Download or read book Foam Assisted Surfactant gas Flooding in Naturally Fractured Carbonate Reservoirs written by Hayrettin Aygol and published by . This book was released on 2017 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: In naturally fractured reservoirs, water flood performance and efficiency for oil recovery is usually limited by capillary forces. Wettability and interfacial tension (IFT) between oil and water phases are essential factors that limit the potential for oil production in naturally fractured reservoirs. The permeability of such reservoirs is in range of 1~20 md (majority of carbonate reservoirs) with the matrix wettability preferentially oil-wet to mixed-wet. Hence, water and/or gas flood performances are not efficient due to the tendency of water or gas flow through fractures. Surfactants are used to reduce IFT between oil and water, alter the wettability of matrix to proficiently water-wet, and generate in-situ foam as a drive and for mobility control. Spontaneous imbibition between the fractures and the matrix is achieved by both wettability alteration and ultra-low interfacial tensions. Experimental studies show that co-injection or alternate injection of surfactant solution and gas are very promising to mobilize and solubilize the remaining oil. In this study, we overview to provide a technical background and review the literature extensively in order to understand surfactant flooding and foam performance in porous media. Results show that surfactants are induced to matrix through fractures not only by spontaneous imbibition, but also by foam that diverts surfactant solutions into low permeability matrix. The finding results by several authors in lab-scale indicate that surfactant type, foam properties, capillary pressure properties corresponding to different wetting states, and oil-water interfacial tension are crucial factors that significantly impact the efficiency of such processes. In general, summary of this work shows that foam plays a dominant role as a drive to displace the oil in matrix when capillary forces are not strong to retain the oil in presence of surfactants. Although there is very restricted work that claim foam efficiency in presence of oil, mobilized oils are displaced and moved toward fractures as pure oil bank (oil phase). Some laboratory measurements and simulation study reveal with both core and reservoir scales that such process provides great sweep efficiency and recover a significant amount of remaining oil from the matrix to fracture.

Download or read book Experimental Investigation of Viscous Forces During Surfactant Flooding of Fractured Carbonate Cores written by Jose Ernesto Parra Perez and published by . This book was released on 2016 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: The objective of this research was to investigate the effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores, specifically, to test the effects of using surfactants that form viscous microemulsions in-situ. The hypothesis was that a viscous microemulsion flowing inside a fracture can induce transverse pressure gradients that increase fluid crossflow between the fracture and the matrix, thus, enhancing the rate of surfactant imbibition and thereby the oil recovery. Previous experimentalists assumed the small viscous forces were not important for oil recovery from naturally fractured reservoirs (NFRs) since the pressure gradients that can be established are very modest due to the presence of the highly conductive fractures. Hence, the most common approach for studying surfactants for oil recovery from NFRs is to perform static imbibition experiments that do not provide data on the very important viscous and pressure forces. This is the first experimental study of the effect of viscous forces on the performance of surfactant floods of fractured carbonate cores under dynamic conditions. The effects of viscous forces on the oil recovery during surfactant flooding of fractured carbonate cores were tested by conducting a series of ultralow interfacial tension (IFT) surfactant floods using fractured Silurian Dolomite and Texas Cream Limestone cores. The viscosity of the surfactant solution was increased by adding polymer to the surfactant solution or by changing the salinity of the aqueous surfactant solution, which affects the in-situ microemulsion viscosity. The fractured cores had an extreme permeability contrast between the fracture and the matrix (ranging from 2500 to 90,000) so as to represent typical conditions encountered in most naturally fractured reservoirs. Also, non-fractured corefloods were performed in cores of each rock type for comparison with the results from the fractured corefloods. In all the experiments, the more viscous surfactants solutions achieved the greater oil recovery from the fractured carbonate cores which contradicts conventional wisdom. A new approach for surfactant flooding of naturally fractured reservoirs is presented. The new approach consists of using a surfactant solution that achieves ultralow IFT and that forms a viscous microemulsion. A viscous microemulsion can serve as a mobility control agent analogous to mobility control with foams or polymer but with far less complexity and cost. The oil recovery from the fractured carbonate cores was greater for the surfactant floods with the higher microemulsions, thus, it is expected that using viscous microemulsion can enhance the oil recovery from naturally fractured reservoirs.

