Download or read book Experimental Investigation of Imbibition in Oil wet Carbonates Under Low IFT Conditions written by Yuxiang Li (M.S. in Engineering) and published by . This book was released on 2016 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Wettability Alteration by Glycine and Seawater Injection in Carbonate Reservoirs written by Ricardo Antonio Lara Orozco and published by . This book was released on 2022 with total page 0 pages. Available in PDF, EPUB and Kindle. Book excerpt: Carbonate reservoirs contain more than half of the world’s conventional oil reserves. However, since most carbonates are naturally fractured and oil- to mixed-wet there is often significant oil saturation remaining after waterflooding. This is because the injected water mostly flows through the fractures without imbibing into the oil-wet matrix. There is an increasing interest in finding low-cost and enviromentally-friendly wettability modifiers that promote water imbibition by shiftting the wetting state of the rock matrix. These injected chemicals, however, must be able to withstand the high temperatures and high salinity brines typically found in carbonate reservoirs. This study presents experimental investigation and modeling work of the application of glycine as a wettability modifier for carbonate reservoirs to improve oil recovery. We first investigated the potential of glycine in altering the wettability of carbonate surfaces. The experiment consisted of monitoring the contact angle of oil droplets placed on top of natural calcite pieces at 95°C for 5 days. The calcite surface remained oil-wet when submerged in formation brine with an average contact angle of 130°. Similar results were obtained with seawater (SW) with a contact angle of 128°. Low salinity water (LSW) was also tested by diluting SW ten times. It resulted in an average contact angle of 108°. In contrast, a strongly water-wet condition was obtained using FB with a glycine concentration of 5 wt% with an average contact angle of 50°. The oil droplets started to detach from the surface on the fourth day. This was direct evidence of the effect of glycine on altering the wetting-state of carbonate surfaces. We then investigated the enhance oil recovery in carbonate rocks by glycine. Spontaneous imbibition experiments were performed at 95 °C with Indiana Limestone cores. Glycine solutions were prepared with FB, SW, and LSW, with a concentration of 5 wt% and compared to LSW. On average, the glycine solutions recovered about 25% more oil than LSW. The recovery factor as a function of the squared root of time showed a linear trend typical of capillary-dominated flow. Glycine significantly enhanced oil recovery in high temperature and high salinity conditions by promoting spontaneous imbibition of water. An explanation to the previous experimental results is that glycine anion interacts with the positively charged surface of carbonate rocks. Wettability alteration then occurs by glycine adsorption and the corresponding removal of organic material from the rock surface. Based on this hypothesis, this research proposes a surface complexation reaction between glycine and carboxylic acids to model wettability alteration. The equilibrium constant was obtained by matching the zeta potential measurements of synthetic calcite in glycine solutions. The tuned surface complexation model (SCM) was used to investigate the desorption of carboxylic acids as a function of glycine concentration and temperature. The results correlated with the contact angle measurements and the recovery factor from the spontaneous imbibition experiments. High temperature was found to be critical for wettability alteration because it increases the concentration of glycine anion in the aqueous phase. Finally, we coupled the SCM in PHREEQC with a numerical model of two-phase flow displacement to investigate the major geochemical reactions driving wettability alteration in carbonates. We found that eight surface complexation reactions in the SCM can be simplified into a couple of anion exchange reactions between the injected wettability modifiers, glycine anion, sulfate ion, and the adsorbed carboxylic acids. Analytical solutions are then presented for the coupled two-phase and multicomponent reactive-transport model with anion exchange reactions to model the injection of wettability modifiers in carbonates

