Browsing by Subject "Enhanced oil recovery"

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An investigation of viscoelastic polymer flooding in high permeability sandstones
(2019-08) Jin, Julia Liu; Balhoff, Matthew T.; Mohanty, Kishore Kumar
Recovery of oil is the key consideration of oil production in underground reservoirs. The correlated decline in oil discoveries and increase in demand for oil have created a scenario in which enhanced oil recovery (EOR) technologies have become increasingly necessary to compensate for the growing energy demand. Polymer flooding has been used as one EOR technique to increase oil recovery. Several authors have observed reduction of residual oil in porous media using polymers that are viscoelastic. Five coreflood experiments were completed using aqueous hydrolyzed polyacrylamide (HPAM) and scleroglucan (EOR-grade) polymer solutions. HPAM polymers were solubilized in low salinity brine which created viscoelastic solutions. All experiments were completed in high-permeability (>1000mD) Bentheimer and Boise sandstones. Two Bentheimer cores were chemically treated to be considered oil-wet. Three other water-wet Boise cores were also used. All experiments were completed using light (4-6 cP) oil. The elastic polymer floods were formulated so that they would have high relaxation times, and therefore high Deborah numbers. Each elastic flood was followed by an inelastic polymer flood with a similar viscosity. The Deborah number for the inelastic polymer floods were less than or close to 1. Following the successful experiments using alternating elastic and inelastic polymer floods in Bentheimer sandstones, these experiments were conducted in different mediums to see if this phenomenon could be replicated under different circumstances. Experiment #1 replicated previous work completed using viscoelastic polymers and alternating elastic and inelastic floods. The results in coreflood #1 showed extremely promising results in the comparatively more heterogeneous Boise sandstone. After alternating between elastic and inelastic polymer floods, the residual oil saturation decreased to lower than 6%. The viscoelastic polymer floods following a waterflood decreased residual oil saturation. In four of the five experiments, the residual saturation after viscoelastic polymer floods closely matched the predicted saturation given by the Elastic Desaturation Curve (EDC) developed by Qi (2018). Except for one flood, the actual experimental S [subscript orp] values were within 1-3% of the predicted S [subscript orp]
Analysis of wastewater injection and prospect regions for induced seismicity in the Texas Panhandle, USA
(2020-05-06) Acevedo, Juan Pablo; Young, Michael H.; Scanlon, Bridget R.
Subsurface injection of wastewater co-produced alongside oil and gas (O&G) has been linked to an increasing number of earthquake events throughout the southern mid-continent of the United States. In Texas, the average count of seismic events per year have risen over the past decade. This study aims to compare injection of produced water into the subsurface and increased number of earthquakes in the Panhandle Region of Texas. For this study, saltwater disposal and enhanced oil recovery through underground injection control (UIC) wells in the Texas Panhandle were analyzed from 1983-2018. During this same period, a total of 64 earthquakes of M ≥ 2.5 were recorded. The average earthquake rates increased from 1.21 events per year (1983-2007) to 3.50 events per year (2008-2018). A total of 1,926 active UIC wells in the Texas Panhandle were identified from the Railroad Commission of Texas database during the study period. This research identified 54 geologic stratigraphic formations present in the region and focused on the 34 target formations into which wastewater was injected. Cumulative UIC volumes were found to be localized by geographic regions and geologic formations, where a total of 2.26 billion barrels (Bbbls, where 1 barrel = 159 liters) of wastewater were injected. Approximately 87% of the total disposal volume (1.96 Bbbls) was injected into seven geologic formations, including the igneous Precambrian basement; another 27 formations received less than 100 million barrels (MMbbls) each. Monthly UIC rates in the Panhandle fluctuated in time, similar to overall O&G industry activity. From this analysis, 61% of earthquake events are considered to be possibly or probably induced by a combination of UIC and O&G practices. Additionally, this research identified regions at risk of potentially hosting future earthquakes induced by current UIC and O&G operations. Understanding how and where UIC practices and O&G operations are affecting seismicity rates in the State of Texas can allow researchers and regulators propose strategies to reduce or mitigate negative externalities such as induced seismicity.
Aqueous formate solution for geological carbon storage : numerical simulation and geochemical interaction studies
(2023-05-04) Oyenowo, Precious Olufemi; Okuno, Ryosuke, 1974-; Mirzaei-Paiaman, Abouzar
Carbon storage in geologic formations has been considered an important technology that reduces the carbon intensity of fossil fuels-based industrial processes. Carbon capture and storage (CCS) conventionally uses carbon dioxide (CO₂) as a carbon carrier. However, various shortcomings of the conventional CCS are related to the physical properties of CO₂, such as low carbon density at low to moderate pressure, low mass density, low viscosity, immiscibility with water, and corrosivity. In particular, CO₂ injection often results in inefficient use of pore space in the formation under subsurface heterogeneities. This report is centered on the novel idea of using a formate solution as an aqueous carbon carrier for geologic carbon storage. Formate is the conjugate base of formic acid. Formate can be produced from CO₂ via electrochemical reduction (CO₂ ECR). The CO₂ ECR technology is not yet industrialized, although it has been substantially improved over the past few years in the energy transition with the current technology readiness level of 5 to 6. The cost of formate produced industrially using the technology is unknown. We measured the viscosities and densities of formate solutions in brine, over a range of formate concentrations and temperatures. The measured data were used in numerical reservoir simulations of formate injection: (i) into an aquifer, and (ii) into an oil reservoir. Compared to simulations of CO₂ injection using the same reservoirs, results consistently showed that the formate injection case resulted in more stable fronts of oil and water displacement. The more stable fronts yielded the oil recovery and carbon storage that were insensitive to the injectant breakthrough. Cost-revenue analysis using the simulation results showed the formate breakeven cost for the oil reservoir case was within the literature estimates of the cost of formate production via CO₂ ECR. The results support the necessity of research and development for efficient CO₂ ECR systems. Geochemical interaction studies were carried out to understand the effect of formate injection (at concentrations up to 30-wt%) on carbonate rock, and the effect on the rock wettability. Experimental data from Amott wettability tests and core floods with limestone cores were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of calcite dissolution increased with increasing formate concentration in a NaCl brine even with an initially neutral pH. Geochemical modeling indicated that the increased calcite dissolution could be caused by the formation of calcium formate complexes that reduced the activity coefficient of the calcium ion and drove the calcite dissolution. The Amott test results and history matching of the core flooding data showed that high-concentration formate solutions rendered the initially oil-wet core to a more water-wet state.
