility control. With regard to the well patterns, water flooding has demonstrated a high productivity in horizontal wells. Recently, other EOR processes have been increasingly applied to the horizontal wells in various well patterns. In this study, the efficiency of SP flooding applied to horizontal wells in various well configurations is investigated in order to select the best EOR performance in terms of either a technical or economical point of view. Furthermore, the reservoir is assumed to be anisotropic with four different layers that have same porosity but different permeability between each layer. The study figures out that, the utilization of a horizontal injector and producer always gives a higher oil production in comparison with the reference case of a conventional vertical injector and producer; however, the best EOR performances that demonstrate the higher oil recovery and lower fluid injected volume than those of the reference case are achieved when the production well is located in bottom layers and parallel with the injection well at a distance. While the location of producer decides oil productivity, the location of injector yet affects the uniformity of fluids propagation in the reservoir. A predefined feasibility factor is also taken into consideration in order to reject the infeasible cases that might give a high oil production but require a higher injected volume than the reference case. This factor is used as an economic parameter to evaluate the success of the EOR performance. The simulation is carried out in a quarter five-spot pattern reservoir with the support of the Computer Modeling Group (CMG) simulator. Understanding the predominant EOR performance of SP flooding in horizontal wells will help to select the best plan to obtain the highest oil recovery when considering economic issues.

Mechanistic modeling of low salinity water flooding

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 109965, "Low- Salinity Waterflooding To Improve Oil Recovery - Historical Field Evidence," by Eric P. Robertson, SPE, Idaho National Laboratory, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed. Crude-oil/water/rock interactions can lead to large variations in the displacement efficiency of waterfloods. Laboratory waterflood tests and single-well tracer tests in the field have shown that injection of low-salinity water can increase oil recovery, but testing on a multiwell-field scale has not yet been undertaken. Three Minnelusa-formation waterfloods in the Powder River basin of Wyoming were compared on the basis of salinity of the formation and injection water and of reservoir characteristics. Introduction Different wetting states of crude-oil, water, and rock ensembles can yield different oil recoveries from laboratory-waterflood tests. The wetting state, or wettability, of a rock/fluid system can be altered. In the laboratory, wettability can be altered by changing the crude-oil composition, changing the temperature while aging the rock and crude oil, or by changing the temperature during water displacement. Also, water composition can have a significant effect on wettability and on oil recovery. Therefore, cases may exist in which attention to injection-water composition could increase oil recovery, and, likely, increase the economic profitability of a waterflood. An optimal composition of dissolved solids in the injection water may exist that would yield the highest oil recovery. The composition could involve many variables with respect to ionic composition and concentration, but current knowledge of how and when water composition can be manipulated to increase oil recovery is limited. Several examples of improved recovery by injecting low-ionic-strength brine have been reported for both outcrop- and field-core samples. Fig. 1 shows the potential for increased oil recovery from low-salinity waterflooding. These corefloods were performed on two cores from the CS reservoir under identical conditions except for the composition of the injected water. The conditions necessary for improved recovery, such as the type of crude oil and rock, composition of the formation and injected waters, and initial water saturation, still are not understood fully. The crude-oil/water/rock interactions that determine displacement efficiency are highly complex. Nevertheless, laboratory observations were sufficiently encouraging to justify more studies aimed at field application. The Idaho National Laboratory (INL) through funding from the US Department of Energy searched historical waterflood records for anecdotal evidence of increased oil recovery resulting from the injection of lower-salinity water to displace oil in reservoirs with higher-salinity initial formation water. The objective was to research and compare historical field data and to compare waterflood responses from low-and high-salinity injection waters.

One of the well-known problems in CO2 enhanced oil recovery (EOR) processes is the poor sweep efficiency due to the high viscosity contrast between CO2 and the reservoir resident fluids (oil and brine). CO2-augmented waterflooding or carbonated water injection (CWI) could lessen this problem. As CO2 is dissolved in and transported by the flood water, CO2 is more evenly distributed within the reservoir thus improves the sweep efficiency. This is beneficial to watered-out oil reservoirs where high water saturations could adversely affect the performance of the conventional CO2 injections. CWI also provides a very safe method for storing large quantities of CO2 as a dissolved phase in oil reservoirs. This paper presents the results of our experimental and numerical investigations on the oil recovery and CO2 storage benefits of CWI in secondary and tertiary recovery modes through a series of coreflood experiments and detailed compositional simulation. The experiments were performed in a water-wet Clashach core with decane as well as restored North Sea reservoir core with stock tank crude oil and seawater at reservoir conditions. The experimental results demonstrate that CWI in both secondary and tertiary recovery modes can improve the oil recovery above the plain waterflooding. 45-51% of the injected CO2 was stored in the core at the end of the coreflood tests indicating the high potential of CWI not only for EOR but also as a CO2 storage injection strategy. Results of the corefloods were used to assess the capabilities and limitations of a commercial compositional flow simulator in modelling the CWI process. The simulation results show that diffusion should be taken into account to properly model the CWI process at the core scale. Using the commercially available reservoir simulators with the instantaneous equilibrium and complete mixing assumptions would lead to inaccurate evaluation of CWI process at this scale of interest.