Download or read book Experiments and Modeling of Wettability Alteration in Low Permeability Porous Media written by Prateek Kathel and published by . This book was released on 2015 with total page 388 pages. Available in PDF, EPUB and Kindle. Book excerpt: Naturally fractured reservoirs contain a significant amount of global hydrocarbon reserves. In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. Wettability alteration provides a possible solution to enhance oil recovery in oil/mixed-wet fractured formations. Different chemicals such as surfactants, enzymes, selective ions can be used to alter wettability from oil-wet towards more water-wet which can substantially increase the oil recovery. Understanding recovery mechanisms for these processes at different inverse bond numbers (ratio of capillary to buoyancy forces) and developing scaling rules are critical for estimating feasibility at field scale. Surfactants were identified which altered the wettability of a low permeability (0.03 – 0.23 mD) mixed-wet/oil-wet sandstone reservoir. Static imbibition experiments in the surfactant solution resulted in high oil recovery (42-68% OOIP) compared to 15% OOIP in formation brine. High (>240) inverse bond numbers for these experiments indicate recovery mechanism as counter-current imbibition driven by capillary forces. Numerically simulated saturation and velocity profiles on validated datasets were analyzed to study the recovery mechanisms. Velocity profiles indicate counter current flows with velocity vectors pointing outwards. Similar visual observations were made during experiments, which were captured through images. The saturation front moves radially inward with symmetric profiles at the top and bottom. An analysis of scaling laws for the capillary driven flow suggests that imbibition recovery curves do not correlate with traditional scaling groups (Mattax and Kyte, 1962; Ma et al. 1997). The scaling equations analyzed are for strongly water-wet porous media and are insufficient to explain the dynamics of changing wettability from oil-wet to water-wet. The recovery data shows that oil recovery varies linearly with square root of time. It was observed that the rate of recovery was higher for the higher IFT cases in experiments performed on cores with almost same initial oil saturation using the same surfactant, but at different salinities. As a result of varying the salinity, interfacial tension between oil/water is varied. To evaluate the application of wettability altering processes at larger scales experiments were performed on outcrop cores of different dimensions and at dynamic conditions. Surfactant formulation was developed which altered the wettability from oil-wet to water-wet on outcrop rocks Estaillades Limestone and Texas Cream Limestone. Using the surfactant formulation static and dynamic imbibition experiments were performed on cores with different dimensions and boundary conditions. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. Study of numerically simulated velocity and saturation profile on validated input datasets established the recovery mechanism as gravity dominated flow. Analytical scaling groups for gravity dominated flow were tested considering pressure drop only in water phase, pressure drop only in oil phase, and pressure drop across both water and oil phases. The model with pressure drop in both phases captures the decrease in recovery with increase in diameter and height of the core. Sensitivity to change in oil recovery with change in height is fairly accurate whereas the model over-predicts oil recovery with change in diameter. A new space-time scaling function (t/DH) is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data from different studies indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition cases. Corefloods were performed on cores from different reservoirs to study the effect of wettability altering surfactant flood in a viscous pressure gradient driven process (as opposed to capillary or buoyancy driven imbibition process). Incremental oil recoveries over waterflood were analyzed for different injection schemes. Incremental recoveries over waterflood of 16% and 11% were obtained for secondary surfactant flood and slug process (surfactant slug injection after short initial waterflood) respectively for carbonate reservoir 1. Similarly, incremental recoveries over waterflood of 11% and 7% were obtained for secondary surfactant flood and slug process respectively for carbonate reservoir 2. The incremental oil recovery due to surfactant injection is attributed to the favorable increase in the relative permeability values of oil as the wettability is changed from oil-wet to water-wet. Experiments indicate that surfactant performance at the reservoir conditions (temperature, salinity, heterogeneity) is a key variable in these processes. Despite the differences in these conditions, for both the reservoirs oil recovery is more in the secondary surfactant injection mode compared to the slug process.