Aqueous solution of ketone solvent for enhanced oil recovery in tight reservoirs
(2021-05-07) Wang, Mingyuan, 1991-; Okuno, Ryosuke, 1974-; Lake, Larry W.; DiCarlo, David; Espinoza, D. Nicolas; Leung, Juliana Y.
Horizontal drilling and multi-stage hydraulic fracturing have made it possible to recover oil from tight formations at economically feasible production rates. However, tight oil reservoirs often show a rapid decline in the production rate. Primary recovery factors in tight reservoirs are typically smaller than 10%. There is a critical need for enhanced oil recovery in tight reservoirs. Most tight oil reservoirs are originally intermediate- to oil-wet. Wettability alteration agents have been studied to facilitate water imbibition into tight rock matrices to enhance oil recovery. However, many factors affect the efficacy and efficiency of enhanced oil recovery by wettability alteration agents. The conventional wettability modifiers, such as surfactants, decrease the interfacial tension between the aqueous and oleic phases, which tends to limit the imbibition rate. The performance of wettability modifiers also depends on their mass transfer from the fracture to the matrix. However, the mass transfer of components between the fracture and the matrix has not been studied quantitatively in the literature. In addition, initial water saturation in the matrix, the concentration of wettability modifier in the injection fluid, and the injection/production pressures also affect the efficacy and efficiency of enhanced oil recovery by wettability alteration agents. This research aims to identify a practical solvent that can alter rock wettability without affecting interfacial tension and transfer efficiently from fracture to matrix. In addition, the effect of initial water saturation on enhanced water imbibition and the impact of the chemical concentration of the injected aqueous solution is investigated. In this research, we identified 3-pentanone, a symmetric dialkyl ketone, can act as a wettability alteration agent without affecting the interfacial tension between the aqueous and oleic phases. It is conceivable that the wettability change caused by 3-pentanone is related to the polar-polar interaction between 3-pentanone molecules and the calcite surface. This interaction may reduce the polar-polar interaction of the carboxylate group of naphthenic acids in oil with the calcite surface. Next, we compared 3-pentanone with a common wettability modifier, a surfactant. The dynamic imbibition experiments demonstrated that 3-pentanone was more efficient in transferring from a fracture to the surrounding matrices than the surfactant. Results indicated that an optimal process with a wettability modifier would have a large imbibed fraction to rapidly enhance the oil displacement by brine in the matrix. Then, we demonstrated that the 3-pentanone solution increased the oil recovery from the shale matrix in comparison to the injection brine through huff-n-puff experiments. Last, we developed a new method for reliable determination of saturation pressure from constant-mass expansion data even when the total compressibility of the fluid does not show a detectable change near the saturation pressure. The new method has been used successfully to design the live-oil experiments in this and other research projects
Chemical treatment and gas huff-n-puff for enhanced oil recovery in oil shale reservoirs
(2022-02-22) Zeng, Tongzhou; Mohanty, Kishore Kumar; Dicarlo, David A; Daigle, Hugh C; Sephehrnoori, Kamy; Werth, Charles J
Shale oil contributes more than 60% to the US oil production. Shale oil production has been feasible because of technological development for horizontal wells with multistage hydraulic fracturing. However, after primary production, more than 90% of the oil is left behind in shale oil reservoirs due to ultra-low permeability. For an average well the oil production rates fall sharply in the first year because of the extremely low permeability, micro-fracture closure, and large flow resistance at the matrix-fracture interface. To sustain oil production from shale oil, it is essential to develop enhanced oil recovery (EOR) techniques for unconventional reservoirs. In this dissertation, lab experiments were conducted to investigate the effect of chemical treatment, gas huff-n-puff, and/or both on EOR in shale oil reservoirs. Surfactant treatment on shale was studied. Static adsorption experiments were performed to investigate the adsorption behavior of surfactant on shale samples. An additive model was built to estimate the adsorption capacity given the mineral composition and TOC of shale samples. A series of surfactant screening process, including aqueous stability tests, contact angle measurements, interfacial tension measurements, and spontaneous imbibition experiments, was used to compare the performance of surfactants at reservoir conditions. Surfactant blends were compared with single surfactants, and the surfactant blends showed improved oil recovery compared to most single surfactants. Chemical blends showed good EOR potential in Eagle Ford formation, and the effects of solvents in chemical blends were investigated via spontaneous imbibition process. Chemical blends with solvents showed improved recovery compared to the brine-only controlled case, and the Green Solvent showed the most promising results among the five solvents tested. Cyclic gas injection was investigated with CO₂ and hydrocarbon gases. CO₂ huffn-puff showed about 40% oil recovery, and it was observed that the huff pressure to which the cores were pressurized with CO₂ did not affect the oil recovery significantly as long as the pressure was high enough. A combination of chemical blend with CO₂ was more effective compared to pure CO₂ huff-n-puff (40% → 64%). The hydrocarbon gas (60% C1 + 35% C2 + 5% C3) showed a similar effectiveness as CO₂, which can be used to replace CO₂ depending on availability and cost. Also, a numerical simulation model was built to investigate the key parameters in the gas huff-n-puff qualitatively. The learning from these simulations can be used for future experimental design.