Microbial Enhanced Oil Recovery Field Pilot in a Waterflooded Reservoir H. Yonebayashi* and K. Ono*, Japan National Oil Corporation; H. Enomoto* and T. Chida*, Tohoku University, C-X. Hong, China Jilin Province Oilfield Administrative Bureau and K. Fujiwara, Kansai Research Institute Abstract Japan National Oil Corporation (JNOC) / Technology Research Center (TRC) has been studying the Microbial Enhanced Oil Recovery (MEOR) process which makes effective use of microorganism's metabolism since 1987. Now, JNOC/TRC is planning a field trial to advance our MEOR study to the next stage. This paper describes the feasibility study of the field test. As a target of MEOR application, a shallow oil field in China which has been under waterflood for over 20 years has been selected. At first, the target reservoir was investigated and adaptabilities of TRC's microorganisms to the field were tested to select candidate microorganisms for injection. The tested TRC's microorganisms were E. cloacae TRC-322, B. subtilis TRC-4118, B. subtilis TRC-4 126, B. licheniform is TRC-18-2-a, B. licheniformis JF-2, B. licheniformis SP-018 and E.cloacae TU-7A which have been especially screened as effective gas, acid, surfactant and/or polymer producers through basic laboratory tests. In the former investigation of the reservoir, a new technique, Polymerase Chain Reaction (PCR) established in the sphere of gene engineering was applied to the study to make clear distinction among reservoir-originated microorganisms. Effects of reservoir conditions, namely, reservoir water, temperature, nutrient, additives and indigenous microorganisms in the reservoir, on the microbial growth and their metabolism were tested to select candidate microorganisms for the field application. Finally, four microorganisms (i.e. TRC-322, TRC-4118, TRC-18-2-a and TU-7A) were selected for the field trial through these compatibility tests followed by flooding tests. Additional oil recovery amounted to approximately 15% of waterflood residual oil using TRC-322, TRC-4118 and TRC-18-2-a on the average. The field trial will start in middle of 1997. The objectives in this test are two fold. One is to validate the laboratory results which have been accumulated. The other is to investigate most predominant microorganisms (i.e. most effective ones on oil recovery), most effective metabolites and/or cause of obstruction of microbial activity. Introduction The oil production from applications of various Improved Oil Recovery (IOR)/Enhanced Oil Recovery (EOR) processes has been increasing steadily with the exception of a short recess during 1992-1994. It appears that this upward trend of EOR oil production will continue in the future, because the current worldwide oil-requirements are increasing. Moreover, due to the rapid economic growth in Asia, it is anticipated that the oil-demands will rise substantially in this region. Hence, it is necessary to increase the oil production. The IOR/EOR processes are recognized as one of solutions to cope with such situation, because the discovery of new big oilfield is becoming rare in recent years. Therefore, the development of the IOR/EOR techniques (redevelopment and stimulation technologies) to produce additional oil must be boosted to supply the future oil-requirements. We recognize microbial EOR process to be one of the effective options among various IOR/EOR methods to redevelop the waterflooded reservoir. Therefore, research on MEOR has been conducted at JNOC/TRC. TRC's research is especially focused on the in-situ process, in which gas production increases pressure and swells oil, polymer production controls mobility and/or surfactant production decreases interfacial tension, TRC has been searching microorganisms which have useful abilities (i.e. surfactant polymer, gas and/or acid productivity) for oil recovery. Up to now, about 500 microorganisms have been gathered and many talented ones have been selected through screening. In addition, flooding experiments have been carried out to evaluate their effects on oil recovery using strains which yielded excellent results in laboratory tests. It was necessary for TRC's MEOR study to move the phase of research to a field application. P. 451^