Download or read book Multi scale Investigations of the Impact of Surfactant Structure on Oil Recovery from Natural Porous Media written by Vahideh Mirchi and published by . This book was released on 2018 with total page 181 pages. Available in PDF, EPUB and Kindle. Book excerpt: This study aims at establishing structure-function relationships relevant to surfactant-based enhanced oil recovery (EOR) under different wettability conditions. We present the results of an extensive, multi-scale experimental study designed to probe the effects of surfactant molecular structure on oil displacement in sandstone and carbonate rock samples. Initially a new framework was developed to methodically characterize the effect of surfactants on fundamental parameters governing fluid displacement in brine/oil/tight rock systems at reservoir conditions. For that, we present a detailed methodology for measuring the interfacial properties of these systems, including rock substrate preparation, thin needle utilization, fluid pre-equilibration, in-line density measurements, all of which are critically important due to surfactant partitioning in brine and oil phases. The experimental framework was first validated with simple ultra-low IFT systems using the rising/captive bubble technique, then the effect of pressure, temperature, surfactant concentration, and brine chemistry on IFT and CA were investigated in a systematic manner. Subsequently, the framework was used to examine the effect of hydrophobic and hydrophilic chain lengths of polyoxyethylenated nonionic surfactants on dynamic interfacial properties in porous media. It included comprehensive experimental examination of phase behavior, cloud point temperature, dynamic interfacial tension, dynamic contact angle, and spontaneous and forced imbibitions at ambient and reservoir conditions. This resulted in development of a new insight that relates the speed by which surfactants reduce interfacial tension to oil-brine displacement efficiency. This relationship was reconfirmed by examining pore-fluid occupancies generated through surfactant imbibition in micromodels. In order to directly study pore-level fluid distributions as a function of surfactant structure, a state-of-the-art X-ray micro-CT scanner integrated with a miniature core-flooding apparatus was deployed to generate three-dimensional pore-fluid occupancy maps at the pore scale. The core-flooding results revealed that there is an additional set of factors besides pore geometry, rock surface wettability, fluid-fluid interfacial tension, and fluids’ viscosities, densities, and flow rates that directly contributes to the distribution of fluids at the pore scale. We demonstrate that under similar rock and fluid properties, interfacial repulsive and attractive interactions, caused by the adsorption of surface-active chemicals on fluid-fluid interfaces, can significantly alter pore-scale fluid occupancies. Oil cluster analyses along with three-dimensional (3D) visualization of fluid distributions indicate that using the nonionic surfactant with large head instead of the anionic surfactant with small head results in the breaking up of the large and medium oil clusters into smaller and scattered ones. We propose a mechanism relating the stability of oil-brine interface to surfactant structure that is responsible for the break-up and/or coalescence of oil clusters inside the pore space. The suggested mechanism is confirmed by the micro-CT images and associated oil cluster analyses. This phenomenon affects the competition between the frequency of displacement mechanisms causing variations in remaining oil saturations. Using the same microtomography technique, we developed a significantly-improved understanding of pore-level displacement mechanisms during low-salinity surfactant flooding in oil-wet carbonates. In this contribution, in-situ fluid distribution maps, in-situ contact angles, and thicknesses of wetting oil layers were investigated under different brine salinities in the presence and absence of a cationic surfactant at elevated pressure and temperature conditions. The investigation revealed that enhanced oil production during low-salinity surfactant waterflooding is caused by several factors such as a rapid alteration of in-situ contact angles toward neutral-wet state, layer thinning of the oil phase, and an increase in the contribution of small-sized pores to the total oil production. The wettability reversal was more profound when the surfactant injection was succeeding a low-salinity waterflooding. The insights gained in this work using different surfactant molecular structures, rock types, brine salinities, and wettability conditions have direct implications for the design of more effective surfactant-based EOR projects.

Download or read book Proceedings of the International Field Exploration and Development Conference 2022 written by Jia'en Lin and published by Springer Nature. This book was released on 2023-08-05 with total page 7600 pages. Available in PDF, EPUB and Kindle. Book excerpt: This book focuses on reservoir surveillance and management, reservoir evaluation and dynamic description, reservoir production stimulation and EOR, ultra-tight reservoir, unconventional oil and gas resources technology, oil and gas well production testing, and geomechanics. This book is a compilation of selected papers from the 12th International Field Exploration and Development Conference (IFEDC 2022). The conference not only provides a platform to exchanges experience, but also promotes the development of scientific research in oil & gas exploration and production. The main audience for the work includes reservoir engineer, geological engineer, enterprise managers, senior engineers as well as professional students.