Co-optimization of CO₂ sequestration and enhanced oil recovery and co-optimization of CO₂ sequestration and methane recovery in geopressured aquifers
(2011-08) Bender, Serdar; Jablonowski, Christopher J.; Sepehrnoori, Kamy, 1951-
In this study, the co-optimization of carbon dioxide sequestration and enhanced oil recovery and the co-optimization of carbon dioxide sequestration and methane recovery studies were discussed. Carbon dioxide emissions in the atmosphere are one of the reasons of global warming and can be decreased by capturing and storing carbon dioxide. Our aim in this study is to maximize the amount of carbon dioxide sequestered to decrease carbon dioxide emissions in the atmosphere and maximize the oil or methane recovery to increase profit or to make a project profitable. Experimental design and response surface methodology are used to co-optimize the carbon dioxide sequestration and enhanced oil recovery and carbon dioxide sequestration and methane recovery. At the end of this study, under which circumstances these projects are profitable and under which circumstances carbon dioxide sequestration can be maximized, are given.
Comparison of glycine, acetate, and formate as wettability modifiers for carbonate formations
(2021-08-19) Baghishov, Ilgar; Okuno, Ryosuke, 1974-
Previous studies indicated the efficacy of the simplest amino acid, glycine, as an aqueous additive for enhanced water imbibition in carbonate reservoirs. The objective of this research was to investigate the importance of the amino group of glycine in its enhanced water imbibition and compare glycine with two carboxylates (acetate and formate) with/without adjusting the solution pH. Contact-angle experiments on calcite were carried out at 347 K and atmospheric pressure with 68000-ppm reservoir brine (RB), and 4 different concentrations of glycine, acetate, and formate solutions in RB. To test the hypothesis that calcite dissolution is one of the main mechanisms in wettability alteration by glycine, we performed another set of contact angle experiments by adding HCl to brine, acetate, and formate solutions. HCl was added to match the pH of the glycine solution at the same concentration. We also performed imbibition tests with Texas Cream Limestone cores at 347 K with brine, glycine, acetate, and formate solutions (with and without HCl) in RB at 5.0 wt%. Contact-angle results indicated that glycine changed calcite’s wettability from oil-wet (120°) to water-wet (45°). However, acetate solution was not able to change the wettability to water-wet; and formate moderately decreased the contact angle to 80°. The increase in pH level during the contact angle experiment with glycine solution indicated the consumption of hydrogen ions because of the calcite dissolution. However, the levels of pH in formate and acetate solutions decreased. Imbibition tests with carbonate cores supported the observations from the contact-angle experiments. The oil recovery factor was 31% for glycine solution, 20% for RB, 21% for formate solution, and 19% for acetate solution. This re-confirmed the effectiveness of glycine as an additive to improve the oil recovery from carbonates. An additional set of imbibition tests revealed that acetate at the pH reduced to the same level as glycine was still not able to recover as much oil as glycine. This showed that glycine recovered oil not only because of the calcite dissolution and the carboxyl group, but also because of the amino group. It is hypothesized that the amino group with its electron donor ability creates a chelation effect that makes glycine entropically more favorable to get attached to the calcite surface than acetate. Another important result is that the formate solution at an adjusted pH resulted in a greater oil recovery than RB or RB at the same pH. This indicates that there is an optimal pH for the carboxyl group to be effective in wettability alteration as also indicated by the pH change during the contact-angle experiment.
Construction and validation of microfluidic platforms for investigation of multiphase flow and nanofluids in porous media
(2018-06-27) Xu, Ke, Ph. D.; Balhoff, Matthew T.; Huh, Chun; Mohanty, Kishore K; Bonnecaze, Roger T; Daigle, Hugh
Flow and transport in porous media is the fundamental physical process in many important applications such as hydrocarbon recovery, carbon dioxide subsurface sequestration, treatment of non-aqueous liquid pollutions in soil systems, and flooding control for fuel cell systems. Clear description, correct modeling and precise prediction of flow in porous media are of great significance. Although many single-phase and multiphase systems can be characterized using macroscopic models such as Darcy’s law (or the multiphase form of it), other complex flow systems, such as emulsion flow, nanoparticle suspension flow, etc., require a more detailed description. For those complex cases, revealing the pore-scale physics is necessary for larger-scale modeling and predictions. Microfluidics provide a simple way to visualize micron-scale flow behavior with excellent controllability, thus helping to clarify the fundamental pore-scale flow mechanisms and is, therefore, useful for studying flow and transport in porous media. In this work, several special micromodel designs from the single-pore level to pore-network level on microchips were made in order to capture realistic pore-scale flow mechanisms while keeping the system simplified enough for easy quantification. At the single-pore level, the trapping and mobilization of a non-wetting oil droplet at a pore-throat structure are investigated on an ideal pore-throat microfluidic geometry. A simple physical model is derived and the effects of bare nanoparticle aqueous suspension in mobilizing oil is further studied. A dual-permeability microchannel is used to study the emulsion flow in natural fracture system and a synergistic effect between nanoparticles and non-ionic surfactant is investigated to stabilize the emulsion and to potentially improve sweep efficiency. At the pore-network-pore level, a 2.5-D porous micromodel is fabricated to introduce essential 3-D feature in traditional 2-D porous micromodel. On this advanced 2.5-D micromodel, multiple complex fluid systems, including spontaneous imbibition, unstable water drainage, ultra-low IFT flooding, bubble evolution under Ostwald ripening, nanofluid flooding, etc., have been studied, with new physics revealed and modeled. A novel EOR method using nanoparticle treated oil (NPTO) is proposed and validated.
Decision support for enhanced oil recovery projects
(2010-08) Andonyadis, Panos; Gilbert, Robert B. (Robert Bruce), 1965-; Lake, Larry W.
