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Collaborating Authors
Results
Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs
Yutkin, M. P. (King Abdullah University of Science and Technology) | Kaprielova, K. M. (King Abdullah University of Science and Technology) | Kamireddy, S. (King Abdullah University of Science and Technology) | Gmira, A. (Saudi Aramco) | Ayirala, S. C. (Saudi Aramco) | Radke, C. J. (University of California โ Berkeley) | Patzek, T. W. (KAUST)
Abstract This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons. The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process. In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity. Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.48)
Abstract Most chemical EOR formulations are surfactant mixtures, but these mixtures are usually modeled as a single pseudo-component in reservoir simulators. However, the composition of an injected surfactant mixture changes as it flows through a reservoir. For example, as the mixture is diluted, the CMC changes, which changes both the adsorption of each surfactant component and the microemulsion phase behavior. Modeling the physical chemistry of surfactant mixtures in a reservoir simulator was found to be more significant than anticipated and is needed to make accurate reservoir-scale predictions of both chemical floods and the use of surfactants to stimulate shale wells.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- Geology > Mineral (0.46)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Abstract The wettability alteration is the most prominent mechanism for a favorable effect of low salinity water flooding in enhanced oil recovery. It has been accepted that the surface charge at crude oil/brine and rock/brine interfaces significantly influences the interaction of the crude oil with rock surface and thus wettability changes. In this study, the interface characteristics were coupled with a solute transport model to simulate low salinity waterflooding in carbonate and sandstone reservoirs. The ionic transport and two- phase flow of oil and water equations were solved and coupled with IPhreeqc for geochemical calculations. The dissolution and precipitation of minerals were considered thorough thermodynamic equilibrium reactions in IPhreeqc. In addition, a triple layer surface complexation model was employed in IPhreeqc to predict electrokinetic properties of crude oil/brine and rock/brine interfaces. The wettability alteration was calculated based the adsorbed polar components of crude oil on mineralsโ surface, which changes the relative permeability. The coupled model able to predict the spatiotemporal variation of ionic profiles, surface and zeta potentials, dissolution and precipitation of minerals, total disjoining pressure, and wettability index in addition to oil recovery for the injection of brines. The validity of the coupled model results was tested against PHREEQC in a single-phase flow without the presence of oil. Moreover, the modelling results were compared with the published experimental data for a single-phase flow in carbonate cores. A very good agreement between experimental data and modelling results was obtained. Furthermore, the coupled model was applied to predict ionic concentration, pH profile, and oil recovery in both carbonate and sandstone cores and verified with experimental data. The modelling results reproduce well the experimental data, suggesting that model captures the geochemical and interface reactions. Finally, the coupled model can be used to optimize brine composition for improved oil recovery in carbonate and sandstone reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Improvements on Modelling Wettability Alteration by Engineered Water Injection: Geochemical Pore-Scale Approach
Bordeaux Rego, Fabio (The University of Texas at Austin) | Mehrabi, Mehran (The University of Texas at Austin) | Sanaei, Alireza (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract Several laboratory experiments demonstrated that different water compositions cause rocks to change from oil- to water-wet state. Although it is a consensus that wettability alteration is the main recovery mechanism, modeling the underlying mechanism is still a major challenge. Our main goal is to improve and validate a physically based model to predict contact angles from zeta-potential measurements. We propose a new mass-action formulation for surface complexation model (SCM) that includes the energy interaction effect between two close surfaces (PS). Currently, most SCMs consider rock and oil as isolated surfaces (IS). Thus, we hypothesize that, as rock and oil surface approach each other, PS model produce a better description of electrostatic distribution. Additionally, we develop a method of determining SCM equilibrium constants to fit several zeta-potential measurements for different ion concentrations (Na, Ca, Mg, SO4 and H). Finally, we estimate contact angles using disjoining pressure calculations and compare them with ones reported in the literature. From a SCM set of reactions available in the literature, we validate the developed IS model against PHREEQC (a reference simulator for geochemical reactions). For the PS case, the system of equationsโ solution is very close to IS approach when the interaction between surfaces are negligible (wide spacing between surfaces). Regarding zeta-potential prediction for calcite-brine system, we argue that Na might not be an indifferent ion as suggested previously. Our simulation results indicate that, besides the renowned potential-determining ions, sodium adsorption on calcite can play an important role in electrostatic interactions, switching surface charge polarity. Thus, we only achieve a successful fit of zeta-potential measurements when Na is considered in the SCM reactions. Finally, contact angle estimation using the PS model and disjoining pressure theory provide good predictions of seven different cases reported in the literature. We validate our method on a total of 66 and 163 contact angle and zeta-potential measurements, respectively. The present work is a novel approach to represent how electrostatic interactions among rock, brine and oil modify the rock surface charge and the rock wetting state.