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Collaborating Authors
Results
Summary Injecting water with chemicals to generate emulsions in the reservoir is a promising method in the enhancement of heavy‐oil recovery because the formation of oil‐in‐water (O/W) emulsions significantly reduces oil viscosity. Nanoparticles (NPs) (Pickering emulsions) can be used for this purpose as a cost‐effective alternative to expensive surfactants; however, such Pickering emulsions need to be stable for successful applications. The objective of this study is to screen the effective emulsifier for O/W emulsions from a broad range of solid NPs and identify suitable Pickering emulsifying agents (e.g., adjusting pH or salt concentration) that can render emulsions stable at relevant conditions, and to investigate how a range of physical parameters, such as particle concentration, water/oil ratio (WOR), and temperature affect emulsion stability. Five NPs—including cellulose nanocrystals (CNCs), silica, alumina, magnetite, and zirconia—were tested on their capabilities of stabilizing O/W emulsions through glass vial screening tests under various pH and salinity conditions. The screening results showed that the CNC could become an effective emulsifier by either adjusting pH or salinity. In addition, zeta potential measurements were conducted to explain the observations. The stabilization mechanisms of CNCs were studied through an epifluorescent transmitted microscope showing that the formation of a dense particle layer around the oil droplets, as well as a network in the continuous phase, were the two main mechanisms accounting for the high stability of the emulsions stabilized by CNCs. The effects of particle concentrations on the emulsion stability were studied quantitatively by analyzing the droplet‐size distributions calculated by the open-source ImageJ software, with the results showing a sharp decrease in droplet size, followed by a smooth change as the particle concentration increased. For the WOR effect, phase inversion from O/W to water‐in‐oil (W/O) emulsions was observed when the oil content was more than 0.6. The thermal stability of emulsions was studied both macroscopically by glass bottle tests and microscopically through a microscope, both of which show that the CNC‐stabilized emulsions remained thermally stable up to 100°C. The rheological properties of both aqueous dispersions of CNCs and the corresponding O/W emulsions were also measured under various salinity conditions. The results showed that the salinity had a great impact on the viscosity of the CNC suspension and the typical shear‐thinning behavior of Pickering emulsions. This study provides an option to enhance emulsion stability without surfactants, which will reduce the costs and facilitate field applications of emulsion flooding in heavy‐oil recovery.
- North America > United States (0.93)
- North America > Canada (0.68)
- Asia > Middle East > Saudi Arabia (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
Mechanics of SAGD Efficiency Improvement Using Combination of Chemicals: An Experimental Analysis through 2D Visual Models
Huang, Jingjing (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Chengdu University of Technology and University of Alberta) | Babadagli, Tayfun (University of Alberta)
Summary Steam‐assisted gravity drainage (SAGD) is (and will be) a dominating method for in‐situ recovery of heavy oil and bitumen in Canada. Its efficiency, however, has been a chronic problem due to the excess use of water and energy causing inflated costs. Solutions are needed to both maintain the production, especially at the late stages, and reduce the amount of steam. One method to improve efficiency is injection of chemicals with steam. This study addresses this problem by focusing on three critical aspects of SAGD: sweep improvement (faster and larger chamber growth), better displacement efficiency (lower residual oil), and reducing the amount of steam (lower steam/oil ratio and lowered steam temperature). By addressing these issues, we provide answers for the proper formulation of chemical blends, optimal injection strategies (continuous or slug), and the right time to introduce chemicals (beginning, midstream, or mature phase). The efficiency of a single chemical additive in recovery improvement is limited because it serves for only one of the mechanisms previously listed. For a better performance, blending chemicals with different functionalities was proposed in this study. Additives showing the highest microscopic oil displacement efficiency (heptane, Novelfroth® 190) and the highest areal sweep efficiency EA [LTS‐18, silicon dioxide (SiO2) nanoparticle, Tween™ 80, deep eutectic solvent (DES) 11] in our previous studies were selected. Eleven different combinations of these six chemical additives were tested for different injection strategies, and the SAGD process was visualized on Hele‐Shaw cells filled with heavy oil. The interaction between different chemical additives was determined by analyzing emulsification, wettability alteration, and the growth and shape of the steam chamber. The optimal formulation and ideal injection strategy were selected by analyzing ultimate EA, microscopic oil displacement efficiency, ultimate oil recovery, energy and water consumption, and the price of chemical additives. The interaction rule of combined chemical additives and their contribution to the recovery during SAGD were clarified, and the optimal injection strategies (best blends and proper time to introduce chemicals) were identified to provide a reference for chemical selection for field applications. This is a critical attempt to reduce the steam/oil ratio (particularly the amount of steam used) in SAGD applications, especially at mature stages.