Recently, oil prices and oil demand are rising and are projected to continue to rise over the long term. These trends create great potential for enhanced oil recovery methods that could improve the recovery efficiency of reservoirs all over the world. The greatest challenges for enhanced oil recovery involve the technical uncertainty with design and performance, and the high financial risk. Pilot tests can help mitigate the risk associated with such projects; however, there is a question about the value of information from the tests. Decision support can provide information about the value of an enhanced oil recovery project, which can assist with alleviating financial risk and create more potential opportunities for the technology. The first objective of this study is to create a new simplified method for modeling oil production histories of enhanced oil recovery methods. The method is designed to satisfy three criteria: 1) it allows for quick simulations based on only a few physically meaningful input parameters; 2) it can create almost any potential type of realistic production history that may be realized during a project; and 3) it applies to all nonthermal enhanced oil recovery methods, including surfactant-polymer, alkali-surfactant polymer, and CO₂ floods. The developed method is capable of creating realistic curves with only four unique parameters. The second objective is to evaluate the predictive method against data from pilot and field scale projects. The evaluations demonstrate that the method can fit most realistic production histories as well as provided ranges for the input parameters. A sensitivity analysis is also performed to assist with determining how all of the parameters involved with the predictive method and the economic model influence the forecasted value for a project. The analysis suggests that the price of oil, change in oil saturation, and the size of the reservoir are the most influential parameters. The final objective is to establish a method for a decision analysis that determines the value of information of a pilot for enhanced oil recovery. The analysis uses the predictive method and economic model for determining economic utilities for every potential outcome. It uses a decision-based method to ensure that the non-informative prior probability distributions have an unbiased, consistent, and rational starting point. A simple example demonstrating the process is discussed and it is used to show that a pilot test provides some valuable information when there is minimal prior information. For future work it is recommended that more evaluations are performed, the decision analysis is expanded to include more input parameters, and a rational and logical method is developed for determining likelihood functions from existing information.
Detection of magneto-activated water/oil interfaces containing nanoparticles
(2011-12) Ryoo, SeungYup; Huh, Chun; Milner, Thomas E.; Driga, Micea; Becker, Michael; Neikirk, Dean; Johnston, Keith P.
Accurate, non-invasive determination of multiphase fluids distribution in reservoir rock can greatly help the evaluation and monitoring of oil reservoirs. This laboratory thesis research, carried but utilizing the biomedical engineering concepts and measurement facilities, is an important step in developing a novel magnetic field-based oil detection method. When paramagnetic nanoparticles are either adsorbed oil/water interface or dispersed in a fluid phase in reservoir rock pores, and exposed to external magnetic field, the resultant particle movements displace the interface. Interfacial tension acts as a restoring force, leading to interfacial fluctuation and a pressure (sound) save. As the first step, the motion of the interface between a suspension of paramagnetic nanoparticles and a non-magnetized fluid (placed in a cylindrical dish) is measured by phase-sensitive optical coherence tomography (PS-OCT). Experiments were carried out with a range of iron-oxide nanoparticles that were synthesized and surface-coated by our Chemical Engineering collaborators. The numerical method was improved to be volume conserving, and extended to 3D, for more quantitative matching. The measurements of interfacial motion by PS-OCT confirm theoretical predictions of the frequency doubling and importance of material properties, such as the particle size, for the interface displacements. The relative densities of the fluid phase(air/aqueous and dodecane/aqueous) strongly affect the interfacial displacement. Next, the acoustic responses to the external magnetic oscillation, from the rock samples into which different aqueous dispersions of nanoparticles were injected, were measured in terms of the magnetic frequency, nanoparticle concentration, and other process parameters. Subsequently, the PS-OCT displacements in response to the external magnetic oscillation, from the rock samples into which different aqueous dispersions of nanoparticles were injected, were also measured in terms of the magnetic frequency, nanoparticle concentration, and other process parameters. Conclusions and the recommendations for further study are then given.
Development of a novel EOR surfactant and design of an alkaline/surfactant/polymer field pilot
(2012-12) Gao, Bo; Sharma, Mukul M.
Surfactant related recovery processes are of increasing interest and importance because of high oil prices and the urge to meet energy demand. High oil prices and the accompanying revival of EOR operations have provided academia and industry with great opportunities to test alkaline surfactant polymer (ASP) methods on a field scale and to develop novel surfactant systems that can improve the performance of such EOR processes. This dissertation intends to discuss both opportunities through two unique projects, the development of novel surfactants for EOR applications and the design for an alkaline/surfactant/polymer (ASP) field pilot. In Section I of this dissertation, a novel series of anionic Gemini surfactants are carefully synthesized and systematically investigated. The remarkable abilities of Gemini surfactants to influence oil-water interfaces and aqueous solution properties are fully demonstrated. These surfactants are shown to have great potential for application in EOR processes. A wide range of Gemini structures (C₁₄ to C₂₄ chain length, -C2- and -C4- spacers, sulfate and carboxylate head groups) was synthesized and shown to have high aqueous solubility, with Krafft points below 20°C. The critical micelle concentrations (CMC) for these new molecules are measured to be orders of magnitude lower than their conventional counterparts. The significantly more negative Gibbs free energy for Gemini surfactant drives the micellization process and results in ultralow CMC. An adsorption study of Gemini surfactants at air-water and solid-water interfaces shows their superior surface activity from tighter molecular packing, and attractive characteristics of low adsorption loss at the solid surface. All anionic Gemini surfactants synthesized have an extraordinary tolerance to salinity and/or hardness. No phase separation or precipitation occurs in the aqueous stability tests, even in the presence of extremely high concentrations of mono- and/or di-valent ions. Moreover, ultra-low IFT values are reached under these conditions for Type I microemulsion systems, at very low surfactant concentrations. The stronger molecular interaction between the Gemini and conventional surfactants offers synergy that promotes aqueous stability and interfacial activity. Gemini molecules with short spacers are capable of giving rise to high viscosities at fairly low concentrations. The rheological behavior can be explained by changes in the micellar structure. A molecular thermodynamic model is developed to study anionic Gemini surfactants aggregation behavior in solution. The model takes into account of the head group-counter-ion binding effect and utilizes two simplified solutions to the Poisson-Boltzmann equation. It properly predicts the CMC of the surfactants synthesized and can be easily expanded to investigate other factors of interest in the micellization process. Section II of this dissertation studies chemical formulation design and implementation for an oilfield where an alkaline/surfactant/polymer (ASP) pilot is being carried out. A four-step systematic design approach, composed of a) process and material selection; b) formulation optimization; c) coreflood validation; 4) lab-scale simulation, was successfully implemented and could be easily transferred to other EOR projects. The optimal chemical formulation recovered over 90% residual oil from Berea coreflood. Lab-scale simulation model accurately history matches the coreflood experiment and sets the foundation for pilot-scale numerical study. Different operating strategies are investigated using a pilot-scale model, as well as the sensitivities of project economics to various design parameters. A field execution plan is proposed based on the results of the simulation study. A surface facility conceptual design is put together based on the practical needs and conditions in the field. Key lessons learned throughout the project are summarized and are invaluable for planning and designing future pilot floods.
