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Collaborating Authors
Results
Shallow-water carbonate structures are characterized by different shapes, sizes and identifying features, which depend, among other factors, on the age of deposition and on the carbonate factory associated with a specific geologic period. These variations have a significant impact on the imaging of these structures in reflection seismic data. This study aims at providing an overall, albeit incomplete, picture of how the seismic expression of shallow-water carbonate structures has evolved through deep time. 297 shallow-water carbonate systems of different ages, spanning from Precambrian to present, with a worldwide distribution of 159 sedimentary basins, have been studied. For each epoch, representative seismic examples of shallow-water carbonate structures were described through the assessment of a selection of discriminating seismic criteria, or parameters. The thinnest structures, commonly represented by ramp systems, usually occurred after mass extinction events, and are mainly recognizable in seismic data through prograding clinoform reflectors. The main diagnostic seismic features of most of the thickest structures, which were found to be Precambrian, Late Devonian, Middle-Late Triassic, Middle-Late Jurassic, some Early Cretaceous pre-salt systems, #8220;middle#8221; and Late Cretaceous, Middle-Late Miocene and Plio-Pleistocene, are steep slopes, and reefal facies. Slope-basinal, resedimented seismic facies, were mostly observed in thick, steep-slope platforms, and they are more common, except for megabreccias, in post-Triassic structures. Seismic-scale, early karst-related dissolution features were mostly observed in icehouse, platform deposits. Pinnacle structures and the thickest margin rims are concentrated in a few epochs, such as Middle-Late Silurian, Middle-Late Devonian, earliest Permian, Late Triassic, Late Jurassic, Late Paleocene, Middle-Upper Miocene, and Plio-Pleistocene, which are all characterized by high-efficiency reef builders.
- South America (1.00)
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- (5 more...)
- Phanerozoic > Paleozoic > Devonian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (5 more...)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- (3 more...)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.67)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.45)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.45)
- South America > Venezuela > Caribbean Sea > Gulf of Venezuela > Gulf of Venezuela Basin > Cardon IV Block > Perla Field (0.99)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- (82 more...)
Feasibility of Foam-Enhanced Water-Gas Flooding for a Low-Permeability High-Fractured Carbonate Reservoir. Screening of Foaming Agent and Flooding Simulation
Derevyanko, V. K. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Bolotov, A. V. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Minkhanov, I. F. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Varfolomeev, M. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Usmanov, S. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Saifullin, E. R. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Egorov, A. N. (CJSC, Aloil, Bavly, Russian Federation) | Sudakov, V. A. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Zhanbossynova, S (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation) | Sagirov, R. N. (Department of reservoir engineering, Kazan Federal University, Kazan, Russian Federation)
Abstract The carbonate reservoirs of the Alekseevskoye field (Russia, Republic of Tatarstan) are complicated by high heterogeneity and the presence of fractures, which make development difficult due to early water or gas breakthrough depending on the injected agent, as well as low of the productive horizon. To increase sweep efficiency and introduce fractured reservoirs into development, it is necessary to use gas enhanced oil recovery (EOR) technologies. To find the optimal technology in terms of technological complexity and efficiency, three technologies were compared: Water Injection (WI), Water-Alternating Gas (WAG), and Foam Assisted Water-Alternating Gas (FAWAG). Series of core-flooding tests were implemented under reservoir conditions on carbonate cores, and cores with artificial fractures, saturated with original reservoir fluids. For FAWAG method compatible with high-mineralization water surfactant was chosen. Total recovery factor for each test was calculated. It was equal to 33%, 76% and 53% respectively for WI, WAG and SWAG, on the original core models. Therefore, WAG and SWAG were chosen as most effective techniques to improve oil recovery for in comparison with CWI. In artificially fractured cores, the WAG method recovery rate was 40%; subsequent injection of a foaming active substance mixed with FAWAG formation water proved effective, increasing the oil recovery rate to 47% due to partial blockage of the fracture.