- Asia > Middle East (1.00)
- North America > Canada > Alberta (0.95)
- North America > United States > California (0.93)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.64)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Venezuela > Zulia > Maracaibo Basin > Tia Juana Field (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
Performance Comparison of Novel Chemical Agents for Mitigating Water-Blocking Problem in Tight Gas Sandstones
Huang, Hai (Xi’an Shiyou University and Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta and Xi’an Shiyou University) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta and Xi’an Shiyou University) | Zhang, Yanming (Oil & Gas Technology Research Institute of Changqing Oilfield Company)
Summary Water blocking can be a serious problem, causing a low gas production rate after hydraulic fracturing, a result of the strong capillarity in the tight sandstone reservoir aggravating the spontaneous imbibition. Fortunately, chemicals added to the fracturing fluids can alter the surface properties and thus prevent or reduce the water‐blocking issue. We designed a spontaneous imbibition experiment to explore the possibility of using novel chemicals to both mitigate the spontaneous imbibition of water into the tight gas cores and measure the surface tensions (STs) between the air and chemical solutions. A diverse group of chemical species has been experimentally examined in this study, including two anionic surfactants (O242 and O342), a cationic surfactant (C12TAB), an alkaline solution of sodium metaborate (NaBO2), an ionic liquid (BMMIM BF4), two nanofluids with aluminum oxide and silicon oxide (Al2O3 and SiO2, respectively), and a series of deep eutectic solvents (DES3‐7, 9, 11, and 14). Experimental results indicate that the anionic surfactants (O242 and O342) contribute to low STs but cannot ease the water‐blocking issue because they yield a more water‐wet surface. The high pH solution (NaBO2), ionic liquid (BMMIM BF‐4), and sodium chloride brine (NaCl) significantly decrease the volume of water imbibed to the tight sandstone core through wettability alteration, and C12TAB leads to both ST reduction and an air‐wet rock surface, helping to prevent water blocking. The different types of DESs and nanofluids exhibit distinctly different effects on expelling gas from the tight sandstone cores through water imbibition. This preliminary research will be useful in both selecting and using proper chemicals in fracturing fluids to mitigate water‐blocking problems in tight gas sandstones.
- North America > United States (1.00)
- Europe (0.93)
- North America > Canada > Alberta (0.47)
- Asia > China > Shaanxi Province (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Oceania > Australia > Western Australia > Perth Basin (0.99)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- (4 more...)
Summary Foamy oil flow is a commonly encountered drive mechanism in the primary production (depletion of naturally methane‐saturated heavy oil) and secondary stage (cyclic gas—mostly methane—injection after primary production). In the former, among other important parameters, pressure depletion rate has been reported to be the most crucial parameter to control the process. In the latter, type and amount of the gas (also described as “solvent”) and application conditions such as soaking time durations and depletion rates are critical. The cornerstone of the foamy oil behavior relies on its stability, which depends on parameters such as oil viscosity, temperature, dissolved gas ratio, pressure decline rate, and dissolved gas (solvent) composition. Although the process has been investigated and analyzed for different parameters in the literature, the optimal conditions for an efficient process (mainly foamy oil stability) has not been thoroughly understood, especially for the secondary recovery conditions (cyclic solvent injection, CSI). In this paper, internal and external gas drive mechanisms for foamy oil performance are reviewed in detail. The optimal conditions of the applications were compiled and listed for different primary production and secondary recovery stages. Combination of methane with other gases as a CSI practice was also discussed to accelerate the process and reduce cost in an effort to improve efficiency. It is reported that combining methane injection with air as a secondary recovery method can save up to 51% of solvent gas.
- South America (1.00)
- North America > United States (1.00)
- North America > Canada > Alberta (1.00)
- Asia > Middle East (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Steam-solvent combination methods (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)
Although thermal recovery seems to present the desired effect on heavy-oil production, this technique carries significant transformation in reservoir thermodynamics. Mobilization of heavy oil in the reservoir through viscosity reduction is the principal intention of this technique (Ali 1974; Ali and Meldau 1979; Blevins et al. 1984; Haghighi and Yortsos 1997; Taylor 2018); however, the increase in temperature could directly or indirectly influence nearly all reservoir parameters, including fluid and interfacial properties, petrophysical characteristics, and solid/fluid interfacial energy. To be specific, the effect caused by thermal energy does not only occur in fluid/fluid interactions but also in rock/fluid interactions. Wettability has been confirmed to be an essential parameter to represent and explain the change in reservoir thermodynamics and is considered to be the most-predominant variable affecting oil-recovery performance as well as enhanced-oil-recovery processes (Moore and Slobod 1955; Crocker and Marchin 1988; Kovscek et al. 1993; Clinch et al. 1995), even in the case of thermal recovery (Hoffman and Kovscek 2004). The complexity of the wettability mechanisms makes this variable remain unclear, particularly in steaminjection applications. Plentiful research publications in the area of heavy-oil recovery have mentioned that thermal energy could favorably alter the wettability state of the rock (primarily because of the removal of heavier/polar components on the rock surface). Nevertheless, this information stays controversial, similar to other effects of temperature (such as changes in the rock composition or scale deposition caused by changes in temperature) (Rao 1999; Punase et al. 2014).
