Injected Pore Volume Research Articles

Analysis of the Effects of Partially Hydrolyzed Polyamide on Oil Reservoir Rocks

The exploitation of heavy oil fields has recently gained momentum due to increased investment in new oil and gas fields and especially due to environmental legislative constraints. That is why in this article I have described the possibility of using partially hydrolyzed polyacrylamide in the exploitation of heavy crude oil deposits, by injecting it into reservoir rocks followed by injection of reservoir water. The role of this polymer is to provide lubrication of the crude oil and water flow channels and especially to block (by reverse osmosis) the large pore communication channels in order to limit pressure leaks in uncontrollable areas. In the study we created two polymers that were used in order to increase the flow rate and decrease the viscosity and the freezing point (additives that are easy to procure and especially with spectacular results in the treatment of stills and without affecting the stability and quality of the final products refinery). We also studied the flow of the polymer through carbonate reservoir rocks, managing to obtain a numerical model that provides data on the rock resistance factor to the flow of partially fluidized polyacrylamide. The adsorption on the surface of the rocks determined the reduction of the mobility of the polymer but also the modification of the gel structure by the modification (crossing) of the polymer (of the polymer chains) which led to clogging (blocking of the pores) and increasing the possibility of fluid flow. In the laboratory we determined the adsorption of silicon for a solution of polyacrylamide of 0.05% partially hydrolyzed concentration in water, it increases from the value of 0.01 mg/m2 to 0.05 mg/m2 when the concentration in NaCl increases from 0 .5% to 10% in are we showed that adsorption increases for pH values ​​lower than 7, and it is stated that for a porous sand medium with a permeability of 140 mD, replacing saline water with 20 g/l NaCl, a presence of the polymer with a concentration of 400 ppm was observed in the effluent, and this value being approximately stabilized after 5 injected pore volumes.

Spatiotemporal X-Ray Imaging of Neat and Viscosified CO2 in Displacement of Brine-Saturated Porous Media

Summary CO2 storage in saline aquifers may contribute to a 90% share in preventing emissions to the atmosphere. Due to low CO2 viscosity at the subsurface often found in supercritical (sc) conditions, the injected CO2 may spread quickly at the formation top and increase the probability of leakage. This work relates to improved CO2 storage in saline aquifers by effective viscosification of the sc-CO2 at very low concentrations of engineered oligomers and the effectiveness of slug injection of viscosified CO2 (vis-CO2). We present the results from X-ray computed tomography (CT) imaging to advance the understanding of two-phase CO2-brine flow in porous media and firmly establish the transport mechanisms. X-ray CT imaging of displacement experiments is conducted to quantify the in-situ sc-CO2 saturation spatiotemporally. In neat CO2 injection, gravity override and adverse mobility ratio may result in early breakthrough and low sweep efficiency. We find cumulative brine production from the fraction collector to be lower than X-ray CT imaging at 2 pore volume (PV) injection. The difference between the two is attributed to the solubility of the produced water in the produced CO2 at atmospheric pressure. We show that when the solubility is accounted for, there is a good agreement between direct measurements and in-situ saturation results. There are three reports (two by the same group) that oligomers of 1-decene (O1D) with six repeat units may have marginal CO2 viscosification. The majority of published work by other groups shows that O1D with six repeat units and higher are effective CO2 viscosifiers. In the past, we have demonstrated the effectiveness of an O1D in the displacement of brine by CO2 at a concentration of 1.5 wt%. The effectiveness is examined and identified by three different methods. In this work, we show that the same oligomer is effective at a low concentration of 0.6 wt%. The oligomer slows the breakthrough by 1.6 times and improves the brine production by 34% in the horizontal orientation. X-ray CT imaging results reveal that such a large effect may be from the increase in the interfacial elasticity. We also show that there is no need for continuous injection of the oligomer. A slug of 0.3 PV injection (PVI) of vis-CO2 followed by neat CO2 injection has the same effectiveness as the continuous injection of the vis-CO2. In this work, we also demonstrate the effectiveness of a new engineered molecule at 0.3 wt% that may increase residual trapping by about 35%. The combination of mobility control and residual brine saturation reduction is expected to improve CO2 storage by effective viscosification with low concentrations of oligomers.