Download or read book Surfactant enhanced Spontaneous Imbibition Process in Highly Fractured Carbonate Reservoirs written by Peila Chen and published by . This book was released on 2011 with total page 196 pages. Available in PDF, EPUB and Kindle. Book excerpt: Highly fractured carbonate reservoirs are a class of reservoirs characterized by high conductivity fractures surrounding low permeability matrix blocks. In these reservoirs, wettability alteration is a key method for recovering oil. Water imbibes into the matrix blocks upon water flooding if the reservoir rock is water-wet. However, many carbonate reservoirs are oil-wet. Surfactant solution was used to enhance spontaneous imbibition between the fractures and the matrix by both wettability alteration and ultra-low interfacial tensions. The first part of this study was devoted to determining the wettability of reservoir rocks using Amott-Harvey Index method, and also evaluating the performance of surfactants on wettability alteration, based on the contact angle measurement and spontaneous imbibition rate and ultimate oil recovery on oil-wet reservoir cores. The reservoir rocks have been found to be slightly oil-wet. One cationic surfactant BTC8358, one anionic surfactant and one ultra-low IFT surfactant formulation AKL-207 are all found to alter the wettability towards more water-wet and promote oil recovery through spontaneous imbibition. The second part of the study focused on the parameters that affect wettability alteration by surfactants. Some factors such as core dimension, permeability and heterogeneity of porous medium are evaluated in the spontaneous imbibition tests. Higher permeability leads to higher imbibition rate and higher ultimate oil recovery. Heterogeneity of core samples slows down the imbibition process if other properties are similar. Core dimension is critical in upscaling from laboratory conditions to field matrix blocks. The imbibition rate is slower in larger dimension of core. Further, we investigated the effects of EDTA in surfactant-mediated spontaneous imbibition. Since high concentration of cationic divalent ions in the aqueous solution markedly suppresses the surfactant-mediated wettability alteration, EDTA improved the performance of surfactant in the spontaneous imbibition tests. It is proposed in the thesis that surfactant/EDTA-enhanced imbibition may involve the dissolution mechanism. More experiments should be conducted to verify this mechanism. The benefits of using EDTA in the surfactant solution include but not limited to: altering the surface charge of carbonate to negative, producing the in-situ soap, reducing the brine hardness, decreasing the surfactant adsorption, and creating the water-wet area by dissolving the dolomite mineral.

Download or read book Aspects of Oil Recovery by Spontaneous Imbibition and Wettability Alteration written by Siluni Wickramathilaka and published by . This book was released on 2011 with total page 271 pages. Available in PDF, EPUB and Kindle. Book excerpt: Spontaneous imbibition is one of the key mechanisms for oil production from naturally fractured reservoirs. The final oil recovery and the rate of oil recovery by spontaneous imbibition depend on many rock and fluid properties and wettability of the rock. Important factors that affect wettability are the rock type, initial water saturation, crude oil type, aging time, brine composition and salinity, and displacement temperature. Understanding wettability through spontaneous imbibition studies is crucial because wettability can affect the fluid location, fluid flow, and residual oil distributions of reservoirs. Many factors that affect imbibition oil recovery and wettability have not been studied extensively for carbonates. Better understanding of the effects of wettability and scaling laboratory spontaneous imbibition