Effective mobility control mechanisms for EOR processes in challenging carbonate reservoirs
(2019-05) Ghosh, Pinaki, Ph. D.; Mohanty, Kishore Kumar; DiCarlo, David; Sepehrnoori, Kamy; Johnston, Keith P; Werth, Charles
Mobility control mechanisms are key to the success of any enhanced oil recovery processes due to their ability to provide favorable mobility ratio of the injected fluids, thus improving the sweep efficiency during the process. This work is focused on developing effective mobility control mechanisms in challenging carbonate reservoirs that are typically high temperature and high salinity and low permeability formations. The first half of the dissertation is focused on investigating novel foam technology using anionic and cationic surfactants to improve the gas enhanced oil recovery process. Typically, gas injection processes suffer from poor volumetric sweep efficiency due to viscous fingering, channeling, and gravity override. Foam helps to improve the sweep efficiency of the gas floods significantly by reducing the mobility of the gas by orders of magnitude, blocking the high permeability channels and diverting fluids to the bypassed lower permeability channels. Carbonate reservoirs, which are typically oil-wet heterogeneous and low permeability, pose additional challenges for an effective foam EOR process. Crude oils destabilize foam rapidly and the thin oil film on oil-wet rock surfaces makes in-situ foam generation difficult as well. Hence, wettability alteration from oil-wet to water-wet using a surfactant was one of the necessary mechanisms for in-situ foam stability. Low permeability of the carbonates makes strong foam generation challenging due to higher entry capillary pressure in small pore throats that exceeds the critical capillary pressures usually. On the other hand, low interfacial tensions (IFT) of the surfactant formulations helps to lower the entry pressure and stabilize the foam better. This work demonstrated the benefits of two different chemical systems – one that includes use of anionic surfactants for low IFT formulations and the other that includes blends of cationic, non-ionic and zwitterionic surfactants for non low IFT formulations in combination with wettability alteration and foaming to improve oil recovery in oil-wet carbonates after a secondary gas flood process. The second half of the dissertation is focused on developing a novel polymer treatment protocol for successful injection in low permeability carbonate reservoirs through mechanical shear degradation and aggressive filtration tests. The behavior of shear degradation of high molecular weight polymers of different chemistry in varying brine salinities performed with a laboratory blender at a constant speed and varying shearing times followed an exponential decay until a steady state was obtained. Master curves for degraded viscosity predictions were developed to estimate the degraded viscosity of any given polymer in any brine salinity at any given shearing time, given the shearing speed was kept constant. A superimposed master curve for the degradation for all kinds of polymers investigated was established to predict the rate of degradation at any given time. A robust approach of comparison of polymer size distribution from dynamic light scattering (DLS) method and pore throat distribution from mercury injection capillary pressure (MICP) was established for injection qualification of high molecular weight polymers in low permeability carbonates. A novel class of hydrophobically modified acrylamides, also known as associative polymers, were investigated as an alternative to conventional HPAMs and synthetic polymers for injection in low permeability carbonates. The thermo-thickening properties of the associative polymers at elevated temperatures and salinities (with high divalent ions) and higher resistance to shear degradation makes them promising for carbonate reservoirs in comparison to HPAMs, where high polymer dosages are required due to significant viscosity loss in shear degradation. The apparent high viscosities generated from high resistance factors during flow in porous media for associative polymers can be advantageous for optimization of polymer dosage in chemical EOR processes. This work demonstrated a significant potential for application of associative polymers as an effective mobility control agent in carbonate reservoirs, especially in low permeability formations. The novel polymer treatment method for low permeability reservoirs was combined with the development of alkaline-surfactant-polymer (ASP) and surfactant-polymer (SP) technology for improvement of oil recovery in carbonates. The successful polymer transport in low permeability carbonates showed great potential for application of chemical EOR processes like ASP and SP in tight formations. Development of robust SP technology for high temperature and high salinity reservoirs also showed promising results in phase behavior experiments and coreflood experiments. This work demonstrated the benefits of SP technology with optimization of surfactant formulation and coreflood design for lower surfactant retention and higher oil recovery, thus making the process economical
Engineering and economics of enhanced oil recovery in the Canadian oil sands
(2014-05) Hester, Stephen Albert, III; Fisher, W. L. (William Lawrence), 1932-
Canada and Venezuela contain massive unconventional oil deposits accounting for over two thirds of newly discovered proven oil reserves since 2002. Canada, primarily in northern Alberta province, has between 1.75 and 1.84 trillion barrels of hydrocarbon resources that as of 2013 are obtained approximately equally through surface extraction or enhanced oil recovery (EOR) (World Energy Council, 2010). Due to their depth and viscosity, thermal based EOR will increasingly be responsible for producing the vast quantities of bitumen residing in Canada’s Athabasca, Cold Lake, and Peace River formations. Although the internationally accepted 174-180 billion barrels recoverable ranks Canada third globally in oil reserves, it represents only a 9-10% average recovery factor of its very high viscosity deposits (World Energy Council, 2010). As thermal techniques are refined and improved, in conjunction with methods under development and integrating elements of existing but currently separate processes, engineers and geoscientists aim to improve recovery rates and add tens of billions of barrels of oil to Canada’s reserves (Cenovus Energy, 2013). The Government of Canada estimates 315 billion barrels recoverable with the right combination of technological improvements and sustained high oil prices (Government of Canada, 2013). Much uncertainty and skepticism surrounds how this 75% increase is to be accomplished. This document entails a thorough analysis of standard and advanced EOR techniques and their potential incremental impact in Canada’s bitumen deposits. Due to the extraordinary volume of hydrocarbon resources in Canada, a small percentage growth in ultimate recovery satisfies years of increased petroleum demand from the developing world, affects the geopolitics within North America and between it and the rest of the world, and provides material benefits to project economics. This paper details the enhanced oil recovery methods used in the oil sands deposits while exploring new developments and their potential technical and economic effect. CMG Stars reservoir simulation is leveraged to test both the feasible recoveries of and validate the physics behind select advanced techniques. These technological and operational improvements are aggregated and an assessment produced on Canada’s total recoverable petroleum reserves. Canada has, by far, the largest bitumen recovery operation in the world (World Energy Council, 2010). Due to its resource base and political environment, the nation is likely to continue as the focus point for new developments in thermal EOR. Reservoir characteristics and project analysis are thus framed using Canada and its reserves.