Upscaling the reaction rates in porous media from pore- to Darcy-scale

Modeling and prediction of reactive transport in porous media are challenging due to the complexity of the characterization of reactions across spatial and time scales. The application of reaction rates obtained from batch experiments to porous media is not valid because it disregards the influences of flow pathways, distribution of residence time, transport limitations within the porous media, as well as neglecting the impact of surface mineralogy heterogeneity. In this study, we presented how the pore-scale modeling can help to improve the Darcy-scale simulations. First, the reactive transport was simulated in a pore-network model and was validated against the experiments. Then, the pore-network results were averaged to obtain the effective reaction rates as a function of pore velocity, the inlet concentration, and the resident concentration. The upscaled function was incorporated into the Darcy-scale model and showed a significant improvement in predicting the concentration profiles. Notably, the use of batch reaction rates in the Darcy model (ADRE-batch) led to significant underestimation, up to 93%, of the required pore volume injection for complete contaminant removal from the simulation domain.

Low-Salinity Waterflooding for EOR in Field A of Western Offshore Basin: A Pilot Study Analysis with Laboratory and Simulation Studies—Early Observations

Carbonate reservoirs hold vast oil reserves, but their complex properties make traditional enhanced oil recovery (EOR) methods challenging. This study explores the application of low-salinity water flooding (LSWF) as a novel EOR method for India’s largest offshore carbonate oil field. Conventional EOR techniques were deemed unsuitable due to reservoir heterogeneity, pressure decline, high temperature, and the offshore location. Favorable factors for LSWF included successful seawater flooding history, medium-weight crude oil, and existing infrastructure. Following core flooding experiments demonstrating a 6–16% increase in oil recovery, a multi-pronged evaluation process was implemented. Single-well chemical tracer tests (SWCTT) and reservoir simulations confirmed the potential of LSWF. A specific target area was chosen based on reservoir characteristics, production data, and available facilities. Simulations predicted a 1.5% incremental oil recovery using diluted seawater (25% salinity) at 30% pore volume injection. After a positive techno-economic analysis, the first offshore LSWF project in India was completed within 3 years. Initial monitoring results are encouraging. This study highlights the successful journey of LSWF from concept to field deployment in a challenging carbonate reservoir, showcasing its potential for revitalizing such fields. Furthermore, this work provides valuable data relevant to Indian offshore environments, where factors like salinity, mineralogy, and crude oil composition pose unique challenges compared to other LSWF applications. These detailed data fill a critical gap in the existing literature.

The Use of an Advanced Intelligent-Responsive Polymer for the Study of Dynamic Water-Carbon Dioxide Alternating Displacement.

Addressing the issue of inadequate temperature tolerance in traditional polymers, in this study, we successfully executed a one-step synthesis of intelligent-responsive polymers which have excellent adaptability in water-gas alternating displacement scenarios. Utilizing the fatty acid method, we produced OANND from oleic acid (OA) and N,N-dimethyl-1,3-propanediamine (NND). Upon testing the average particle size in the aqueous solution both prior and subsequent to CO2 passage, it became evident that OANND assumes the form of a small-molecule particle in the aqueous phase, minimizing damage during formation. Notably, upon CO2 exposure, it promptly organizes into stable micelles with an average size of 88 nm and a relatively uniform particle distribution. This unique characteristic endows it with a rapid CO2 response mechanism and the ability to form a highly resilient gel. In the exploration of viscoelastic fluids, we observed the remarkable behavior of the AONND aqueous solution when CO2/N2 was introduced. This system displayed repeatable transitions between aqueous and gel states, with the highest viscosity peaking at approximately 3895 mPa·s, highlighting its viscosity reversibility and reusability properties. The rheological property results that we obtained indicate that an elongated micellar structure is present in the solution system, with the optimal concentration ratio for its formation determined as 0.8, which is the molar ratio of the OANND-NaOA system. In the sealing performance tests, a 1.0 wt% concentration of the gel system exhibited excellent injectability properties. At 80 °C, this gel effectively reduced the permeability of a sand-filled model to 94.5% of its initial value, effectively sealing potential leakage paths or gas fluxes. This remarkable ability to block leakage paths and reduce seepage capacity highlights the material's superior blocking effect and erosion resistance properties. Furthermore, even at a temperature of 90 °C and an injection pore volume (PV) of 3, this plugging system could reduce the permeability of a high-permeability sand-filled model to over 90% of its initial value.