data is important to predicting oil recovery from fractured reservoirs. The objectives of the present study were to investigate various crude oil/brine/rock (COBR) interactions and factors which could affect wettability, to evaluate correlation of spontaneous imbibition data with various wetting conditions for carbonates, and to improve oil recovery by spontaneous imbibition with change in invading brine composition and salinity and by use of surfactants. Reproducibility of the spontaneous imbibition results is also emphasized. The variation of aqueous phase viscosity was performed for three distinct wettability conditions classed as Very Strongly Water-Wet (VSWW), Uniformly-Wet (UW-CO) and Mixed-Wet (MXW), to study the effects on spontaneous imbibition as well as to extend previous studies on spontaneous imbibition correlations. The Mason et al. (2010) scaling group (a modification of the Ma et al. (1997) scaling group) developed mainly for wide variation in aqueous phase viscosities of VSWW Berea sandstone was used to satisfactorily correlate most of the data obtained for VSWW carbonate spontaneous imbibition results. The mechanism of VSWW imbibition was investigated by use of Magnetic Resonance Imaging (MRI) to monitor oil recovery from spontaneous imbibition of brine. The saturation profiles and images obtained for linear and radial imbibition indicate that the pore structure plays a significant role during spontaneous imbibition of brine into an oil saturated rock. Formation of a sharp piston-like imbibition front also validates previous assumptions made for development of imbibition scaling groups. Under wettability conditions that made capillary forces very weak, imbibition was controlled by change in density of the aqueous phase. For UW-CO, improved correlation was given by using weighted viscosity terms. Data was correlated by scaling with respect to the product of dimensionless time (basically the ratio of capillary to viscous forces) times the ratio of gravity to capillary forces. The initial water saturation, crude oil type, aging time, and displacement temperature have been varied for selected rocks to evaluate wettability and its effects on oil recovery by spontaneous imbibition. Improved oil recovery was demonstrated for spontaneous imbibition through reduction in invading brine salinity and also by addition of various types of anionic, amphoteric, cationic, and nonionic surfactants. Increases in recovery were fastest and highest for nonionic surfactants.

Download or read book Imbibition of Anionic Surfactant Solution Into Oil wet Matrix in Fractured Reservoirs written by Mohammad Mirzaei Galeh Kalaei and published by . This book was released on 2013 with total page 656 pages. Available in PDF, EPUB and Kindle. Book excerpt: 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.

Download or read book Nanorobotics written by Constantinos Mavroidis and published by Springer Science & Business Media. This book was released on 2013-01-04 with total page 464 pages. Available in PDF, EPUB and Kindle. Book excerpt: Nanorobots can be defined as intelligent systems with overall dimensions at or below the micrometer range that are made of assemblies of nanoscale components with individual dimensions ranging between 1 to 100 nm. These devices can now perform a wide variety of tasks at the nanoscale in a wide variety of fields including but not limited to fields such as manufacturing, medicine, supply chain, biology, and aerospace. Nanorobotics: Current Approaches and Techniques offers a comprehensive overview of this emerging interdisciplinary field with a wide ranging discussion that includes nano-manipulation and industrial nanorobotics, nanorobotic manipulation in biology and medicine, nanorobotic sensing, navigation and swarm behavior and CNT, and protein and DNA-based nanorobotics.

