Experimental Investigation of Surfactant Flooding in Fractured Limestones PDF Download

Author: Miguel Mejia (M.S. in Engineering)
Publisher:
ISBN:
Category :
Languages : en
Pages : 286

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Book Description
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

Author: Jose Ernesto Parra Perez
Publisher:
ISBN:
Category :
Languages : en
Pages : 202

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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.

Author: Miguel Mejia (M.S. in Engineering)
Publisher:
ISBN:
Category :
Languages : en
Pages : 0

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Book Description
Carbonate oil reservoirs are important energy sources, accounting for over 60% of the world’s oil reserves. Recovering oil from these reservoirs is challenging, especially if they are naturally fractured. Waterflooding is inefficient because water flows through the highly permeable fractures and bypasses the rock matrix, where most of the oil is stored. Mixed-wettability, low matrix permeability, and large heterogeneities also make secondary oil recovery challenging. Chemical enhanced oil recovery with alkali, surfactants, and polymer addresses some of these challenges. Surfactants can lower the interfacial tension to decrease the residual oil saturation. Polymer increases the viscosity of the injected water, improving the microscopic and macroscopic sweep efficiency. This research involves the optimization of some chemical flooding methods for naturally fractured carbonates. Coreflood experiments and the UTCHEM reservoir simulator were used to investigate alkali-surfactant flooding in fractured Texas Cream limestone cores. A decrease in fracture mobility caused by viscous phase trapping in the fracture was identified as the main reason for the high observed oil recoveries. Due to the uncertain properties of the viscous phase trapped in the fracture, polyethylene oxide (PEO) polymer was investigated for mobility control. Coreflood experiments demonstrated the viability for using PEO in 18 mD cores. PEO significantly improved oil recovery in a fractured core. The viscosity and cloud point of the PEO were systematically investigated. The polymer concentration, temperature, salinity and hardness were varied, and several additives were added to potentially increase the range of conditions for which PEO could be applied to EOR. Methyl-urea, urea, and ethanol were identified as additives to increase the cloud point and viscosity of PEO. Finally, machine learning models including support vector machine, random forest, and neural network models were trained to predict the aqueous stability of surfactant solutions and phase behavior of microemulsions. A large database of over 600 phase behavior experiments and over 800 aqueous stability experiments was used to train the models. The models may be used to guide the process of selection of surfactants that produce sufficiently high solubilization ratios

Author: Trevor Storm Pollock
Publisher:
ISBN:
Category :
Languages : en
Pages : 606

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Book Description
A limited number of laboratory studies and pilot programs have been reported in chemical Enhanced Oil Recovery (EOR) flooding of carbonate reservoirs (Adams & Schievelbein, 1987). Fewer still have involved surfactants in limestone reservoirs. No surfactant/polymer flood on a field wide basis of a carbonate reservoir has ever been documented in the literature (Manrique, Muci, & Gurfinkel, 2010). This void represents a colossal opportunity given that nearly a third of the 32 billion barrels of oil consumed in the world each year come from carbonate reservoirs (Sheng, 2011, pp. 1, 254). This thesis is based on experiments with a high hardness (~5,000 ppm divalent ions) carbonate field. Phase behavior, aqueous stability, and core flood experiments were performed using polymer and various surfactants and co-solvents. Both commercially available and laboratory synthesized surfactants were tested. The objective was to optimize the chemical injection design in order to lower interfacial tension between water and oil in the reservoir. Research was also done with alkali intended for use with hard brines. The main challenges when working with hard brine were poor solubilization and low aqueous stability limits. However, highly propoxylated and ethoxylated surfactants mixed with internal olefin sulfonates, hydrophilic sulfates, and sec-butanol were observed to have very high solubilization ratios, fast phase behavior equilibration times, negligible viscous macroemulsion effects, and excellent aqueous stability. Spinning drop interfacial tensiometer tests confirmed low IFT values were obtained for a range of acceptable salinities with hard brine. Three core floods were performed using one of the surfactant formulations developed. One flood was done with field core, brine, and crude oil and failed to meet expectations because of high levels of heterogeneity (vugs) within the core that lead to an elongated oil bank and low and slow oil recovery. The other floods were done with Estillades Limestone. The first Estillades flood used hard synthetic field brine and had better mobility but poor oil recovery. The last core flood had good mobility and recovered 90% of the residual oil to water flooding, but only after a total of 1.1 pore volumes of 1.0 wt% surfactant solution were injected. The results provided in this thesis constitute proof of concept that S/P flooding can be done in high salinity and hardness reservoirs.