Enhanced oil recovery (EOR) in unconventional reservoirs
(2021-12-08) Junira, Adi; Sepehrnoori, Kamy, 1951-; Delshad, Mojdeh; Daigle, Hugh; Javadpour, Farzam; Ganjdanesh, Reza
Rapid production decline is typical in oil production from unconventional reservoirs. Enhanced oil recovery (EOR) with gas in cyclical (huff-n-puff) injection mode is arguably the most feasible method to solve the problem of relatively low oil recovery in the low permeability reservoirs, as supported by wealth of evidences. Nonetheless, the results so far seem vary widely. In some cases, the results are encouraging, while in some others, they are marginal. There seems to be many parameters to be considered in predicting the chance of a huff-n-puff gas EOR success. It is of interest not to just be able to forecast whether a huff-n-puff gas EOR will result in a satisfactory result, but also to obtain the highest oil recovery achievable, at least theoretically. With reliable real field data, rather than the synthetic one, research to identify the most significant factors affecting the gas EOR results in unconventional reservoirs by means of the widely used numerical simulation, is possible. The origin of the data should arguably give more credibility to the results, and thus their related analyses. Once the significant factors are identified and how they interact is understood, an optimum operational parameters design that maximizes the oil recovery is attainable. The acquired knowledge can also be of use in reducing the unknowns in other attempts with other methods to improve unconventional reservoirs’ oil recovery, so that the focus can be directed towards the right direction. Admittedly, uncertainties are inherent to the procedures used, but they are assumed to be acceptable for the purpose. This research found that the maximization of the oil recovery from unconventional reservoirs is viable and it is worth the resources spent. There seems to be some kind of matrix permeability threshold, below which the gas EOR will return meager even negative incremental oil recovery. This is because in order for the EOR to work well, the oil phase must be able to traverse with reasonable ease in the matrix, unless the injection gas effectively vaporizes the reservoir oil phase. Good injection gas choices are the ones that lower the oil viscosity while monotonically vaporize it in reservoir conditions. Field gas, [CO₂, C₂, C₃, and C₄] are usually good injection gas choices, with certain conditions. Single oil or gas phase in reservoir conditions is desirable, as the presence of another phase will adversely affect the phase flow, as described by the relative permeability curves concept. Good operational parameters are the ones that facilitate the production of the heavy components the most, while minimizing the obstruction to the oil influx from the matrix to the SRV. By extension, it is suggested that the use of water-based surfactant could be detrimental to the oil recovery in the long term, as the water phase will block the injection gas contact with the reservoir fluid. The inability to apply sufficiently high pressure without adversely affecting the aforementioned oil influx is a concerning challenge in the real field EOR implementation. Unless the reservoir permeability is enough to allow adequate oil phase mobility, it may be more reasonable to produce such unconventional reservoirs in primary production mode. Moreover, a higher GOR tends return a higher incremental oil recovery for black and volatile oil, in case of the EOR is applied from the beginning without a preceding primary production period. The data obtained from the oil-producing fields is also used to develop some kind of screening criteria for injection gas type, within which a huff-n-puff gas EOR will result in a good incremental oil recovery. The criteria cover the reservoir pressure, oil viscosity, C₇₊ molar fraction, and fracture conductivity. However, due to the available data is for reservoir oil with relatively low viscosity, the screening criteria is also more appropriate for such type of reservoir oil. As for the reservoir permeability point of view, the screening criteria is more suited for unconventional reservoirs with permeability of 685 nanodarcy or higher
Enhanced oil recovery by carbon dioxide and diethyl ether as mutual solvents
(2017-12) Alzayer, Ahmed Jamal; Mohanty, Kishore Kumar; Sepehrnoori, Kamy, 1951-
Increasing the oil recovery factor from existing fields is the key towards meeting future oil demand. The injection of solvents, an established EOR technique, has shown significant improvement in oil recovery over conventional water floods. However, the injection of pure solvent slugs can be quite costly for field operators. To mitigate this problem, recent literature has suggested the use of brines that are saturated with mutual solvents (dissolve in both oil and water) such as Carbon Dioxide (CO₂) and Dimethyl Ether (DME). This practice minimizes the amount of used solvent since it is governed by its limited solubility in water. The solubility of CO₂ and DME is much higher in oil than in water. Therefore, a mass transfer takes place once CO₂ or DME saturated brines come into contact with oil. As these solvents go into the oil phase, they promote oil swelling and reduce the oil viscosity, thereby making it movable and increasing the oil recovery as a result. Although there has been recent lab work performed with this EOR method, most of the work performed so far involved short cores, high injection rates and in some cases limited to sandstone cores. In this thesis, we investigated the effect of using brines that were saturated with CO₂ and Diethyl ether (DEE) on oil recovery. The results came out to be mixed and not completely in line with previous literature for CO₂ rich brine (Carbonated Water). Injecting carbonated water into sandstone cores did not improve the oil recovery. However, there was an improvement in oil recovery as a result of carbonated water injection in carbonate cores, which also displayed effluent line plugging. For the case of DEE-rich brine, there was a noticeable improvement in oil recovery but it took more pore volumes to have an effect in comparison to DME-rich brine literature results. The experimental work was further supplemented with numerical modeling. The simulator was not able to capture the effects of carbonated water observed in the experiment, due to the absence of rock–fluid interaction in the modeling mechanism. In contrast, the DEE rich brine case was successfully matched with the compositional simulator since it did not involve rock reactions and was strictly based on fluid–fluid interactions
Experimental Evaluation of Co-Solvents in Development of High Performance Alkali/Surfactant/Polymer Formulations for Enhanced Oil Recovery
(2009-12) Sahni, Vinay Manmohan; Pope, Gary A.