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geology > Mineral > Carbonate Mineral > Calcite (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.40)
- North America > United States > Arkansas > Magazine Field (0.89)
- Europe > United Kingdom > England > London Basin (0.89)
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Rohilla, Neeraj (Dow Chemical International Pvt. Ltd.) | Katiyar, Amit (The Dow Chemical Company) | Rozowski, Pete M. (The Dow Chemical Company) | Gentilucci, Adrianno (The Dow Chemical Company) | Patil, Pramod D. (Rock Oil Consulting Group) | Pal, Mayur (North Oil Company) | Saxena, Prabhat (North Oil Company)
Abstract Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains. An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 ยฐC and in some cases up to 120 ยฐC) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases). The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
Artificial Diagenesis of Carbonates: Temperature Dependent Inorganic and Organic Modifications in Reservoir Mimetic Fluids
Rao, Ashit (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Kumar, Saravana (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Annink, Carla (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Le-Anh, Duy (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | B. Alotaibi, Mohammed (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco) | C. Ayirala, Subhash (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco) | Siretanu, Igor (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Duits, Michel (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | Mugele, Frieder (Physics of Complex Fluids Group and MESA+ Institute, Faculty of Science and Technology, University of Twente) | A. Yousef, Ali (The Exploration and Petroleum Engineering Center - Advanced Research Center, Saudi Aramco)
Abstract Within reservoirs, spatial variations related to mineralogy and fluid chemistry determine the success of improved oil recovery (IOR) techniques. However, the composition and structure of mineral-adsorbent-fluid interfaces, which fundamentally determine the initial and IOR-altered wettability of reservoir rocks as well as the displacement of crude oil (CRO), are unclear. Replicating the diagenetic alterations of carbonates, this study addresses the temperature dependence of the inorganic and organic modifications of calcite by reservoir pertinent fluids as well as its consequences on mineral wettability and reactivity. We utilize a suite of characterization methods, such as confocal Raman, scanning electron and atomic force microscopy as well as Fourier-transform infrared spectroscopy, to investigate the modifications of carbonates on aging in formation water (FW), CRO-equilibrated FW and FW-equilibrated CRO. The microscopic modifications of carbonates present positive correlations with aging temperature and also are varied, encompassing topographical alterations, cation substitution of lattice Ca ions by Mg ions and the deposition of particles enriched with polyaromatic hydrocarbons (PAHs) as organic adlayers. Aging in the formation waters produce substantial reconstruction of calcite surfaces, with the formation of Mg-calcite layers at elevated temperatures. Subsequent aging in brine-equilibrated CRO produces an organic coating on calcite surfaces, which is composed of PAH-enriched particles. The organic adlayers, deposited at high temperature, produce a transition in the macroscopic contact angles towards a more โoil wetโ tendency. In addition, the organic adlayer presents limited permeability and serves as a diffusion barrier to the reactivity of the bound mineral, as evident from substantially reduced rates of calcite dissolution. The multilayer deposition of organic particles is attributed to an interplay between bulk and surface reactions for interfacially active constituents of CRO. With the enrichment of PAHs even observed for mineral grains within reservoir rocks, the permeability and stability of organic adlayers emerge as key factors determining the wettability of carbonates as well as the diffusion behavior of ionic and molecular species at mineral-fluid interfaces. Results of this study are relevant to multiple aspects of reservoir development and maintenance, encompassing laboratory scale wettability and core flooding experiments, in silico models as well as the advancement of IOR strategies. The observed nano- and microscopic surface alterations of carbonates within reservoir mimetic environments facilitate our understanding of the physicochemical relations between mineralogy and fluid chemistry as well as elucidate the organization of mineral-adsorbent-fluid interfaces within reservoirs.
- Asia > Middle East > Saudi Arabia (0.68)
- North America > United States (0.67)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- (4 more...)