Author: K.R.V. Subramanian
Publisher: CRC Press
ISBN: 0429886985
Category : Science
Languages : en
Pages : 532

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Nanofluids are solid-liquid composite material consisting of solid nanoparticles suspended in liquid with enhanced thermal properties. This book introduces basic fluid mechanics, conduction and convection in fluids, along with nanomaterials for nanofluids, property characterization, and outline applications of nanofluids in solar technology, machining and other special applications. Recent experiments on nanofluids have indicated significant increase in thermal conductivity compared with liquids without nanoparticles or larger particles, strong temperature dependence of thermal conductivity, and significant increase in critical heat flux in boiling heat transfer, all of which are covered in the book. Key Features Exclusive title focusing on niche engineering applications of nanofluids Contains high technical content especially in the areas of magnetic nanofluids and dilute oxide based nanofluids Feature examples from research applications such as solar technology and heat pipes Addresses heat transfer and thermodynamic features such as efficiency and work with mathematical rigor Focused in content with precise technical definitions and treatment

Author: D.O. Shah
Publisher: Elsevier
ISBN: 0323141579
Category : Technology & Engineering
Languages : en
Pages : 589

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Book Description
Improved Oil Recovery by Surfactant and Polymer Flooding contains papers presented at the 1976 AIChE Symposium on Improved Oil Recovery by Surfactant and Polymer Flooding held in Kansas City. Organized into 18 chapters, the book includes papers that introduce petroleum reservoirs and discuss interfacial tension; molecular forces; molecular aspects of ultralow interfacial tension; the structure, formation, and phase inversion of microemulsions; and thermodynamics of micellization and related phenomena. Papers on adsorption phenomena at solid/liquid interfaces and reservoir rocks, as well as on flow through porous media studies on polymer solutions, microemulsions, and soluble oils are also provided. Significant topics on molecular, microscopic, and macroscopic aspects of oil displacement in porous media by surfactant and polymer solutions and related phenomena are also discussed. The literature cited in this book forms a comprehensive list of references in relation to improved oil recovery by surfactant and polymer flooding. This book will be useful to experts and non-experts in this field of research.

Author: Mohammad Mirzaei Galeh Kalaei
Publisher:
ISBN:
Category :
Languages : en
Pages : 656

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Water-flooding in water-wet fractured reservoirs can recover significant amounts of oil through capillary driven imbibition. Unfortunately, many of the fractured reservoirs are mixed-wet/oil-wet and water-flooding leads to poor recovery as the capillary forces hinder imbibition. Surfactant injection and immiscible gas injection are two possible processes to improve recovery from fractured oil-wet reservoirs. In both these EOR methods, the gravity is the main driving force for oil recovery. Surfactant has been recommended and shown a great potential to improve oil recovery from oil-wet cores in the laboratory. To scale the results to field applications, the physics controlling the imbibition of surfactant solution and the scaling rules needs to be understood. The standard experiments for testing imbibition of surfactant solution involves an imbibition cell, where the core is placed in the surfactant solution and the recovery is measured versus time. Although these experiments prove the effectiveness of surfactants, little insight into the physics of the problem is achieved. This dissertation provides new core scale and pore scale information on imbibition of anionic surfactant solution into oil-wet porous media. In core scale, surfactant flooding into oil-wet fractured cores is performed and the imbibition of the surfactant solution into the core is monitored using X-ray computerized tomography(CT). The surfactant solution used is a mixture of several different surfactants and a co-solvent tailored to produce ultra-low interfacial tension (IFT) for the specific oil used in the study. From the CT images during surfactant flooding, the average penetration depth and the water saturation versus height and time is calculated. Cores of various sizes are used to better understand the effect of block dimension on imbibition behavior. The experimental results show that the brine injection into fractured oil-wet core only recovers oil present in the fracture; When the surfactant solution is injected, the CT images show the imbibition of surfactant solution into the matrix and increase in oil recovery. The surfactant solution imbibes as a front. The imbibition takes place both from the bottom and the sides of the core. The highest imbibition is observed close to the bottom of the core. The imbibition from the side decreases with height and lowest imbibition is observed close to the top of the core. Experiments with cores of different sizes show that increase in either the length or the diameter of the core causes decrease in the fractional recovery rate (%OOIP). Numerical simulation is also used to determine the physics that controls the imbibition profiles. %The numerical simulations show that the relative permeability curves strongly affect the imbibition profiles and should be well understood to accurately model the process. Both experimental and numerical simulation results imply that the gravity is the main driving force for the imbibition process. The traditional scaling group for gravity dominated imbibition only includes the length of the core to upscale the recovery for cores of different sizes. However based on the measurements and simulation results from this study, a new scaling group is proposed that includes both the diameter and the length of the core. It is shown that the new scaling group scales the recovery curves from this study better than the traditional scaling group. In field scale, the new scaling group predicts that the recovery from fractured oil-wet reservoirs by surfactant injection scales by both the vertical and horizontal fracture spacing. In addition to core scale experiments, capillary tube experiments are also performed. In these experiments, the displacement of oil by anionic surfactant solutions in oil-wet horizontal capillary tubes is studied. The position of the oil-aqueous phase interface is recorded with time. Several experimental parameters including the capillary tube radius and surfactant solution viscosity are varied to study their effect on the interface speed. Two different models are used to predict the oil-aqueous phase interface position with time. In the first model, it is assumed that the IFT is constant and ultra-low throughout the experiments. The second model involves change of wettability and IFT by adsorption of surfactant molecules to the oil-water interface and the solid surface. Comparing the predictions to the experimental results, it is observed that the second model provides a better match, especially for smaller capillary tubes. The model is then used to predict the imbibition rate for very small capillary tubes, which have equivalent permeability close to oil reservoirs. The results show that the oil displacement rate is limited by the rate of diffusion of surfactant molecules to the interface. In addition to surfactant flooding, immiscible gas injection can also improve recovery from fractured oil-wet reservoirs. In this process, the injected gas drains the oil in the matrix by gravity forces. Gravity drainage of oil with gas is an efficient recovery method in strongly water-wet reservoirs and yields very low residual oil saturations. However, many of the oil-producing fractured reservoirs are not strongly water-wet. Thus, predicting the profiles and ultimate recovery for mixed and oil-wet media is essential to design and optimization of improved recovery methods based on three-phase gravity drainage. In this dissertation, we provide the results from two- and three-phase gravity drainage experiments in sand-packed columns with varying wettability. The results show that the residual oil saturation from three-phase gravity drainage increases with increase in the fraction of oil-wet sand. A simple method is proposed for predicting the three-phase equilibrium saturation profiles as a function of wettability. In each case, the three-phase results were compared to the predictions from two-phase results of the same wettability. It is found that the gas/oil and oil/water transition levels can be predicted from pressure continuity arguments and the two-phase data. The predictions of three-phase saturations work well for the water-wet media, but become progressively worse with increasing oil-wet fraction.