The ability to select low-cost, high-performance surfactants for a wide range of crude oils under a wide range of reservoir conditions has improved dramatically. There are thousands of possible combinations of the chemicals (including salinities, hardness, oil concentrations) that could be tested for each oil, and each chemical combination requires many observations at reservoir temperature for proper evaluation, so it would take too long, cost too much and in many cases not even be feasible to test all combinations. The research presented in this work uses and describes a scientific understanding of how to match up the surfactant/co-surfactant/co-solvent characteristics with the oil characteristics, temperature, salinity and hardness. The work describes the role of co-solvents including some novel co-solvents in the formulation design and testing procedure. It is essential that the surfactant solution be a clear, stable aqueous phase. Surfactants that show ultra-low interfacial tension and excellent microemulsion phase behavior are often not sufficiently soluble at optimum salinity to give clear, stable aqueous solutions. Even slightly cloudy solutions often show phase separation or precipitation after a few days at reservoir temperature, which is very short compared to reservoir flooding times. The addition of polymer often makes the problem worse although the low solubility of the surfactant at high salinity is the fundamental problem. Surfactants with large hydrophobes produce the lowest IFT, but are often not sufficiently water soluble at optimum salinity. Hydrophilic co-surfactants and/or co-solvents are needed to make the solutions pass the stringent aqueous stability test. This research shows why this is so important, how to select and test the best co-solvents, and illustrates the results with core floods where the oil recovery was doubled by simply adding a small concentration of co-solvent to make the ASP slug clear. In such cases, the co-solvent more than pays for itself in terms of higher oil recovery because of the lower surfactant retention and improved effectiveness of the polymer for mobility control.
Experimental investigation of surfactant flooding in fractured limestones
(2018-12-06) Mejia, Miguel, M.S. in Engineering; Balhoff, Matthew T.; Pope, G. A.
Carbonates are important candidates for enhanced oil recovery, but recovering oil from oil-wet fractured carbonate reservoirs is challenging. Waterflooding bypasses the rock matrix and recovers little oil. Chemical enhanced oil recovery using surfactants increases oil recovery by lowering the interfacial tension, changing the wettability, and generating viscous microemulsions that improve mobility control. Seven Texas Cream Limestone cores with a permeability of 15-30 md were fractured and saturated with 100% oil. The cores were aged for one week at 78 C to make them oil-wet. The fracture permeability was adjusted so that it was 10,000 times higher than the rock matrix by changing the confining stress. Waterflooding recovered an average of 6.5% of the original oil in place with an oil cut of less than 2% at the end of the waterfloods. Aqueous surfactant-alkali solution was injected after each waterflood. All of the surfactant floods produced oil cuts of more than 25% soon after injection started. Surfactant slugs of 3 PV, 1 PV and 0.3 PV followed by brine drives recovered 45, 44, and 30% of the remaining oil after the waterfloods. The 1 PV and 0.3 PV slug sizes were more efficient in terms of oil recovered for a given mass of injected surfactant. In both cases, a high salinity surfactant solution was injected to produce a viscous microemulsion in-situ. The viscous microemulsion increased oil recovery by promoting crossflow and improving mobility control. Low surfactant retention is vital for the economics of surfactant floods. The experiments show that using sodium hydroxide caused surfactant retention to be very low in fractured limestone cores. The average surfactant retention was 0.17 mg/g-rock. Decreasing the flow rate increased the oil recovery at a given injected pore volume. Thus changing practical design variables (salinity, surfactant slug size, flow rate) has a significant effect on oil recovery.
Experimental parameter analysis of nanoparticle retention in porous media
(2010-08) Caldelas, Federico Manuel; Bryant, Steven L.; Huh, Chun
With a number of advantages hitherto unrecognized, nanoparticle-stabilized emulsions and foams have recently been proposed for enhanced oil recovery (EOR) applications. Long-distance transport of nanoparticles is a prerequisite for any such EOR applications. The transport of the particles is limited by the degree to which the particles are retained by the porous medium. In this work, experiments that quantify the retention and provide insight into the mechanisms for nanoparticle retention in porous media are described. Sedimentary rock samples (Boise sandstone and Texas Cream limestone) were crushed into single grains and sieved into narrow grain size fractions. In some cases, clay (kaolinite or illite) was added to the Boise sandstone samples. These grain samples were packed into long (1 ft – 15 ft) slim tubes (ID = 0.93 cm) to create unconsolidated sandpack columns. The columns were injected with aqueous dispersions of silica-cored nanoparticle (with and without surface coating) and flushed with brine. The nanoparticle effluent concentration history was measured and the nanoparticle recovery was calculated as a percentage of the injected nanoparticle dispersion. Fifty experiments were performed in this fashion, varying different experimental parameters while maintaining others constant to allow direct comparisons between experiments. The parameters analyzed in this thesis are: specific surface area of the porous medium, lithology, brine salinity, interstitial velocity, residence time, column length, and temperature. Our results indicate that retention is not severe, with an 8% average of the injected amount, for all our experiments. From the parameters analyzed, specific surface area was the most influential variable, with a linear effect on nanoparticle retention independently of lithology. Salinity increased nanoparticle retention slightly and delayed nanoparticle arrival. Velocity, residence time and length are coupled parameters and were studied jointly; they had a minor effect on retention. Temperature had a marginal effect, as we observed an approximate 2% increase in retention at 80°C compared to 21°C. Both surface coated and bare silica nanoparticles were successfully transported, so surface coating does not appear to be a prerequisite for transport for the particle and rock systems studied.