Download or read book Simulation Study to Investigate the Effect of Natural Fractures on the Performance of Surfactant polymer Flood in Carbonate Reservoirs written by Nawaf Ibrahim A. Sayedakram and published by . This book was released on 2011 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: This thesis presents a comprehensive simulation study on the impact of natural fractures on the performance of surfactant polymer flood in a field scale surfactant-polymer flood. The simulation model utilized for the study is a dual porosity dual permeability model representing 1/8 of a 20-acre 5-spot pattern. The model parameters studied include wettability alteration, IFT changes and mobility reduction effect. The results of this study clearly indicate the importance of reservoir description and fracture modeling for a successful surfactant-polymer flood. Naturally fractured carbonate reservoirs are usually characterized by mixed wettability and low matrix permeability which leads to low oil recovery and high remaining oil saturation. Enhanced oil recovery methods such as surfactant-polymer flood (SPF) enhance the recovery by increasing the spontaneous imbibitions either by lowering the interfacial tension or altering the wettability. However, one of the main reasons for failed surfactant-polymer floods is under-estimating the importance of the reservoir especially the description of natural fractures and their effect on recovery. Sensitivity runs were made to compare oil recovery capillary force, buoyancy force and viscous force. The simulation study indicates that critical water saturation should be reached before the start of surfactant-polymer flood to maximize oil recovery and utilize the capillary force. Also, when a surfactant alters the rock wettability, an optimum IFT should be identified for faster and higher imbibitions. The study shows that a contrast in permeability between that of the fracture and that of the matrix will result in a slightly lower oil recovery. Having the fracture perpendicular to the injector producer will result in a higher areal sweep and lower residual oil. A sensitivity study on the effect of the size of surfactant polymer slug was not conclusive. Maximum adsorption capacity was reached which was one of the causes of low imbibitions rate. Following the surfactant-polymer with water flood was able to reverse the adsorption and restore some of the movable oil. The results show that if the enhanced fluid that alter the wettability, imbibed in the matrix, injecting high IFT brine will increase the rate of imbibition. The study calls for further investigation of this phenomenon through research using a scaled laboratory model to verify the simulation results.

Download or read book written by and published by . This book was released on 2005 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Systematic Study of Foam for Improving Sweep Efficiency in Chemical Enhanced Oil Recovery written by Nhut Minh Nguyen and published by . This book was released on 2010 with total page 158 pages. Available in PDF, EPUB and Kindle. Book excerpt: Foam-assisted low interfacial tension and foam-improved sweep efficiency are attractive enhanced oil recovery (EOR) methods with numerous studies and researches have been conducted in the past few decades. For example, CO2-Enhanced Oil Recovery (CO2-EOR) is very efficient in terms of oil displacement. However, due to the low viscosity of super critical CO2, the process usually suffers from poor sweep efficiency. One method of increasing sweep efficiency in CO2-EOR has been identified through the use of surfactants to create "foams" or more correctly CO2-in-water (C/W) macroemulsions. Polymer flooding techniques such as Alkali -- Polymer (AP), Surfactant -- Polymer (SP), and Alkali -- Surfactant -- Polymer (ASP) have been the only proven chemical EOR method in sandstone reservoirs with many successful pilot tests and field projects. However, the use of polymer is limited in carbonates due to unfavorable conditions related to natural characteristics of this type of lithology. In this case, foam-assisted EOR, specifically Alkali -- Surfactant -- Gas (ASG) process, can be an alternative for polymer flooding. It is a fact that large amount of the world's oil reserves resides in carbonate reservoirs. Therefore, an increase in oil recovery from carbonates would help meet the world's increasing energy demand. This study consists of two parts: (1) the development of new surfactant for creating CO2 -- in -- water macroemulsions for improving sweep efficiency in CO2 -- EOR processes; (2) systematic study of ASG method as a novel EOR technique and an alternative for polymer flooding in carbonate reservoirs. Both studies are related to the use of foam as a mobility control agent. In the first part, the design and synthesis of twin tailed surfactants for use at the CO2/water interface is discussed. The hydrohobes for these surfactants are synthesized from epichlorohydrin and an excess alcohol. Subsequent ethoxylation of the resulting symmetrical dialkyl glycerin yields the water soluble dual tailed surfactants. The general characteristics of these surfactants in water are described. A comparison is carried out between twin-tailed dioctylglycerine surfactants and linear secondary alcohol surfactant based on results from a core flood. The results show that even above the cloud point of the surfactants, the twin tailed surfactants create a significant mobility reduction, likely due to favorable partitioning into the CO2 phase. The data covers surfactant structures designed specifically for the CO2-water interface and can be used by producers and service companies in designing new CO2-floods, especially in areas that might not have been considered due to problems with reservoir heterogeneity. Second part contains a systematic study of ASG process on carbonate rocks through a series of experiments. The purpose is to demonstrate the performance as well as the potential of ASG as a new EOR technique. In this study, basic concepts in chemical EOR are presented, while the design of chemical formulation, phase behavior, and the role of foam are discussed in details. Experimental results showed relatively good recovery, low surfactant retention. However, pressure drop during chemical injections were high, which indicates the formation of both strong foam and viscous microemulsion at the displacement front when surfactant starts solubilizing oil. Overall, ASG showed good performance on carbonate rocks. Optimization can be made on surfactant formula to form less viscous microemulsion and therefore improve efficiency of the process.