Download or read book Pore scale Characterization of Wettability and Displacement Mechanisms During Oil Mobilization Due to Waterflood based Oil Recovery Schemes written by Mahdi Khishvand and published by . This book was released on 2018 with total page 217 pages. Available in PDF, EPUB and Kindle. Book excerpt: We present the results of an extensive pore-scale experimental study of trapping of oil in topologically disordered naturally-occurring pore spaces. A unique miniature core-flooding system is built and then integrated with a high-resolution micro-computed tomography (micro-CT) scanner to create a new experimental platform, which enables us to conduct flow experiments on a small rock specimen, nominally 5-mm-diameter, at conditions representative of subsurface reservoirs while the sample is being imaged. We develop robust experimental procedures and state-of-the-art image analysis techniques to characterize in-situ wettability and accurately map the spatial distribution of fluid phases at the pore level during various multiphase flow phenomena. This indeed has the possibility to transform our understanding of these important flow processes and allows us to have a much more effective way of designing enhanced oil recovery schemes deployed in a wide range of geological systems. Below, we list four key applications of this new approach, which are achieved under this study. These include: (1) In-situ characterization of wettability and pore-scale displacement mechanisms; (2) Micro-scale investigation of the effects of flow rate on nonwetting phase trapping; (3) Systematic examination of the impact of brine salinity on residual phase saturation; and (4) Experimental study of the remobilization of trapped oil ganglia associated with CO2 exsolution during carbonated water injection. Initially, we perform several two-phase experiments on Berea sandstone core samples and characterize contact angle hysteresis for various fluid pairs. Afterward, we carry out a three-phase experiment including a secondary gas injection followed by a waterflood and then an oilflood. We generate in-situ oil-water, gas-water, and gas-oil contact angle distributions during each stage of this flow experiment and compare them with the two-phase counterparts to develop new insights into relevant complex displacement mechanisms. The results indicate that, during gas injection, the majority of displacements involving oil and water are oil-to-water events. It is observed that, during the waterflood, both oil-to-gas and gas-to-oil displacement events take place. However, the relative frequency of the former is greater. For the oilflood, gas-water interfaces only slightly hinge in pore elements. Pore-scale fluid occupancy maps and the Bartell-Osterhoff constraint verify the above-mentioned findings. Secondly we conduct a pore-scale experimental study of residual trapping on consolidated water-wet sandstone and carbonate rock samples. We investigate how the changes in wetting phase flow rate impacts pore-scale trapping of the nonwetting phase as well as size and distribution of its disconnected globules. The results show that with increase in imbibition flow rate, the residual oil saturation reduces from 0.46 to 0.20 in Bemtheimer sandstone and from 0.46 to 0.28 in Gambier limestone. The reduction is believed to be caused by alteration of the order in which pore-scale displacements took place during imbibition. We use pore-scale displacement mechanisms, in-situ wettability characteristics, and pore size distribution information to explain the observed capillary desaturation trends. Furthermore, we explore that the volume of individual trapped oil globules decreases at higher brine flow rates. Moreover, it is found that the pore space in the limestone sample is considerably altered through matrix dissolution at extremely high brine flow rates. Imbibition in the altered pore space produces lower residual oil saturation (from 0.28 to 0.22) and significantly different distribution of trapped oil globules. Thirdly, a series of micro- and core-scale flow experiments are carried out on mixed-wet reservoir sandstone core samples at elevated temperature and pressure conditions to examine the impact of injection brine salinity on oil recovery and accentuate governing displacement mechanisms. Individual core samples are cut from a preserved reservoir whole core, saturated to establish initial reservoir fluid saturation conditions, and subsequently waterflooded with low- and high-salinity brines. In addition to the preserved experiments, several samples are cleaned, subjected to a wettability restoration process, and then used for waterflooding experiments. The results indicate approximate waterflood residual oil saturations (S[subscript]orw) of 0.25 and 0.39 for LSWF and HSWF, respectively. These observations highlight the remarkably superior performance of LSWF compared to that of HSWF. LSWF tests show a more prolonged oil recovery response than HSWF. The findings provide direct evidence that LSWF also causes a wettability alteration toward increasing water-wetness – due to limited release of mixed-wet clay particles and multi-component ion exchange, whereas contact angles measured during HSWF remain unchanged. It is observed that the reduction in oil-water contact angles lowers the threshold water pressure needed to displace oil from some medium-sized pore elements and enhances oil recovery during LSWF. Finally, we present the results of a micro-scale three-phase experimental study, using a spreading fluid system, of carbonated water injection and subsequent CO2 exsolution, as a consequence of pressure depletion, that lead to recovery of a significant fraction of trapped oil. Micro-CT visualization of pore occupancy show that the gradual increase in the pressure drop leads to exsolution of CO2, internal gas drive, mobilization of oil ganglia, and a notable reduction in waterflood residual oil saturation. When contacted by CO2, oil globules form thick spreading layers sandwiched between brine (in the corners) and gas (in the center of pores) and are displaced toward the outlet along with moving gas clusters. We observe significant re-connection of trapped oil globules due to oil layer formation during early stages of CWI. The oil layers stay stable until the very late stages of gas exsolution.