Development of Novel Star-Like Branched-Chain Acrylamide (AM)-Sodium Styrene Sulfonate (SSS) Copolymers for Heavy Oil Emulsion Viscosity Reduction and Its Potential Application in Enhanced Oil Recovery.

Injecting water with chemicals to generate emulsions in the reservoir is a promising method for enhancing heavy oil recovery because oil-in-water (O/W) emulsions significantly reduce oil viscosity. To enhance heavy oil recovery efficiency, we developed new star-like branched AM-SSS copolymers (SB-PAMs) with reduction in the viscosity of the heavy oil emulsion, which was synthesized by reversible addition-fragmentation chain transfer (RAFT) controlled radical polymerization. The core structure of the branched polymer was RAFT polymerization of acrylamide (AM) and N,N'-methylene bis-acrylamide (BisAM), in the presence of 3-(((benzylthio)carbonothioyl)thio)propanoic acid as a chain transfer agent, followed by chain extension with AM and SSS. The core structures were achieved by incorporation of total monomer ratios [BisAM]/[AM] of 1:11. The expansion of the core structures by copolymerization of AM and SSS resulted in star-like branched polymer SB-PAM-co-SSS with apparent molecular weights ranging from 240 to 2381 kDa. 1H-nuclear magnetic resonance (1H NMR) and Fourier transform infrared (FTIR) confirmed the synthesized polymer structure. The molecular weight was determined by gel permeation chromatography (GPC). The polydispersity coefficient was between 1 and 7, which has a broad molecular weight distribution. The polymer dissolves only 0.75 h in deionized water, faster than conventional polyacrylamide. At 50 °C, the viscosity of the 1000 mg/L SB-polymer solution can reach up to 45 mPa·s. First, heavy oil viscosity reduction by 800 mg/L SB polymer can reach 91.7%, at a water dehydration rate of 90.4%; second, with 0.6 PV injection, 800 mg/L SB polymer improved oil recovery up to 23.66% after water flooding; and third, SB-polymer-assisted hot water flooding shows that heavy oil recovery improved by 19.46% at 110 °C with 0.6 pore volume (PV) SB-polymer injection. This novel branched chain polymer with heavy oil emulsion capability will shed light on high-temperature polymer flooding and the development of a new candidate structure for heavy oil viscosity reduction.

Long tube flooding tests for investigating salt precipitation induced by CO2 injection

Capturing a large amount of CO2 from industry, energy production, or incineration plants and storing it in the subsurface such as depleted hydrocarbon reservoirs or saline aquifers can fundamentally reduce the footprint of atmospheric greenhouse gasses. Injection of CO2 in a saline aquifer zone or depleted hydrocarbon reservoir will vaporize formation water and lead to potential salt precipitation in porous rock, thus increasing the risk of formation damage near the wellbore area and reducing the injectivity of CO2 in the reservoir. Previous experimental studies on salt precipitation have focused on core flooding, including micro-core flooding, ordinary single-plug flooding, and composite core flooding. The length of the core plugs limits these flooding tests. They usually suffer from serious end effects, and it is generally challenging to investigate the variation along the flooding direction, especially after large pore volumes of injection. In this study (Project Greensand), we have researched and developed new equipment termed “long tube apparatus” to improve the understanding of salt precipitation and gage the effects of formation damage in detail for a North Sea depleted oil field reservoir (Nini West) under investigation, while injecting CO2. The main aim of the experiment was to determine two properties such as salt and water content, which are used to evaluate the formation damage due to salt precipitation. Finally, a numerical simulation was carried out using CMG GEM in both 1D homogeneous model and another heterogeneous model honoring the channeling at the inlet. Results with qualitative agreement were achieved, especially with the heterogeneous model.

Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates

Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10–20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4–5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8–10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery.

Heat Transfer Included Simulation of Carbonate Rock Acidizing Using Two-Scale Continuum Model with Varying Rock Physics Curves

Summary Matrix acidizing is the commonly used method to enhance permeability of a damaged zone around the well. Acid injection will dissolve the rock, creating narrow, high-permeability channels, called wormholes, to bypass the damaged zone. The pattern of wormhole generation indicates the efficiency of the well stimulation process. Although the injection rate has the most important role in this process, there are other factors such as rock properties, presence of an immiscible phase, and temperature variation that could also affect the dissolution pattern. A few studies have considered the simultaneous effects of all phenomena involved in the acidizing process. We have developed a two-phase heat transfer model coupled with a two-scale continuum model considering capillary and gravity forces for the first time, to simulate the wormhole dissolution pattern. It could be used to analyze the dissolution phenomenon of carbonate rock. A new two-phase relative permeability model is implemented to take the effect of dissolution on relative permeability curves into account. The influence of acid-rock temperature difference, reaction heat, nonisothermal condition, phase saturation, formation porosity, intrinsic permeability and heterogeneity on dissolution pattern, and number of injected pore volumes (PVs) before acid breakthrough is investigated in the developed model. The simulation results show that both optimum injection rate and required PV of acid to breakthrough are strongly dependent on acid and rock temperatures. High formation temperature increases both the optimum injection rate and the optimum number of injected PVs before breakthrough. Injection of acid at lower temperatures will decrease both the optimum injection rate and the optimum number of injected PVs to break through. Simulation results show that the optimum number of injected PVs to break through is 8% higher when reaction heat is considered. Formation properties and degree of heterogeneity influence the number of required injected PVs to breakthrough. Low porosity formations with high heterogeneity correspond to the lowest number of injected PVs to breakthrough. The results indicated that formations with higher permeability will have a higher optimum number of injected PVs to break through and an optimum injection rate. Simulated results show that increasing the initial water saturation will increase the volume of acid to breakthrough. Variation in initial water saturation has a minor effect on wormhole shape, but it does not change the dissolution regime.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

Simulation study of polymer flooding performance: Effect of salinity, polymer concentration in the Malay Basin

The major problem of the water flooding development process is the flood process's high mobility and viscous fingering. Previous studies have shown that polymer flooding is viable and can recover bypassed oil. However, the mechanism of the polymer flooding process is still tenuous in literature. Therefore, in this study, a two-dimensional model was used to simulate polymer flooding and forecast the mechanism of the polymer flood in the presence of electrolytes. Likewise, the effect of pH, pressure, and temperature on the polymer flooding process was investigated. Thereafter, the model was validated with an independent set of experimental data from the literature. The results show that the polymer flooding mobility ratio (M) was 0.36 indicating a favorable mobility control, thereby improving oil recovery by 60% of original oil in place (OOIP). In comparison, to water flooding mobility ratio of 3.6, which was greater than 1, thus resulted in viscous fingering, early water breakthrough, and oil recovery of 36% OOIP. Besides, at high salinity concentrations, the polymer adsorption was 3.3 mg/g compared to 2.2 mg/g from the experimental results. This indicates that the simulation results were consistent with the experimental results at the same concentration. Likewise, the simulation and experimental studies suggest high oil recovery was obtained at a higher injected pore volume. Finally, it can be concluded from this study that mechanical trapping and adsorption of the polymer on the pores of the porous media were the dominant mechanisms during the polymer flooding.