Download or read book Chemical Enhanced Oil Recovery written by Patrizio Raffa and published by Walter de Gruyter GmbH & Co KG. This book was released on 2019-07-22 with total page 277 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book aims at presenting, describing, and summarizing the latest advances in polymer flooding regarding the chemical synthesis of the EOR agents and the numerical simulation of compositional models in porous media, including a description of the possible applications of nanotechnology acting as a booster of traditional chemical EOR processes. A large part of the world economy depends nowadays on non-renewable energy sources, most of them of fossil origin. Though the search for and the development of newer, greener, and more sustainable sources have been going on for the last decades, humanity is still fossil-fuel dependent. Primary and secondary oil recovery techniques merely produce up to a half of the Original Oil In Place. Enhanced Oil Recovery (EOR) processes are aimed at further increasing this value. Among these, chemical EOR techniques (including polymer flooding) present a great potential in low- and medium-viscosity oilfields. • Describes recent advances in chemical enhanced oil recovery. • Contains detailed description of polymer flooding and nanotechnology as promising boosting tools for EOR. • Includes both experimental and theoretical studies. About the Authors Patrizio Raffa is Assistant Professor at the University of Groningen. He focuses on design and synthesis of new polymeric materials optimized for industrial applications such as EOR, coatings and smart materials. He (co)authored about 40 articles in peer reviewed journals. Pablo Druetta works as lecturer at the University of Groningen (RUG) and as engineering consultant. He received his Ph.D. from RUG in 2018 and has been teaching at a graduate level for 15 years. His research focus lies on computational fluid dynamics (CFD).

Download or read book Modern Chemical Enhanced Oil Recovery written by James J.Sheng and published by Gulf Professional Publishing. This book was released on 2010-11-25 with total page 648 pages. Available in PDF, EPUB and Kindle. Book excerpt: Crude oil development and production in U.S. oil reservoirs can include up to three distinct phases: primary, secondary, and tertiary (or enhanced) recovery. During primary recovery, the natural pressure of the reservoir or gravity drive oil into the wellbore, combined with artificial lift techniques (such as pumps) which bring the oil to the surface. But only about 10 percent of a reservoir's original oil in place is typically produced during primary recovery. Secondary recovery techniques to the field's productive life generally by injecting water or gas to displace oil and drive it to a production wellbore, resulting in the recovery of 20 to 40 percent of the original oil in place. In the past two decades, major oil companies and research organizations have conducted extensive theoretical and laboratory EOR (enhanced oil recovery) researches, to include validating pilot and field trials relevant to much needed domestic commercial application, while western countries had terminated such endeavours almost completely due to low oil prices. In recent years, oil demand has soared and now these operations have become more desirable. This book is about the recent developments in the area as well as the technology for enhancing oil recovery. The book provides important case studies related to over one hundred EOR pilot and field applications in a variety of oil fields. These case studies focus on practical problems, underlying theoretical and modelling methods, operational parameters (e.g., injected chemical concentration, slug sizes, flooding schemes and well spacing), solutions and sensitivity studies, and performance optimization strategies. The book strikes an ideal balance between theory and practice, and would be invaluable to academicians and oil company practitioners alike. Updated chemical EOR fundamentals providing clear picture of fundamental concepts Practical cases with problems and solutions providing practical analogues and experiences Actual data regarding ranges of operation parameters providing initial design parameters Step-by-step calculation examples providing practical engineers with convenient procedures