Pilot Test of Surfactant-Polymer Flood with Mixtures of Anionic-Cationic Surfactants for High Temperature Low Permeability Sandstone Reservoir
Li, Yingcheng (Sinopec Shanghai Research Institute of Petrochemical Technology) | Zhang, Weidong (Sinopec Shanghai Research Institute of Petrochemical Technology) | Shen, Zhiqin (Sinopec Shanghai Research Institute of Petrochemical Technology) | Jin, Jun (Sinopec Shanghai Research Institute of Petrochemical Technology) | Su, Zhiqing (Sinopec Shanghai Research Institute of Petrochemical Technology) | Yao, Feng (Sinopec Jiangsu Oil Field Company) | Yu, Xiaoling (Sinopec Jiangsu Oil Field Company) | Bao, Xinning (Sinopec Shanghai Research Institute of Petrochemical Technology) | He, Xiujuan (Sinopec Shanghai Research Institute of Petrochemical Technology) | Wu, Xinyue (Sinopec Shanghai Research Institute of Petrochemical Technology) | Zhang, Hui (Sinopec Shanghai Research Institute of Petrochemical Technology) | Sha, Ou (Sinopec Shanghai Research Institute of Petrochemical Technology)
Abstract The first pilot test of surfactant-polymer (SP) flood in the world with mixtures of anionic-cationic surfactants (Sa/c) was carried out for a high temperature low permeability sandstone reservoir with high content of clay to demonstrate the potential of this novel technique to improve oil recovery. Low critical micelle concentrations (CMC) of 2.78ร10 mol/L, ultralow interfacial tension (IFT) of 10 to 10 mN/m when surfactant concentrations were above 0.025 wt%, and lower phase microemulsion with high oil solubilization of 22, as well as 55.45 % oil washing rate were obtained by using Sa/c. The adsorption inhibitor (AI) was adopted to reduce the adsorption because of the high clay contained in the natural core. Dynamic adsorption was about 0.30 mg/g with addition of AI, as well as IFT kept almost unchanged before and after adsorption. In order to reduce the injection pressure and improve the mobility ratio in the low permeability reservoir, low molecular weight polyacrylamide was adopted. The viscosity of polymer and SP were 2.96 mPaยทs and 4.05 mPaยทs, respectively. Core flooding results showed more than 16 % original-oil-in-place (OOIP) crude oil was recovered by SP over water flood. Since August 2012, the pilot test of SP containing Sa/c was carried out in a Sinopec reservoir with temperature of 83 ยฐC, salinity of 15,000 mg/L, permeability of 41.5 mD, clay of 12 %. Totally 0.40 PV chemicals, including 0.1 PV polymer pre-slug, 0.25 PV SP main slug and 0.05 PV polymer drive, were injected from August 2012 to December 2017 with an injection rate of 0.08 PV/a. After that water drive was conducted. Maximal water cut decreased from 82.2 % to 62.1 %, and the peak daily oil production increased from 12.2 t to 32.3 t. The oil recovery was increased by 8.0 % OOIP by the end of December 2018.
- Asia > China (0.90)
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (0.90)
Polymer Chemical Structure and its Impact on EOR Performance
Beteta, Alan (Heriot-Watt University) | Nurmi, Leena (Kemira Oyj) | Rosati, Louis (Kemira Chemicals Inc.) | Hanski, Sirkku (Kemira Oyj) | McIver, Katherine (Heriot-Watt University) | Sorbie, Kenneth (Heriot-Watt University) | Toivonen, Susanna (Kemira Oyj)
Abstract Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period. Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments. The majority of the work was carried out in seawater at temperature, T = 58ยฐC. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased. The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.
- North America > United States > Oklahoma (0.29)
- North America > United States > West Virginia (0.24)
- North America > United States > Pennsylvania (0.24)
- (2 more...)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Mineral > Silicate (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
Abstract This paper describes the interpretation of a successful inter-well field trial of a novel reservoir-triggered polymer technology, making use of pressure transient analysis and numerical simulation. The polymer has been engineered to improve sweep in oil-bearing formations whilst reducing the impact of two of the key operational and economic challenges facing polymer enhanced oil recovery (EOR). The polymer employs a chemical strategy to render it resistant to shear during injection and in the high flux region at the sand face. In addition, the injection solution has a viscosity similar to that of water until triggered in the reservoir, which sustains injectivity. We demonstrate the use of laboratory kinetics, rheology data, high-resolution surveillance of the injector, and comprehensive analysis of produced fluids to constrain the simulation of the in-situ viscosification of this polymer. Numerical models using commercial and in-house R&D codes were calibrated to tracer effluent data, pressure fall-off tests, and injection pressures, to interpret the size and mobility of the polymer bank and its response to water injection. The field trial has qualified the polymer to be considered for deployment. A comprehensive surveillance programme and downhole sampling was used to successfully demonstrate that the polymer was protected from shear degradation upon injection and propagation, and it viscosified under flow at the designed location in the reservoir. Kinetic and rheology data from laboratory testing, combined with reservoir-scale simulations and field trial surveillance, enabled the reaction and adsorption characteristics of the polymer to be estimated. Simulations of the injection pressure demonstrate that this polymer has significantly better injectivity under matrix conditions than would be obtained with a conventional polymer of an equivalent deep-reservoir viscosity.
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Block RJ/ON-90/1 > Bhagyam Field (0.99)
General Overview This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode. Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model. The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.