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 Effect of Changing Injection Water Salinity on Oil Recovery from Oil wet Carbonate Rocks written by Ugur Pakoz and published by . This book was released on 2015 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Experimental studies and some field applications have shown that tuning the salinity of the injected water can affect oil recovery from water flooding. Most of the available literature has dedicated efforts to investigate the effect of low salinity water injection, especially for sandstone. Further studies on carbonate rocks also proved that low salinity effect might be observed for carbonate rocks as well. The main mechanism for the improved oil recovery from low salinity water flooding has been attributed to wettability alteration. The purpose of this work is to further investigate the effect of water salinity on oil recovery from oil-wet carbonate rocks. A series of core flood experiments were performed in the laboratory to measure and compare oil recovery from increasing and decreasing salinity floods at room temperature. Selected carbonate cores were aged with synthetic oil at 100 oC for 12 days prior to core flooding. Contact angles were measured on pre-aged and post-aged core slices to validate aging procedure and oil-wet conditions. Both, increasing and decreasing salinity floods showed measurable recovery gains in the secondary and tertiary modes compared with initial floods. In case of increasing water salinity, 1.3% and 0.6% additional recoveries were obtained while in the case of decreasing water salinity, additional recoveries were 0.6% and 0.7%, all in terms of original oil in place in the core. Results suggest that the system disturbance caused by the change in injection water salinity may have a greater influence on oil recovery than wettability alteration under the laboratory conditions tested.

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 LABORATORY INVESTIGATION OF OIL COMPOSITION AFFECTING THE SUCCESS OF LOW SALINITY WATERFLOODING IN OIL WET CARBONATE ROCKS written by Gregory Kojadinovich and published by . This book was released on 2018 with total page pages. Available in PDF, EPUB and Kindle. Book excerpt: Improved oil recovery via wettability alteration by tuning the ionic composition of the injection water has been thoroughly researched in recent years. It has been well documented that seawater can increase the water wetness of chalk at high temperature. Forced displacement and spontaneous imbibition experiments have attributed the wettability alteration to interactions between active ions in the brine, Ca2+, Mg2+, and SO42-, the rock surface, and the oil phase. It has been suggested that the adsorption of SO42- onto the rock surface causes the bond between adsorbed carboxylic material in the crude oil and the rock surface to deteriorate which causes the release of the crude oil. Reduction in ionic strength of the injection water has also been proposed to trigger the effect of wettability alteration in carbonates. Although the numerous experiments devoted to understanding the mechanisms governing the low salinity effect in the past two decades, there has been no consensus about the dominant mechanisms driving wettability alteration. The purpose of this research is to improve the understanding of how reduced ionic strength and potentially determining ions (PDIs) contribute to oil recovery, as well as provide a direct comparison of their oil recovery performance for a synthetic oil versus crude oil during waterflooding. For this, a series of waterflood experiments were conducted in the laboratory at 90 C in Indiana limestone core plugs. Chemically tuned brines derived from seawater were used in secondary and tertiary recovery modes to displace synthetic oil. A waterflood with formation brine was also conducted as an experimental baseline to assess the advantages of low-salinity waterflooding over typical secondary recovery methods. Effluent analysis was conducted to evaluate the surface interactions occurring between the brine and rock surface. Gas chromatography-mass spectroscopy was performed to compare the chemical make-up of the synthetic and crude oil. Oil recovery curves from this study indicate that there was no benefit after increasing the concentration of PDIs in injection water compared to seawater (SW). However, the use of seawater and all chemically tuned brines derived from seawater resulted in an average 6.47% increase in oil recovery post water breakthrough, relative to the formation brine waterflood. The success of wettability alteration leading to improved oil recovery in carbonates has been noted as a strong function of the oil composition.