Download or read book Numerical Simulation of Foam assisted Immiscible Gas Injection for Enhanced Oil Recovery written by Phattharaporn Khongdi and published by . This book was released on 2022 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: The efficiency of foam displacement in gas enhanced oil recovery (EOR) in low- permeability (1-10 mD), heterogeneous carbonate formations depends on the stability of the foam in the presence of oil. This study presents a new approach to determine foam model parameters using the Computer Modelling Group (CMG) GEMTM Foam simulator and foam core-flood experiments in the absence and presence of oil. Laboratory data was obtained from coreflood experiments including water flooding and co-injection of alkyl polyglucoside (APG) surfactant solution and hydrocarbon gas at different rates to generate foam in-situ in carbonate rocks. A series of numerical simulations was conducted to construct the relative permeability functions for gas, formation brine, and crude oil in oil-water carbonate cores. These functions were obtained by history matching water flooding data including the measured pressure drop and oil recovery using the CMG CMOSTTM. Next, these relative permeability functions were used to simulate foam propagation in carbonate cores using an empirical foam model implemented in CMG-GEM. The main focus of this simulation work is to develop a method for determining foam model parameters based on foam core flooding experiments. Then, the obtained endpoint relative permeabilities were used to construct relative permeability models. Second, pressure drop measured during foam flooding in a water-wet core at different surfactant concentrations was used to determine part of the foam model parameters that represent surfactant effect on foam behavior. These parameters were then used to history-match pressure drops at different injection rates and foam qualities from the same core to identify other foam model parameters that represents the effect of foam dry-out, mobility reduction, and capillary pressure. Finally, the foam model parameters representing the effect of oil on foam propagation were determined by history matching pressure drops obtained from foam corefloods in an oil-wet core. An excellent agreement between the foam simulations and experiments was obtained. The study indicated that in order to obtain the foam parameters that can be used for the field development plan, it is beneficial to designated experimental data into stages which can reduce the requirement for extensive simulations to select parameters for foam- assisted enhanced oil recovery. Additionally, rather than concurrent matching, when parameters from previous simulations were kept constant while parameters in subsequent simulations were modified, history-matching quality improved

Download or read book On the Stability of Foam written by Benjamine Tokuo Tsunajima and published by . This book was released on 1925 with total page 144 pages. Available in PDF, EPUB and Kindle. Book excerpt:

Download or read book Surfactants in Upstream E P written by Theis Solling and published by Springer Nature. This book was released on 2021-06-19 with total page 458 pages. Available in PDF, EPUB and Kindle. Book excerpt: This edited book explores the use of surfactants in upstream exploration and production (E&P). It provides a molecular, mechanistic and application-based approach to the topic, utilising contributions from the leading researchers in the field of organic surfactant chemistry and surfactant chemistry for upstream E&P. The book covers a wide range of problems in enhanced oil recovery and surfactant chemistry which have a large importance in drilling, fracking, hydrate inhibition and conformance. It begins by discussing the fundamentals of surfactants and their synthesis. It then moves on to present their applicability to a variety of situations such as gas injections, shale swelling inhibition, and acid stimulation. This book presents research in an evolving field, making it interesting to academics, postgraduate students, and experts within the field of oil and gas.

Download or read book SURFACTANT BASED ENHANCED OIL RECOVERY AND FOAM MOBILITY CONTROL written by and published by . This book was released on 2004 with total page 5 pages. Available in PDF, EPUB and Kindle. Book excerpt: Surfactant flooding has the potential to significantly increase recovery over that of conventional waterflooding. The availability of a large number of surfactants makes it possible to conduct a systematic study of the relation between surfactant structure and its efficacy for oil recovery. Also, the addition of an alkali such as sodium carbonate makes possible in situ generation of surfactant and significant reduction of surfactant adsorption. In addition to reduction of interfacial tension to ultra-low values, surfactants and alkali can be designed to alter wettability to enhance oil recovery. An alkaline surfactant process is designed to enhance spontaneous imbibition in fractured, oil-wet, carbonate formations. It is able to recover oil from dolomite core samples from which there was no oil recovery when placed in formation brine. Mobility control is essential for surfactant EOR. Foam is evaluted to improve the sweep efficiency of surfactant injected into fractured reservoirs. UTCHEM is a reservoir simulator specially designed for surfactant EOR. A dual-porosity version is demonstrated as a potential scale-up tool for fractured reservoirs.