Author: Patrizio Raffa
Publisher: Walter de Gruyter GmbH & Co KG
ISBN: 3110640430
Category : Technology & Engineering
Languages : en
Pages : 277

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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).

Author: Muhammad Tahir
Publisher:
ISBN:
Category :
Languages : en
Pages : 0

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Author: Yuxiang Li (M.S. in Engineering)
Publisher:
ISBN:
Category :
Languages : en
Pages : 0

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Natural reservoir drives and waterflooding in naturally fractured carbonate reservoirs with an oil-wet matrix generate very low oil production. Surfactants enhance oil recovery in these reservoirs by altering wettability and reducing interfacial tension (IFT). The main purpose of this research was to determine how to scale up low IFT surfactant imbibition from the lab to fractured, oil-wet carbonate reservoirs. A series of imbibition experiments were conducted using cores with different horizontal (i.e. diameter) and vertical (i.e. height) dimensions. Their fractional oil recoveries (% OOIP) were systematically measured to better understand how to scale up the surfactant imbibition process. There was a particular need to perform experiments using cores with larger horizontal dimensions since almost all previous experiments in the literature used cores with a small diameter, typically 3.8 cm. The core diameters in this study varied from 3.8 to 20 cm. The traditional static imbibition experimental method was adapted and modified by periodically flushing out fluids surrounding the cores inside the cells to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. The high performance surfactant formulations for the oils used on in this study were developed using microemulsion phase behavior tests. These surfactants gave ultra-low IFT (on the order of 0.001 dynes/cm) at optimal salinity and good aqueous stability. Although most of the experiments used ultra-low IFT formulations, experiments using higher IFT (on the order of 0.1 dynes/cm) formulations were also performed for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. In addition, experiments were done to understand the role of other variables on oil recovery, such as matrix permeability, surfactant and co-solvent concentrations, microemulsion viscosity, and oil viscosity. A simple analytical model was developed to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock and fluid properties, and time. The model and experimental data are in good agreement considering the many simplifications made to derive the model. Both experimental data and the model showed that the oil recovery was lower for cores with larger horizontal and vertical dimensions. However, the decrease was not proportional to an increase in these dimensions. The scaling implied by the model is significantly different than the traditional scaling groups in the literature.