Download or read book Enhanced Oil Recovery from a Carbonate Reservoir written by Medina Joshua Anthony and published by . This book was released on 2021 with total page 38 pages. Available in PDF, EPUB and Kindle. Book excerpt: With the ever-growing demand for oil & gas in the world today, and the increasing difficulty of recovering hydrocarbons from reservoirs, it is becoming ever so vital to apply enhanced oil recovery (EOR) techniques. Carbonate reservoirs typically have natural fractures and are found natively to have oil-wet matrixes. These properties make enhanced oil recovery from these reservoirs more challenging. Wettability alteration is a viable EOR mechanism in this scenario. However, there is ambiguity about which chemical solutions apply best to carbonate reservoirs since there is minimal information related to such formations. With the utilization of surfactants as a wettability altering agent, greater recoveries of hydrocarbons may be attained. In this study, we assessed the capabilities of various surfactants’ interfacial properties and their ability to perform wettability alterations at reservoir conditions. All surfactants were evaluated by solubilization and emulsification experiments at ambient conditions, then at high-temperature conditions. Spontaneous imbibition experiments were performed on outcrop carbonate limestone rocks to gauge chemical effects on the distinct rock type while considering the impact of the chemical group. Dynamic interfacial tension (IFT) and wettability alteration were the two main mechanisms for oil recovery studied. In the conclusion of this study, an optimum solution was identified and recommended for a Limestone reservoir.

Download or read book Carbonate Petroleum Reservoirs written by P.O. Roehl and published by Springer Science & Business Media. This book was released on 2012-12-06 with total page 587 pages. Available in PDF, EPUB and Kindle. Book excerpt: The case history approach has an impressive record of success in a variety of disciplines. Collections of case histories, casebooks, are now widely used in all sorts of specialties other than in their familiar application to law and medicine. The case method had its formal beginning at Harvard in 1871 when Christopher Lagdell developed it as a means of teaching. It was so successful in teaching law that it was soon adopted in medical education, and the col lection of cases provided the raw material for research on various diseases. Subsequently, the case history approach spread to such varied fields as busi ness, psychology, management, and economics, and there are over 100 books in print that use this approach. The idea for a series of Casebooks in Earth Sciences grew from my ex perience in organizing and editing a collection of examples of one variety of sedimentary deposits. The project began as an effort to bring some order to a large number of descriptions of these deposits that were so varied in pre sentation and terminology that even specialists found them difficult to compare and analyze. Thus, from the beginning, it was evident that something more than a simple collection of papers was needed. Accordingly, the nearly fifty contributors worked together with George de Vries Klein and me to establish a standard format for presenting the case histories.

Download or read book Enhanced Oil Recovery in Shale and Tight Reservoirs written by James J.Sheng and published by Gulf Professional Publishing. This book was released on 2019-11-07 with total page 538 pages. Available in PDF, EPUB and Kindle. Book excerpt: Oil Recovery in Shale and Tight Reservoirs delivers a current, state-of-the-art resource for engineers trying to manage unconventional hydrocarbon resources. Going beyond the traditional EOR methods, this book helps readers solve key challenges on the proper methods, technologies and options available. Engineers and researchers will find a systematic list of methods and applications, including gas and water injection, methods to improve liquid recovery, as well as spontaneous and forced imbibition. Rounding out with additional methods, such as air foam drive and energized fluids, this book gives engineers the knowledge they need to tackle the most complex oil and gas assets. Helps readers understand the methods and mechanisms for enhanced oil recovery technology, specifically for shale and tight oil reservoirs Includes available EOR methods, along with recent practical case studies that cover topics like fracturing fluid flow back Teaches additional methods, such as soaking after fracturing, thermal recovery and microbial EOR