Download or read book Enhanced Oil Recovery Field Case Studies written by James J.Sheng and published by Gulf Professional Publishing. This book was released on 2013-04-10 with total page 710 pages. Available in PDF, EPUB and Kindle. Book excerpt: Enhanced Oil Recovery Field Case Studies bridges the gap between theory and practice in a range of real-world EOR settings. Areas covered include steam and polymer flooding, use of foam, in situ combustion, microorganisms, "smart water"-based EOR in carbonates and sandstones, and many more. Oil industry professionals know that the key to a successful enhanced oil recovery project lies in anticipating the differences between plans and the realities found in the field. This book aids that effort, providing valuable case studies from more than 250 EOR pilot and field applications in a variety of oil fields. The case studies cover practical problems, underlying theoretical and modeling methods, operational parameters, solutions and sensitivity studies, and performance optimization strategies, benefitting academicians and oil company practitioners alike. Strikes an ideal balance between theory and practice Focuses on practical problems, underlying theoretical and modeling methods, and operational parameters Designed for technical professionals, covering the fundamental as well as the advanced aspects of EOR

Download or read book Novel Cationic Surfactants for CO2 foam Flooding in Carbonate Reservoirs written by Ruth Ellen Hahn and published by . This book was released on 2015 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: A majority of oil throughout the world is contained in carbonate reservoirs. Alkaline-Surfactant-Polymer (ASP) floods cannot be applied in many carbonate reservoirs for three main reasons: conventional alkali are not compatible with divalent ions, adsorption of anionic surfactants is high in the absence of alkali, and the permeability of the rock is often low for polymers to pass through the pores. One alternative to ASP flooding is CO2-foam flooding. Foam flooding reduces the mobility of the CO2 and increases the sweep efficiency. To overcome the adsorption of surfactant on the carbonate surface, cationic surfactants can be used rather than anionic surfactants. The objective of this research is to study two novel cationic surfactants for foam flooding applications. These surfactants are gemini surfactants, containing two head groups and two tail groups. The bulk foam stability in the presence and absence of oil was studied for these surfactants and compared to conventional surfactants; these gemini surfactants showed comparable bulk foam stability to other cationic surfactants. Corefloods in the absence of oil were performed at reservoir conditions to prove foam formation in porous media and to determine the optimum ratio of CO2 to surfactant injection ratio. Both water-wet and oil-wet coreflood experiments were performed for the gemini surfactants. The water-wet corefloods for both surfactants recovered 6-16 %OOIP after the waterflood. The pressure drop during the water-wet foam floods was not too high, less than 15 psi/foot which is reasonable for a low permeability carbonate core. The corefloods showed results comparable with a polymer flood, with no injectivity issues, indicating that these surfactants can be used in place of polymer flooding in carbonate reservoirs. The oil-wet experiment also resulted in foam flood recovery of 13% OOIP, despite the poor wettability alteration results seen with calcite chips. With better foam stability in the presence of oil and enhanced wettability alteration, this new class of cationic surfactants could be a viable option for enhanced oil recovery in carbonate reservoirs.

Download or read book Multiphase Fluid Flow in Porous and Fractured Reservoirs written by Yu-Shu Wu and published by Gulf Professional Publishing. This book was released on 2015-09-23 with total page 420 pages. Available in PDF, EPUB and Kindle. Book excerpt: Multiphase Fluid Flow in Porous and Fractured Reservoirs discusses the process of modeling fluid flow in petroleum and natural gas reservoirs, a practice that has become increasingly complex thanks to multiple fractures in horizontal drilling and the discovery of more unconventional reservoirs and resources. The book updates the reservoir engineer of today with the latest developments in reservoir simulation by combining a powerhouse of theory, analytical, and numerical methods to create stronger verification and validation modeling methods, ultimately improving recovery in stagnant and complex reservoirs. Going beyond the standard topics in past literature, coverage includes well treatment, Non-Newtonian fluids and rheological models, multiphase fluid coupled with geomechanics in reservoirs, and modeling applications for unconventional petroleum resources. The book equips today’s reservoir engineer and modeler with the most relevant tools and knowledge to establish and solidify stronger oil and gas recovery. Delivers updates on recent developments in reservoir simulation such as modeling approaches for multiphase flow simulation of fractured media and unconventional reservoirs Explains analytical solutions and approaches as well as applications to modeling verification for today’s reservoir problems, such as evaluating saturation and pressure profiles and recovery factors or displacement efficiency Utilize practical codes and programs featured from online companion website