- Geology > Rock Type > Sedimentary Rock (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.37)
- Europe > Russia > Volga Federal District > Bashkortostan > Alekseevskoye Field (0.99)
- Europe > Russia > Volga Federal District > Tatarstan > Volga Urals Basin > Romashkinskoye Field (0.94)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Fyodorovskoye Field (0.94)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Samotlorskoye Field (0.94)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger (Corresponding author)) | Herlofsen, Sander Sunde (Department of Energy Resources, University of Stavanger) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger) | Minde, Mona Wetrhus (Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger)
Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130°C in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100–150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 (in pure and less pure chalk, at 130°C) show injection rate-dependent results (Andersen et al. 2022) and smoother alterations [Mg precipitation was seen from inlet to outlet (Zimmerman et al. 2015)], indicating that Mg-mineral reactions at same conditions have a longer time scale. The limited distance mineral alteration has occurred, suggesting that adsorption processes, happening in parallel, can explain previous observations (Korsnes and Madland 2017) of Ba and Sr injection strengthening chalk. Flushing out formation water with these ions during injection may be a new water-weakening mechanism.
- North America > United States (1.00)
- Europe > Norway > North Sea (0.70)
- Europe > Denmark > North Sea (0.70)
- (2 more...)
- Geology > Geological Subdiscipline > Geochemistry (0.86)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.98)
- (10 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
New Insights into Hybrid Low-Salinity Polymer Flooding through a Coupled Geochemical-Based Modeling Approach
Hassan, Anas M. (Petroleum Engineering Department, Khalifa University of Science and Technology (Corresponding author)) | Al-Shalabi, Emad W. (Petroleum Engineering Department, Khalifa University of Science and Technology) | Alameri, Waleed (Petroleum Engineering Department, Khalifa University of Science and Technology) | Kamal, Muhammad Shahzad (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals) | Patil, Shirish (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals) | Hussain, Syed Muhammad Shakil (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals)
Summary Low-salinity polymer (LSP) flooding is a synergic emergent enhanced oil recovery (EOR) technique. Previous laboratory experiments showed noticeable improvements in displacement efficiency, polymer rheology, injectivity, and viscoelasticity. Nevertheless, when it comes to modeling LSP flooding, it is still challenging to develop a mechanistic predictive model that captures polymer-brine-rock (PBR) interactions. Therefore, this study uses a coupled MATLAB reservoir simulation toolbox (MRST)-IPhreeqc simulator to investigate the effect of water chemistry on PBR interactions during LSP flooding through varying overall salinity and the concentrations of divalent and monovalent ions. For describing the related geochemistry, the presence of polymer in the aqueous phase was considered by introducing novel solution species (Poly) to the Phreeqc database. The developed model’s parameters were validated and history matched with experimental data reported in the literature. Moreover, different injection schemes were analyzed, including low-salinity (LS) water, LSP injection (1 × LSP), and 5-times spiked LSP injection (5 × LSP) with their related effects on polymer viscosity. Results showed that polymer viscosity during LSP flooding is affected directly by Ca and Mg and indirectly by SO4 owing to PBR interactions on a dolomite rock-forming mineral. Monovalent ions (viz. Na and K) have minor effects on polymer viscosity. Ca and Mg ions discharged from dolomite dissolution create polymer complexes (acrylic acid, C3H4O2) to reduce polymer viscosity significantly. The increased SO4 concentration in the injected LSP solution affects the interactions between the polymer and positively charged aqueous species, leading to minimized polymer viscosity loss. For LSP flood derisking measures, the cation’s effect was related to the charge ratio (CR). Thus, it is key to obtain an optimal CR where viscosity loss is minimal. This paper is among the few to detail the mechanistic geochemical modeling of the LSP flooding technique. The validated MRST-IPhreeqc simulator evaluates the previously overlooked effects of water chemistry on polymer viscosity during the LSP process. Using this coupled simulator, several other geochemical reactions and parameters can be assessed, including rock and injected-water compositions, injection schemes, and other polymer characteristics.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.28)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.46)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract This paper uses reactive transport modelling to analyse the impact of variations in the water and gas injection flow rates from a geochemical perspective on the scaling potential of carbonate reservoirs under CO2-WAG injection. A sensitivity analysis of the calcite saturation index is performed for different water and gas injection flow rates. Geochemical properties of the injection fronts are analysed through the reservoir. The study is carried out using a 1D model of water-alternating-gas injection, assuming a light oil with 1.2% CO2 concentration, desulphated seawater injection and calcite as the rock substrate. The reactive transport modelling is performed using a commercial compositional reservoir simulator with the WOLERY database. Pressure, temperature, formation water (FW) and injected water (IW) compositions are based on published data. The scale potential is measured by calculating the saturation index and water production rates. Results show that calcite dissolution occurs continuously in the block closest to the injection well, and equilibrium is not reached in this region during water injection, but it is reached during CO2 injection. The extent of the reaction decreases from the injector to the producer well because the fluid becomes more saturated with CO2 as it flows through the reservoir. The reaction also decreases as the water and gas injection flow rates decrease, mainly due to the reduced volume throughput. The reactions during the water injection part of the cycle occur further away from the waterflood front as the water injection rate declines, and the reactions during the CO2 injection part of the cycle occur further away from the gas flood front as the CO2 injection rate declines. The system takes longer to reach equilibrium at lower flow rates, and so the water composition varies for longer. In the highest water flow rate model, it takes a very short time to reach equilibrium after the water breakthrough in the producer well. In the lowest water flow rate model, it takes more than five times as long. This work indicates the previously unreported finding that the water and gas injection flow rates may affect the geochemical equilibrium in the reservoir, specifically demonstrating that the reactions during the non-equilibrium stage may occur further away from the water and gas flood fronts, depending on the water and gas flow rates.
- South America > Brazil (0.93)
- North America > United States (0.68)
- Asia > Middle East > UAE (0.28)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.72)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Xanthan gum is a non-damaging viscosifier and fluid loss control agent commonly included in reservoir drill-in, completion and workover fluid formulations. One of the key benefits offered by xanthan in these applications is that it is not an especially robust polysaccharide and under downhole conditions it will eventually self-break through molecular collapse and/or depolymerisation reactions. With only a temporary presence in the filter cake and formation invaded by filtrate, xanthan can never pose a serious or permanent threat to oil and gas production but clearly it would be good to be able to control and manage the rate at which it degrades. The rate at which xanthan degrades downhole is a function of the temperature, the presence of oxidants and the ionic environment. The purpose of the experimental program described in this paper was to measure the rate of natural self-breaking of xanthan under different temperature conditions when dissolved in various water and brine systems containing formate and halide ions. A simulated North Sea formation water and a low-sulfate seawater were included in the test program. The samples were dynamically and statically aged for periods up to 12 months, and their degree of natural self-breaking was tracked by viscosity measurements. Several other classes of polysaccharide were tested in the program, either alone or in combination with xanthan. The tests confirmed that at temperatures in the range 124–170°C (255–338°F) xanthan and the other polysaccharides all degraded over time and the resulting "broken" fluids had low viscosities. It was found that the self-breaking rate varied hugely with brine type and concentration. Concentrated formate brines, rich in antioxidants and high molar concentrations of water-structure making ions, allowed steady rates of polymer breaking over weeks and months while the same polysaccharides dissolved in brines containing significant amounts of sodium bromide degraded very quickly. These results suggested that clear brine systems of any density within the compatibility limits of the blended components could be engineered to self-break within a set period of time by blending formate and sodium bromide brines in appropriate ratios. Degradation tests at 124°C (255°F) of xanthan in a typical North Sea formation water and a low-sulphate seawater, showed very rapid self-degradation, resulting in hardly any remaining viscosity after only 4 days of ageing. It seems likely that xanthan gum and other polysaccharides that are stabilized in formate brines, will lose their viscosity rapidly if contacted by formation water or well injection water. In fact, an overflush of the filter cake and near wellbore formation with any low salinity fluid would make an effective breaker system for xanthan in the applicable temperature range. The learning points from this study offer a solution to the problem of filtrate retention as an artifact in laboratory coreflood tests of viscosified brine-based fluids. Not exposing the fluid to the reservoir temperature for a realistic time period between invasion and drawdown may leave some viscosified brine in the pore space and in the filtercake, that is hard to remove during the standard drawdown time. Such retained filtrate has an adverse effect on the core's water saturation and thereby on the effective permeability to hydrocarbons.
- North America > United States > Texas (0.68)
- Europe > Norway > North Sea > Northern North Sea (0.46)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Rogn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/9 > Draugen Field > Garn Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6407/12 > Draugen Field > Rogn Formation (0.99)
- (30 more...)
ABSTRACT Many mechanisms have been proposed in the literature to explain wettability alteration at low salinity waterflooding. However, no consensus has been reached on which one is the key mechanism in low-salinity enhanced oil recovery. Moreover, these mechanisms are poorly understood. Parameters such as salinity, electrolyte type, oil components and presence of clay minerals are often associated to the degree to which the injection of low-salinity water increases oil production. Therefore, an investigation of the geochemistry of the clay-fluid interface is crucial to understand the role of petrophysical properties such as wettability on oil production. We use Molecular Dynamics (MD) to (i) investigate at an atomistic scale, wettability alteration mechanisms such as EDL expansion and multicomponent ion exchange, (ii) quantify the impacts of different types oil components, electrolytes and its mixture at varying ionic strengths on interfacial properties, and (iii) investigate wettability alteration by means of water adsorption quantification. In this work, we investigate the brine/clay and oil/brine/clay interfacial interactions. Clay is represented by illite and brine is composed of water molecules and different electrolyte types such as NaCl, CaCl2, and their mixtures at varied concentrations. The oil components investigated in this work include, decane, decanoic acid and sodium decanoate. Initially, we set up systems composed of different ion composition and salinity to investigate the effect of these parameters on EDL structure and water adsorption. Then, we create systems composed of mixed electrolyte and different organic components to verify the impacts of these molecules on the oil/brine/clay interface. Finally, we increase the NaCl concentration in the system containing sodium decanoate to investigate the role of Na in wettability alteration. MD simulations were performed at 330 K and particle density profiles of water, hydrocarbon and ions inside the illite nanopores are computed. From the density profile of water, organic molecules and ions, the structure of the fluid was analyzed. We vary the ion composition and salt concentration of our systems and we found that those variations do not result in changes in the adsorption planes of cations. For the same systems, we also compute the number of water molecules per unit cell in each hydration layer. We observe that the change in the thickness of these hydration layers is also very small. Our results reveal that all organic components simulated, present very similar density profiles when simulated at same electrolyte concentration. However, we note that calcium preferentially forms bridges with sodium decanoate molecules compared to other organic components. Increasing the NaCl concentration in the system containing sodium decanoate, we observe a change in the organic compound adsorption behavior, suggesting that the system wetting properties could be slightly altering toward oil wet. Despite being widely known as an efficient method for achieving enhanced oil recovery, the underpinning mechanism for wettability alteration at low salinity waterflooding is still not fully understood. The outcomes of this work improve our understanding of the most effective mechanism in wettability alteration.
- Asia (0.68)
- North America > United States > Texas (0.31)
Visualization of Surfactant Flooding in Tight Reservoir Using Microfluidics
Scerbacova, Alexandra (Skolkovo Institute of Science and Technology, LABADVANCE) | Pereponov, Dmitrii (Skolkovo Institute of Science and Technology, LABADVANCE) | Tarkhov, Michael (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Kazaku, Vitaly (Skolkovo Institute of Science and Technology) | Rykov, Alexander (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Filippov, Ivan (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Zenova, Elena (Institute of Nanotechnology of Microelectronics of the Russian Academy of Sciences) | Krutko, Vladislav (Gazpromneft STC LLC) | Cheremisin, Alexey (Skolkovo Institute of Science and Technology, LABADVANCE) | Shilov, Evgeny (Skolkovo Institute of Science and Technology, LABADVANCE)
Abstract Surfactant flooding is among the most studied and widespread EOR technologies that is being introduced into tight and low-permeable reservoirs to mobilize trapped oil. Typically, the selection of formulations for chemical flooding is associated with numerous challenges and constraints such as time-consuming core flooding tests, the high cost of the tests with modern saturation control methods, and a limited amount of core samples. To overcome these issues, microfluidic technology was applied to optimize the screening of surfactant compositions for flooding. The workflow of this project consisted of five main steps: (1) fabrication of microfluidic chips, (2) surfactant screening in bulk, (3) surfactant flooding in microfluidic chips, (4) image analysis and data interpretation. Silicon-glass microfluidic chips, which are 2D representatives of the reservoir porous media, were used in the experiments. The porous structure geometry was developed based on CT images of core samples from a particular field with low permeability. For the selected surfactants, interfacial behavior on the boundary with n-decane was studied and correlated with hydrocarbon recovery ability. The results obtained revealed that the IFT patterns have a significant influence on displacement efficiency. Thus, the surfactant compositions with a lower initial IFT than the equilibrium value achieved higher recovery factors.
- North America > United States (0.47)
- Europe > Austria (0.28)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates
Andersen, Pål Østebø (Department of Energy Resources, University of Stavanger, Norway) | Herlofsen, Sander Sunde (Department of Energy Resources, University of Stavanger, Norway) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger, Stavanger, Norway) | Minde, Mona Wetrhus (Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger, Stavanger, Norway)
Abstract Chalk reservoirs in the North Sea of Norway contain significant amounts remaining oil and gas, and are potential candidates for enhanced recovery by modifying the injected brine composition. This work investigates how brines with divalent cations Ba, Sr and Mg interact when injected into chalk (CaCO3). Ba and Sr are often associated with mineral precipitation and occur in formation water while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130 °C in triaxial cells with four brines containing 0.12 mol/L divalent cations: either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100 to 150 pore volumes. The injection rate was varied between 0.5 and 8 pore volumes per day. Produced brine was analyzed continuously and compared with the injected brine composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of Scanning Electron Microscopy (SEM), matrix density, specific surface area and X-Ray diffraction. In all experiments, the produced divalent cation concentration was reduced compared to the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 50%, while when flooding 0.12 mol/L Ba, 10% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was little sensitivity in steady state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few cm from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, specific surface area, micro scale structure, porosity and composition (XRD and SEM-EDS). The material near the inlet was clearly altered. Images, XRD, SEM-EDS and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2- and SrCl2-flooding, respectively. The simulations also predicted equal exchange of cations to occur. The matrix densities, porosities and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba-, Sr-, Mg-brines and their mixtures can be highly reactive in chalk without clogging the core after tens of pore volumes. This is because precipitation of minerals bearing these ions associates with simultaneous dissolution of calcite. The Ca-, Ba-, Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 show rate dependent results and smoother alterations, indicating that Mg-mineral reactions at same conditions have longer time scale.
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- Geology > Geological Subdiscipline > Geochemistry (0.49)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.98)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract Cation exchange occurs when water with a different salinity as the connate brine is injected in a reservoir. During polymer flooding operations, the potential release of divalent cations by the rock can have a detrimental impact on the in-situ viscosity in the polymer bank. The objective of this work was to assess for the risk related to cations exchange in an Argentinian oilfield and to provide guidelines for the injection water design. Reservoir rock samples were first submitted to mineralogical analysis involving scanning-electron microscopy (SEM), X-Ray Diffraction (XRD) and determination of their Cation Exchange Capacities (CEC). Coreflood tests were then performed where the effluents were analyzed for their cations composition. In these experiments, two main scenarios for the composition of the low-salinity injection water (with or without softening) were investigated and the transport properties of the polymer were determined. As a more exploratory approach, polymer was also injected in a 12-meter-long slim tube filled with crushed reservoir rock, to assess if it could be exposed to released cations. The results showed that all reservoir rocks investigated had high CEC, which was consistent with their high clay contents, and that significant cations exchanges took place during low salinity water injection, although no formation damage occurred, showing the stability of the clays. During injection of the softened water, evidences of significant divalent (and monovalent) cations release from the rock were found. During injection of the unsoftened water, a marked and long-term adsorption of the injected calcium cations was observed, corresponding to a depletion in calcium of the injected water. This suggests that, quite counter-intuitively, using unsoftened water as polymer make up water could be interesting in view of economics because the cations exchanges could entail an increase of the in-situ viscosity. The coreflood test results also showed that the presence of polymer in the injected water had no impact on the cations exchanges mechanisms. The partial results from the slim tube injection test suggested, however, that the retardation of the polymer bank caused by polymer adsorption was sufficient to avoid for its viscosity to be affected by the changes in cations distribution. This study illustrates the importance of cation exchange mechanisms and their potential impact for polymer flooding. It also shows that these effects can be investigated in a representative manner at the lab and that practical guidelines for the composition of the polymer injection water can be deduced from the experiments, provided a risk for in-situ viscosity reduction is identified.
- North America > United States (0.93)
- Asia > Middle East > Oman (0.28)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Geological Subdiscipline (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Asia > Middle East > Oman > Dhofar Governorate > South Oman Salt Basin > Marmul Field > Al-Qalata Formation (0.94)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.94)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.94)
- (2 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)