- Asia > Middle East (0.93)
- North America > Canada > Alberta (0.68)
- North America > United States > California (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.82)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.93)
Summary When considering the wettability state during steam applications, we find that most issues remain unanswered. Removal of polar groups from the rock surface with increasing temperature improves water‐wettability; however, other factors, including phase change, play a reverse role. In other words, hot water or steam shows different wettability characteristics, eventually affecting the recovery. Alternatively, wettability can be altered using steam additives. The mechanism of this phenomenon is not yet clear. The objective of this work was to quantitatively evaluate the steam‐induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the phase change of water and by chemical additives. Heavy oil from a field in Alberta (27,780 cp at 25°C) was used in contact‐angle measurements conducted on quartz, mica, calcite plates, and rock pieces obtained from a bitumen‐containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature ranging up to 200°C using a high‐temperature/high‐pressure interfacial tension (IFT) device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock type, and contact sequence, were considered and studied separately. To study the effect of pressure on wettability, we started by maintaining the water in liquid phase and measuring the contact angles between the oil and water at different pressures. Next, the contact angle was measured in pure steam by keeping the pressure lower than saturation pressure. The influence of contact sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement; these measurements were repeated on different substrates. Different temperature‐resistant chemical additives (alkalis, surfactants, ionic liquid) were added to the steam during contact‐angle measurement to test the wettability alteration characteristics at different temperatures and pressure conditions (steam or hot‐water phase). In addition to these wettability‐state observations, surface‐tension experiments were conducted to evaluate the performance of additives in reducing surface tension for the oil/steam system. The results showed that the wettability of the tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil‐wet in steam than in water at the same temperature in the calcite test. The wettability state could be altered by using chemical additives in certain ranges of concentration; moreover, the optimal chemical‐additive concentration was also observed from both contact‐angle and surface‐tension measurements. Analysis of the degree of wettability alteration induced by steam (or hot water) and temperature was helpful to further understand the interfacial properties of the steam/bitumen/rock system, and proved useful in the recovery‐performance estimation of the steam‐injection process in carbonate and sand reservoirs, specifically in chemically enhanced heavy‐oil recovery.
- Asia > Middle East (1.00)
- North America > Canada > Alberta (0.89)
- North America > United States > California (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
- North America > United States > California > San Joaquin Basin > Kern River Field (0.99)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
Summary Cyclic steam stimulation (CSS) is a proven effective technique for boosting oil production. Metal species can act as a catalyst for aquathermolysis reactions between heavy oil and water during the CSS process. For this paper, a series of CSS experiments with and without metal nanoparticles was conducted at temperatures up to 220°C to compare the performance of nickel and iron oxide nanoparticles in promoting aquathermolysis reactions in CSS; further, different loadings of metal nanoparticles were also tested in the CSS experiments. During the experiments, we monitored the variations of oil recovery factor, oil viscosity, gas composition, and water production. The experimental results show that both nickel and iron oxide nanoparticles can act as a catalyst for aquathermolysis reactions and reduce the viscosity of heavy oil. However, their respective catalytic effects differ significantly: nickel nanoparticles can break the C‐S bond more effectively than iron oxide metal nanoparticles, thus achieving a higher ultimate oil recovery factor of CSS. The introduction of metal nanoparticles boosted oil production and increased water production from the very first cycle in the CSS process. The gas chromatography (GC) analysis and the pressure data recorded during each soaking period revealed that a higher amount of evolved gas including alkenes and hydrogen sulfide was generated in the early stage, increasing reservoir pressure and forcing more condensed water to be produced from the sandpack.