Extraction of useful signals from noise using advanced time-frequency analysis in Enhanced Oil Recovery
(2017-08-04) Komodromos, Sotiris; Lu, Nanshu; Djurdjanovic, Dragan
In Enhanced Oil Recovery (EOR), the injected CO2 does not distribute evenly through ground layers and often is not going to the desired direction. The key issue of this research, was to extract the useful signal from noise for a novel CO2 subsurface imaging solution which uses surfaced based sensors only, in comparison with conventional seismic technology which requires downhole equipment [5, 7, 8, 19, 20]. That could potentially reduce the cost drastically due to its simplicity in installation, performance, less labor intensive and faster process of data. The extremely low signal-to-noise (S/N) ratio required the utilization of binomial time-frequency domains (TFDs) to process the collected field data as the problem involves extremely non-stationary signals. Binomial Cone-Kernel function is arguably the most advanced signal independent kernel; it allowed us to extract useful signals embedded in noise and observe repeatable waves for the first time.
Ferrofluid applications in petroleum engineering
(2021-04-09) Wang, Ningyu (Ph. D. in petroleum engineering); Prodanovic, Masa; Balhoff, Matthew T; Bonnecaze, Roger T; Daigle, Hugh; Mohanty, Kishore
Ferrofluid is a stable suspension of superparamagnetic nanoparticles (SMNPs). Because of their small size, and with suitable coating, SMNPs stay suspended in the fluid and their retention in porous media is minimized. When exposed to an external magnetic field, the SMNPs align with the magnetic field, triggering magnetic, mechanical, and thermal phenomena. When the external magnetic field is removed, the orientation of the SMNPs restores randomness. In this study, we explored two applications of ferrofluid in petroleum engineering. First, we explored the potential of SMNPs for flow assurance, more specifically, dewaxing. Exposing SMNPs to an alternating magnetic field produces heating due to Neel’s relaxation. SMNPs can be dispersed, lodged within a coat of paint, and applied to a pipe’s interior (nanopaint). The heating effect of nanopaint in a pipe was initially explored and the idea of injecting an electromagnetic source into pipeline for dewaxing purposes was proposed by Mehta et al. in 2015. However, they performed fewer than 10 simulations and did not consider pig movement or flowing hydrocarbon. In this study, three numerical models were set up to study the heating process of an electromagnetic dewaxing system in a pipeline with wax deposition. The device that emits the alternating magnetic field is named an electromagnetic pig, and the corresponding dewaxing process is called electromagnetic pigging. Induction heat is generated in the nanopaint layer in the pipeline and is transported to the deposited wax to melt at least part of the wax to dissolve the wax back into the flowing hydrocarbon or to peel the wax off the pipeline wall. The heating effectiveness and efficiency of a simplified electromagnetic pig composed of a single solenoid coil were numerically studied in the commercial multiphysics simulation software COMSOL. Heating effectiveness was evaluated by heating zone length, heating zone depth, and maximum pig speed, while heating efficiency was evaluated by pig induction factor (PIF). Simulation results show that the solenoid coil should have a longer radius and shorter length to achieve better wax-heating performance. Shorter coil length slightly increases the heating effectiveness and heating efficiency. Longer coil radius increases the heating effectiveness and yields stable heating efficiency. The impact of coil radius on heating efficiency is complicated, while longer coil radius avoids the lowest-efficiency region. The pig speed should be faster to decrease operation time and increase heat efficiency, as long as the heating effectiveness does not drop too much and the wax can still melt and peel off. A battery of100 kW h can power the pig to melt 216 kg of deposited wax and peel off several times more wax, which is sufficient to dewax a 0.2-m inner radius pipeline of 1.78 km (1.1 mi). To melt a longer section of pipeline, a larger battery set or a fleet of pigs would be necessary. Although the system is designed to lower the hydrocarbon temperature in the pipeline, higher hydrocarbon temperature helps the electromagnetic dewaxing. Second, we explored ferrofluid-fluid displacement at the pore scale with the potential to enhance oil recovery using microfluidic experiments. Nanoparticles have great potential to mobilize trapped oil in reservoirs by reducing the oil-water interfacial tension, altering the rock wettability, stabilizing foams and emulsions, and heating the reservoir to decrease the oil viscosity. However, the direct application of magnetic forces on SMNPs in reservoir engineering applications has not been extensively investigated. Possible oil recovery by magnetic forces when the magnetic field is parallel to the flow direction was predicted by Soares in 2014, but no experiment results have confirmed the oil recovery or the mechanism. In this study, we demonstrate the enhanced oil recovery (EOR) potential of hydrophilic magnetic nanoparticles in oil production by direct observation using microfluidics, and we examine the mechanism and hypothesize new theories to explain the experimental phenomena. Ferrofluid flooding experiments were performed in a micromodel of a converging-diverging single channel and then in a micromodel of a foot-long pore network, both with varying depth (so-called 2.5D micromodel). The micromodels were made of glass, and thus, the water-based ferrofluid was the wetting fluid. Initial ferrofluid flooding experiments in single channels were performed under a static magnetic field transverse to the flow direction. This magnetic field caused oil droplet deformation, dynamic break-up into smaller droplets, and subsequent residual oil saturation reduction. Significant oil blob displacement was observed within 2 hours after the magnetic field was applied. During one flooding experiment, the oil saturation within the observation area of the micromodel reduced from 27.4% to 12.0%. This result contrasts with the prediction of the theory of magnetic forces, and we hypothesize that oil recovery is at least partly attributed to the temporary SMNP microstructures in the ferrofluid when exposed to an external magnetic field. We then designed a rotating magnetic device to examine the hypotheses and to reveal that a changing field would have an even larger effect on saturation reduction. We subsequently observed a completely different phenomenon, namely self-assembly of oil droplets, indicating the formation of hydrophilic SMNP microstructures (chains under the magnetic field). These SMNP microstructures were ever-changing under the rotating external magnetic field. While the ability of ferrofluid to rotate small blobs was interesting in and of itself, in experiments without actual flooding (and thus synergy of hydrodynamic and magnetic forces), we did not observe any additional oil recovery. Further ferrofluid flooding experiments were performed in a foot-long 2.5D micro-model in a rotating external magnetic field to study the oil recovery effect of the rotating magnetic field at the core scale. In one experiment, the oil saturation dropped from 44.6% to 33.3% after the rotating magnetic field was applied. The additional oil recovery of 11.3% shows good potential for ferrofluid flooding with a rotating external magnetic field.