Download or read book Exploitation of Unconventional Oil and Gas Resources written by Kenneth Imo-Imo Israel Eshiet and published by . This book was released on 2019-07-10 with total page 152 pages. Available in PDF, EPUB and Kindle. Book excerpt: The stimulation of unconventional hydrocarbon reservoirs is proven to improve their productivity to an extent that has rendered them economically viable. Generally, the stimulation design is a complex process dependent on intertwining factors such as the history of the formation, rock and reservoir fluid type, lithology and structural layout of the formation, cost, time, etc. A holistic grasp of these can be daunting, especially for people without sufficient experience and/or expertise in the exploitation of unconventional hydrocarbon reserves. This book presents the key facets integral to producing unconventional resources, and how the different components, if pieced together, can be used to create an integrated stimulation design. Areas covered are as follows: • stimulation methods, • fracturing fluids, • mixing and behavior of reservoir fluids, • assessment of reservoir performance, • integration of surface drilling data, • estimation of geomechanical properties and hydrocarbon saturation, and • health and safety. Exploitation of Unconventional Oil and Gas Resources: Hydraulic Fracturing and Other Recovery and Assessment Techniques is an excellent introduction to the subject area of unconventional oil and gas reservoirs, but it also complements existing information in the same discipline. It is an essential text for higher education students and professionals in academia, research, and the industry.

Download or read book Study of Alternating Anionic Surfactant and Gas Injection in Carbonate Cores written by Pinaki Ghosh (M.S. in Engineering) and published by . This book was released on 2016 with total page 196 pages. Available in PDF, EPUB and Kindle. Book excerpt: A major portion of the oil across the world is contained in carbonate reservoirs. Most of the carbonate reservoirs are typically oil-wet or mixed-wet, hence water-flooding processes have low oil recovery. Hence the most common mechanisms applied to increase the recovery are through wettability alteration and ultra-low interfacial tension (IFT) formulations with the addition of surfactants, or gas injection to have immiscible and miscible displacement processes, or combination of these processes. Secondary immiscible gas floods have been applied for several years in carbonate reservoirs and the typical recovery is found to be around 35-40% OOIP. The problems associated with many gas injection processes are the inefficient gas utilization, poor sweep efficiency, and low incremental oil recovery due to viscous instability (channeling or fingering) and gravity segregation. These are mainly caused by rock heterogeneity as well as the low density and viscosity of the injected gas. To address these drawbacks foam can be injected into the oil reservoir by co-injection of surfactant solution and gas, or by surfactant-alternating-gas (SAG) mode. The strategy implemented here is to inject a surfactant that causes wettability alteration or ultra-low IFT to recover additional oil followed by gas injection which helps in generation of foam and provides mobility control to achieve better sweep efficiency. The main objective of this research is to study the effect of slug size variation on oil recovery in surfactant-alternating-gas (SAG) processes for carbonate rocks using a wettability alteration anionic surfactant solution. The bulk foam stability in the presence and absence of the crude oil were studied for several surfactants. In addition, phase behavior studies and wettability alteration experiments were performed with the crude oil to screen the surfactant solutions. A propoxy sulfate surfactant, Alfoterra (0.5 wt%) was found to be optimal for these studies. Coreflood experiments in the absence of oil were performed in outcrop Texas Cream limestone rocks to measure the apparent foam viscosity and single phase pressure drop in presence of 80% quality foam, in comparison to 80% quality gas-brine co-injection as a base case. The resistance factor (measured as the ratio of pressure drop with foam and without foam) was found to be 3.5. Coreflood experiments with surfactant-alternating-gas (SAG) mode were performed in oil aged reservoir limestone rocks and outcrop carbonate rocks using Alfoterra (0.5 wt%). The coreflood experiments with a single slug of 0.5 PV surfactant solution showed additional oil recovery of about 25% OOIP in the outcrop rock. The average pressure drop during the experiment was in the range of 5-15 psi. The coreflood experiments with limestone rocks from a reservoir showed an additional oil recovery of about 25% OOIP for 0.1 PV slug size and smaller slug size injection of 0.05 PV showed an additional oil recovery of about 28% OOIP. The average pressure drop recorded was comparatively higher in the range of 40-60 psi for smaller slug sixe injection. Smaller slug size leads to higher oil recovery. The dynamic adsorption measured for Alf S23-7S-90 (S1) in Texas Cream limestone rock was found to be about 0.112 mg/gm of rock.

Download or read book Foam Assisted Low Interfacial Tension Enhanced Oil Recovery written by Mayank Srivastava and published by . This book was released on 2010 with total page 432 pages. Available in PDF, EPUB and Kindle. Book excerpt: Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II( - ) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II( - )) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO2) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO2 reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N2) forms stronger foam than CO2. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment.