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Abstract CO2 injection into depleted gas fields causes long-term cooling of the reservoir. Therefore, even if injection pressure stays below the fracture initiation pressure, the cooled volume still creates an extensive stress disturbance that can induce propagation of large fractures over time. The enhanced injectivity after the onset of this thermal fracturing might jeopardize injection operations due to the risk of hydrate plugging in the injection well caused by the combination of low pressure and low temperature, and large fractures may also increase the risk of loss of containment. Modeling the fracture evolution provides an estimate of these effects and their timing. Coupled simulation of CO2 injection provides the thermal fracture dimensions for a given uncertainty in the reservoir parameters. Simplified stress modelling is applied in the thermal fracture reservoir simulation, but a full 3D geomechanical model that was developed for fault slip analysis provides accurate estimates of the stress state after depletion and the subsequent evolution of the stresses during CO2 injection. For computation efficiency, sector models were used with locally refined grids to accommodate fractures in the reservoir simulation model. It was verified that the fracture models match the full-field simulation under matrix flow conditions. The fracture simulations were developed in close relation with flow assurance modeling to determine the operational windows that avoid hydrate formation while maintaining the required injection target. Thermal fracture propagation by CO2 injection into the depleted Dutch offshore gas field has been simulated by using coupled simulation approach. The model has been developed with geomechanical properties and stresses obtained from various sources in neighboring fields. It was found that stress, thermal expansion coefficient, modulus and permeability distribution are the principal parameters that determine fracture growth. The forecast of thermal fracture propagation yielded in some cases very long fractures reaching compartment boundaries. Injectivity was enhanced by up to a factor of 4, which is significant for flow assurance. The coupled modeling of thermal fracturing provides mitigating measures in case the temperature and pressure drop into the hydrate formation window.
- Europe > Netherlands > North Sea > Dutch Sector > Q10a License > Volpriehausen Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > L09 License > Hardegsen Formation (0.99)
- Europe > Netherlands > North Sea > Dutch Sector > P18a License > P18-4 Field > Main Buntsandstein Formation (0.94)
- (2 more...)
Effect of Temperature and Particle Exposure on Hydroxyapatite Nanoparticles on Wettability Alteration of Oil-Wet Sandstone
Ngouangna, E. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia.) | Jaafar, M. Z. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia./ Institute for Oil and Gas, IFOG, Universiti Teknologi Malaysia, Malaysia.) | Anam, M. N. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia.) | Agi, A. (Faculty of Chemical and Process Engineering Technology, College of Engineering Technology, Universiti Malaysia Pahang, Gambang, Pahang, Malaysia./ Centre for Research in Advanced Fluid and Processes, Fluid Centre, Universiti Malaysia Pahang, Gambang, Pahang, Malaysia.) | Gbonhinbor, J. (Department of Petroleum Engineering, Faculty of Engineering, Niger Delta University, Wilberforce Island, Bayelsa State, Nigeria.) | Ridzuan, N. (Faculty of Chemical and Process Engineering Technology, College of Engineering Technology, Universiti Malaysia Pahang, Gambang, Pahang, Malaysia.) | Mahat, S. Q. A. (Faculty of Chemical and Process Engineering Technology, College of Engineering Technology, Universiti Malaysia Pahang, Gambang, Pahang, Malaysia.) | Yakassai, F. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia./ Department of Chemical and Petroleum Engineering, Faculty of Engineering, Bayero University, Kano, Kano State, Nigeria.) | Oseh, J. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia.) | Al_Ani, M. (Department of Petroleum Engineering, School of Chemical and Energy Engineering, Faculty of Engineering, Universiti Teknologi Malaysia, Malaysia.)
Abstract Nanofluid treatment is being developed to improve oil recovery and reduce residual oil entrapment in sandstone reservoirs. Nanoparticles for enhanced oil recovery (EOR) at ambient conditions have shown good potential in recent research. The efficiency on EOR has been found to be significantly influenced by nanofluid composition, exposure and time. However, there is a serious lack of knowledge regarding the influence of temperature on nanofluid performance. The effects of temperature, exposure, time, and particle size of hydroxyapatite nanoparticles (HAP) on the wettability alteration of an oil-wet sandstone were thoroughly investigated, and the stability of the nanofluids was equally examined. At higher temperatures, it was discovered that nanofluid treatment is more effective, with nanoparticle size having little or no influence. The sandstone surface mechanically absorbed most nanoparticles in an irreversible manner. The HAP nanofluid was still effective at high temperature reservoir condition and is herein proposed.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.72)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.46)
The objective of this paper is to present a fundamentals-based, three-phase flow model consistent with observation that avoids the pitfalls of conventional models. Though the use of the Stone II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears counterintuitively to limit the flow of oil when water is present near its irreducible saturation. The novelty of the work presented in the complete paper is in the development of a model based on fundamentals of flow in fine channels that better explains observed results in the context of flow in porous media. Residual oil saturation (So) from retrieved cores from oil-drained chambers of steam-assisted gravity drainage (SAGD) reservoirs invariably shows values as low as 1 or 2%, whereas reservoir simulations using Stone II-based relative permeabilities (an industrywide favorite) predict significantly higher numbers (14–18%). In previous work, the author and others, in an attempt to remedy the situation, extended the oil-phase relative permeability in the presence of the water phase (krow) and oil-phase relative permeability in the presence of the gas phase (krog) curves all the way to water and gas saturation values less than unity; however, they discovered that, in the presence of water saturation (Sw) near the irreducible water saturation (Swi), the use of the Stone II formula for oil relative permeability still resulted in high residual So.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Geochemical Impact on Rock Wettability in Injection of High-Concentration Formate Solution for Enhanced Geologic Carbon Storage and Oil Recovery
Oyenowo, Oluwafemi Precious (The University of Texas at Austin) | Wang, Hao (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Mirzaei-Paiaman, Abouzar (The University of Texas at Austin) | Sheng, Kai (The University of Texas at Austin)
Abstract Aqueous formate (FM) solution has been studied for geologic carbon storage, in which highly concentrated FM solution as carbon-bearing water is injected into the target formation. The literature shows that aqueous FM solution may cause geochemical interactions with carbonate rocks, but no experimental data exist for high-concentration FM solutions. This paper presents a new set of data focused on core-scale wettability alteration of carbonate porous media with varying FM concentration (up to 30 wt%) in NaCl brine. Experimental data from Amott wettability tests and core floods with limestone cores were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of calcite dissolution increased with increasing FM concentration in the NaCl brine even with the initially neutral pH. For example, the calcium concentration in the 30-wt% FM case was 15.9 times greater than that in the NaCl brine case with the initial pH of 7.0. Furthermore, reducing the initial solution pH from 7.0 to 6.1 for the 30-wt% FM solution caused the calcium ion concentration to increase by a factor of 3.2. Geochemical modeling indicated that the increased calcite dissolution could be caused by the formation of calcium FM complexes that reduced the activity coefficient of the calcium ion and therefore, drove the calcite dissolution. The 30-wt% FM solution with the initial pH of 6.1 yielded 4.7 times greater oil recovery than the NaCl brine case in the spontaneous imbibition. The resulting Amott index clearly indicated the wettability alteration to a water-wet state by the FM solution. The 30-wt% FM solution with the initial pH of 7.0 yielded only 30% greater oil recovery than the brine case in the spontaneous imbibition; however, it reached nearly the same amount of total oil recovery (spontaneous and forced) with the 30-wt% FM solution with the initial pH of 6.1. This is likely because the in-situ solution pH could be sufficiently lower than the calcite isoelectric point consistently during the forced imbibition, unlike under the static conditions during the spontaneous imbibition. Increasing the FM concentration in the injection brine (pH 7.0) delayed the water breakthrough in core floods. Numerical history matching of the core flooding data showed that increasing the FM concentration in the injection brine rendered the initially oil-wet core to a more water-wet state as quantified by Lak and modified Lak wettability indices. Results in this research collectively suggest the importance of in-situ solution pH in wettability alteration by aqueous FM solution in carbonate media, in order to cause the rock surface to be positively charged in the presence of FM and calcium ions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.87)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (6 more...)
Abstract Thermally-activated, single-component resin formulations in which the catalyst is included in the resin composition can be challenging to place over intervals longer than 30 feet (9.1 meters). Despite the proven consolidation performance observed with epoxy-based systems, initial viscosity and rapid reactivity leading to short placement times have resulted in the industry seeking alternative chemistries to enhance formation integrity. Herein we report the development of a 2-stage formation consolidation system entailing a hetero-aromatic-based resin composition that, once placed downhole, will only begin curing with subsequent introduction of an activation fluid. The latent property of the updated resin formulation allows for extended lateral applications, and incorporating a new surface modifying agent allows for the treatment of formations with an excess of 20% wt—clay mineralogy.
- Asia (0.68)
- Africa > Nigeria (0.68)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.66)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 359 > Mahogany Field (0.99)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Ship Shoal South Addition > Block 349 > Mahogany Field (0.99)
- North America > United States > Alaska > North Slope Basin > Umiat-Gubik Area > Umiat Field > Tuluvak Formation (0.99)
- (5 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- (10 more...)
Abstract Halite scaling in natural gas production systems may cause formation damage, particularly in zones immediately surrounding the well and perforations. The clogging of flow paths has induced the loss of productivity (and injectivity in CO2 injection wells) and, in some cases, total abandonment of wells. This paper captures the process of drawdown as the main driver of the salt precipitation phenomena under specific field conditions. Calculations were performed using reactive transport compositional reservoir simulation software to model the impact of drawdown on the change in water solubility in the gas phase during low water-cut gas production in a specific field. 1D and 2D radial models with small near-well blocks and large outer blocks were developed to account for water vaporization at irreducible and mobile water saturations, considering capillary pressure effects (horizontal and vertical imbibition) and gravity segregation. Changes in the values of critical parameters such as absolute permeability, production rate, and initial reservoir pressures were inputted to test their impact on salt precipitation. Calculations confirm that the steepest pressure gradients occur closest to the wellbore. Consequently, there is an increase in water solubility in the methane as the gas approaches the well, which causes an increase in the rate of evaporation and a greater propensity toward drying out in the near-wellbore region. For the 1D model at irreducible water conditions, the dry-out zone increases as the permeabilities, and initial reservoir pressures decrease. In contrast, there is reduced salt deposition as the production rate is reduced. Under mobile water conditions and horizontal imbibition, the dry-out zone is extended, but only a slight increase in formation damage occurs. Horizontal imbibition causes an increase in pressure gradient because it reduces gas mobility. The Kozeny-Carman porosity-permeability relationship meant a 16% reduction in porosity resulting in a ~35% reduction in permeability near the well. The 2D modelling suggests a similar trend to 1D, but with a much stronger localized effect in the lower parts of the well due to vertical imbibition, resulting in up to 95% porosity loss locally. In contrast to the horizontal imbibition, this is due to the vertical imbibition causing a greater mass of salt to be transported into the dry-out zone. The information presented in this study provides a platform for operators by which the theory and concepts underlying salt precipitation may be better understood. Improved reservoir management decisions may then be made, and methods of optimally producing the wells in this field could be adequately deployed. Depending on economic considerations, reducing flow rates and managing well bottom hole pressures could be considered, in addition to the application of wash water treatments whilst the problem remains localized.
- Europe (0.95)
- North America > United States (0.93)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Abstract The interaction between clay minerals in formations and drilling fluids was analyzed through a study of four core plugs in different types of fluid, including gas oil, anionic surfactant (SDS), non-ionic surfactant (PEG), and cationic surfactant (CTAB). The core plugs were cut for petrophysical tests, including permeability, saturation, X-ray diffraction, and petrographical analyses. The original samples contained clay minerals such as illite and smectite. A static immersion test revealed that swelling and dispersing changed the original petrophysical rock properties of the samples. The addition of nanoparticles of Ca, K, Na, Cl at low, high, and saturated salinity in sodium chloride (NaCl), potassium chloride (KCl), and calcium chloride (CaCl2) was used to reduce active shale and increase mud density from 8.33 to 11.8 ppg, improving petrophysical rock properties by reducing filtration and swelling. The permeability and water saturation were measured before and after core injection of the drilling fluids. The results showed that surfactants (PEG) > (SDS) > (CTAB) in a water-based drilling fluid improved fluid loss and viscosity and reduced the interfacial tension, shifting the reservoir wettability towards a more water-wet state in low, high, and saturation salinity. The use of surfactants in water-based mud reduced formation damage and increased well productivity.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Abstract For hydraulic fracturing of low permeability dry gas formation, capillary discontinuity at the matrix-fracture interface and fluid entrapment in the hydraulic and natural fractures can impact the effective fracture half-length and thus result in loss of fracture conductivity. Adding surfactant-based novel fluids can reduce the capillary trapping of fluids by lowering the surface tension and modifying wettability to less water-wet condition and thereby improve the relative gas permeability and well productivity. In this work, a novel surfactant-based fluid was developed to be effective in reducing water entrapment. The surfactant formulation was evaluated in various reservoir conditions including Eagle Ford, Permian, Duvernay, Kansas St. Louis, and Bakken. The new formulation showed excellent stability under harsh reservoir conditions up to 150 °C and 27% TDS. Additionally, a laboratory workflow was developed to evaluate the efficiency of surfactant formulations in the mitigation of water entrapment using two-phase coreflood (CF). Our results show that three formulations (A, B and C) reduce the surface tension comparably. However, in the liquid recovery test using CF, formulations B and C outperformed A, resulting in much higher recovery of the aqueous fluid compared to the control case of formation brine. Wash-off tests were further performed by flushing the cores with fresh brine after treatment with novel formulations. The core treated with formulation C outperformed B after 5 pore volume (PV) flush of brine. Notably, for the core treated with formulation C, even after flushing with 140 PV of brine, the fluid recovery is still much higher compared to the brine case without treatment. Interestingly, formulation C performs even better in the harsh reservoir condition with high salinity brine, which can be explained by the three different adsorption patterns governing the interaction energy between surfactant and rock surface. This work demonstrates that tailoring fluid-rock interactions is crucial to reduce the water entrapment and thereby improve gas productivity for dry gas wells. Our workflow provides a comprehensive process to understand the mechanisms behind water entrapment and how to tailor novel formulations to reduce water entrapment in dry gas wells.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.94)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.66)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (3 more...)
ABSTRACT The subsurface geothermal energy storage system uses underground temperatures for energy extraction and storage. The energy is extracted by an injection-production-shut in procedure. Working fluids (i.e., water) are injected into the underground and heated by the subsurface high-temperature reservoir. Then, the fluids are extracted to the surface for thermal purposes, such as electricity generation and direct-use applications. This study establishes a parametric study using numerical simulation methods to comprehensively understand the influence of reservoir properties and operational factors on the geothermal energy storage system. A huff-n-puff well is modeled to simulate energy extraction and storage purposes. Water is injected for 8 hours, produced for 10 hours, and shut in for 6 hours. The reservoir is assumed to be a pure water reservoir (the only fluid in the reservoir is water). The total time for one cycle is 24 hours (a day). The performance of the well in 30 days is simulated. Effects of several reservoir properties and operational parameters such as formation temperature, heat capacity and thermal conductivity of formation, permeability, porosity, injected, and produced rates are evaluated. The results present that as formation porosity increases from 5% to 30%, energy in place grows 26.1%. The water recovery factor decreases from 0.52 to 0.087. Compared with vertical permeability, horizontal permeability has a much more significant influence. The formation temperature increases from 60 °C to 210 °C resulting in a 434% increase in the energy in place. Water recovery factor rises from −0.27 to 0.17 as the temperature from 60 °C to 90 °C, then remains constant (the negative value means under this condition the injected rate of water from the surface facilities is higher than its produced rate). Thermal conductivity has no important changes in energy extraction, while heat capacity affects the energy in place. When heat capacity is accelerated from 1.3×10 to 2.5×10 J/(m·day·°C), the total reservoir energy increases by 60%. Operation factors significantly influence the recovery factor and reservoir energy by changing the injected and produced rates.
- North America > United States > Montana > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Asia > Middle East > Iran > Khuzestan > Zagros Basin > Ahwaz Field > Khami Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
ABSTRACT In the last two decades, ultrasonic (US) technologies research has increasingly earned attention for applications in the oil and gas industry. Numerous laboratory and field studies have proven ultrasonics as an efficient, sustainable, and cost-effective technology for improving well productivity. This paper pursues the elaboration of a review of the most recent research related to ultrasonic technologies for applications in the oil and gas industry. The huge gap between numerical and field studies in comparison with laboratory studies deems it necessary to increase efforts on developing numerical models and field tests of the ultrasonic effect. A review of the US mechanisms for enhanced oil recovery (EOR) and emulsification/demulsification was conducted. Cavitation and thermal effects on wellbore fluid and formation rock have been widely accepted as two of the most influencing mechanisms. Most authors agreed that ultrasonics is a highly efficient method for EOR and emulsion treatment if the optimal conditions are identified and achieved. Treatment with ultrasound waves has shown improvement of oil recovery efficiency rates of over 90% and viscosity reduction values of over 80%. The most efficient results were observed when in combination with another conventional EOR method, where ultrasound boosts the recovery efficiency. INTRODUCTION Current oil well stimulation methods, such as acid stimulation, are in many cases ineffective and might cause additional operational issues such as emulsion formation, secondary chemical reactions, among others. These methods also involve the use of dangerous contaminants jeopardizing the facilities, personnel, and the environment. Emerging new technologies such as ultrasound stimulation present numerous advantages compared to conventional methods required by the Oil & Gas (O&G) industry to perform maintenance operations and oil well stimulations. The present work intends to perform a comprehensive review of the available literature gathered regarding existing laboratory studies and field tests of ultrasound technology. Previous work covered state of the art summaries for research related to ultrasound with quite specific scopes and timelines. The current work intends to continue previous researchers’ efforts with a wider focus integrating these publications, analyzing the most prominent applications for ultrasound technologies, and compiling a global summary with the latest publications and trends in ultrasonics and sonochemistry research.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (0.71)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.70)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.69)