- Asia > Middle East (0.68)
- North America > Canada > Alberta (0.29)
- North America > United States > California (0.28)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral > Oxide > Iron Oxide (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- South America > Venezuela (0.89)
- North America > United States > Louisiana > China Field (0.89)
Summary Capillary imbibition tests are commonly applied to measure wettability-alteration potential of chemicals. However, these tests are exhaustive, time-consuming, and expensive, and the underlying physics of the alteration process from a surface-chemistry point of view is often limited and/or unexplained. Contact-angle measurement is a quicker and more-feasible screening tool to assess the emerging wettability modifiers. It also provides visual data on the mechanics of the wettability-alteration process. This paper focuses on contact-angle measurements as a means to evaluate the wettability alteration on mineral plates and porous-rock samples. Imidazolium ionic liquids were tested at different concentrations. To study the effect of pH on the wettability, sodium chloride and sodium borate were used at different concentrations. The composition of divalent ions was varied because of their possible use with low-/high-salinity water as wettability-alteration agents. Unmodified and surface-modified silica, zirconium, and alumina nanoparticles were also tested. Contact-angle measurements were performed initially on mica, marble, and calcite plates. Experiments were repeated on polished surfaces of Berea sandstone, Indiana limestone, and cleaned Grosmont carbonate cores. Oils (pure and solvent-mixed crude oils) with different viscosities and densities were used to test the effect of oil type on the process. The images were obtained by an single-lens reflex (SLR) camera at different temperatures ranging from 25 to 80°C. By testing with different concentrations, the optimum chemicals were found for different mineral-plate/porous-rock systems. Then, the results were cross checked with the imbibition tests performed on the same samples to validate the contact-angle-measurement observations. Thermal-stability tests were also performed in case of their use during or after a thermal method. For the thermal-stability tests, contact-angle experiments were conducted in a high-pressure and high-temperature (up to 200°C) cell. It was shown that certain ionic liquids and nanofluids are stable at high temperatures and can be efficiently used at low concentrations.
- North America > Canada > Alberta (0.29)
- North America > United States > Indiana (0.26)
- North America > United States > West Virginia (0.25)
- (3 more...)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.38)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.74)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Yibal Field > Yibal Khuff Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Yibal Field > Sudair Formation (0.99)
Summary Light-hydrocarbon solvent injection is an effective process to improve heavy-oil/bitumen recovery from oil sands. In this process, oil production is achieved by gravity drive, which is enhanced through the dilution of oil by injected solvent. However, solvent retrieval is one of the major economic concerns in defining the viability of this technique. In this research, a sandpack experimental study was conducted, and the solvent retrieval was determined on the basis of thermodynamic conditions and fluid characterization. Two heavy-oil samples (8.6°API and 10.28°API) from different fields in Alberta, Canada, and four light-hydrocarbon solvents (propane, n-hexane, n-decane, and distillate hydrocarbon) were used in this experimental scheme. Results showed that solvent retrieval increases when light-hydrocarbon solvents (propane and distillate hydrocarbon) are used compared with solvent with high molecular weight (n-hexane and n-decane). Temperature and pressure highly influenced the solvent retrieval. The percentage of solvent retrieval increased when the hydrocarbon solvent was closer to the vapor phase (dewpoint). However, oil recovery showed significant reduction when propane and n-hexane were injected because of high asphaltene deposition on the sandpack. The maximum solvent retrieval was calculated to be nearly 98% at 120°C and 698.47 kPa when propane-and-distillate hydrocarbon was used as solvent. Formation damage, on the other hand, may increase when propane is used as solvent because of the high asphaltene deposition.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Summary Foamy-oil flow is encountered not only during the primary stage of the cold-heavy-oil-production (CHOP) process through evolving methane originally in the oil but also in the post-CHOP enhanced-oil-recovery (EOR) applications in which different gases are injected and dissolved in heavy oil. Despite remarkable efforts on the physics of foamy oil flow, the mechanics of its flow through porous media is not properly understood yet. This is mainly because of lack of detailed experimental studies at the core scale to clarify the physics of the process and to support numerical-modeling studies. One also should test foamy-oil flow for different types of EOR gases dissolved and evolved at different conditions under pressure depletion. The objective of the present work is to perform detailed laboratory experiments on foamy-oil flow through porous media. Pressure/volume/temperature (PVT) studies were conducted to determine the actual pressure ranges in the coreflooding experiments in the beginning. After dissolving different gases in dead oil at 400 psi for methane (CH4) and carbon dioxide (CO2) and 112 psi for propane, the oil was injected into a sandpack to saturate it. The solution-gas-drive test was started by opening the outlet valve of the coreholder after reaching equilibrium. To mimic typical post-CHOP EOR conditions with methane, propane, or CO2 injection, the pressure was kept high (400 psi for CO2 and CH4 and 112 psi for propane). The produced oil by solution-gas drive and the gas evolved were monitored by collecting them in a graduated cylinder and a gas cylinder, respectively, while the pressure was recorded by an automatic data-acquisition system. The experimental data provided information about the effect of initial pressure of the depletion test in the amount of oil and gas measured as well as the visual observations of bubble characteristics of the foamy oil. Results showed that, among the three gases, CO2 is a good candidate for foamy oil. Maximum oil recovery [more than 50% of original oil in place (OIP) (OOIP)] was obtained in case of CO2.
- North America > Canada > Alberta (0.94)
- Asia > Middle East (0.93)