Laboratory Flushing Tests of Dissolved Contaminants in Heterogeneous Porous Media with Low-Conductivity Zones

The retention of contaminants within low-conductivity regions such as clay lenses and aquitards can greatly affect groundwater remediation processes. The aim of this study was to experimentally investigate the effects of the geometry of low-conductivity zones, conductivity contrast, and flow regime on solute flushing. We conducted a series of flushing tests in cylindrical models containing a cylindrical low-conductivity zone (i.e., low-K zone) embedded in a highly conductive medium (i.e., high-K zone). Seven models comprising four high-conductivity-contrast (SL, SS, LL, and LS), one medium-contrast (LLM), one low-contrast (LLL), and one homogeneous (H) models were considered. Experiments were conducted at two flow rates (Q = 0.6 and 26 cm3/min) for each heterogeneous model (SL, SS, LL, LS, LLM, and LLL) to compare the flushing processes in different flow regimes. First, we verified the validity of our experiments by comparing the results of the H model from an analytical solution with our experiment. The results of the high-contrast models showed that for a diffusion-dominated regime (Q = 0.6 cm3/min), the pore volume injected (PVI) required to flush out solute mass was much smaller than that in an advection-dominated regime (Q = 26 cm3/min). To evaluate the pore volumes required to flush out solutes for the four high-contrast models, we introduced a parameter P0.01, which is defined as the PVI needed for the relative concentration to become 0.01 at the middle of the low-K zone. P0.01 decreases with increasing the specific surface area of the low-K zone for diffusion-dominated regimes, while it increases with increasing the length of the low-K zone for advection-dominated regimes. We also determined the importance of the effect of K contrast on solute retention by comparing the results of three different models of K contrast (LL, LLM, and LLL).

Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Viscous Oil Reservoirs: A Combined Experimental and History-Matching-Based Analysis

Summary Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

An NMR-assisted laboratory investigation of coal fines migration in fracture proppants during single-phase water production

Proppants are injected with the fracturing fluid to keep the hydraulic fractures open. However, deposition of coal fines in the void spaces between proppants significantly damage flow conductivity of the fractures. In this study, we experimentally model coal fines migration in a proppant pack. Standard quartz sand (16–20 mesh) is used to prepare the proppant pack. The proppant pack is installed within a low-field Nuclear Magnetic Resonance (NMR) facility to record NMR response before and after the experiment of fines suspension injection. The injected suspension consists of water with 500 ppm concentration of coal fines of radius from 2.8 to 142.9 µm. Coal fines are generated by crushing an anthracite coal sample. The permeability is damaged significantly by about 41% after 80 pore volume injection. NMR response suggests that volume of the large-size pores (radius rp > 60 um) decreases while that of the medium-size pores (0.9 um <rp < 60 um) increases. The pore structure change is caused by two possible mechanisms: (a) reducing pore size by fines occupying pore space and (b) developing inter-particulate pore space of fines gathering at the damaged pores. Although the fines size (radius from 2.8 to 142.9 um) is significantly smaller than the pore size (<1005.2 um), the large-size pores can still be damaged by the fines. The results of this study can help to understand mechanisms of fines migration and conductivity evolution in/of the hydraulic fractures during Coal Seam Gas production.

Similarity-based laboratory study of CO2 huff-n-puff in tight conglomerate cores

Tight conglomerate reservoirs are featured with extremely low permeability, strong heterogeneity and poor water injectivity. CO2 huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs, owing to its advantages in reducing oil viscosity, improving mobility ratio, quickly replenishing formation pressure, and potentially achieving a miscible state. However, reliable in-house laboratory evaluation of CO2 huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure. In this study, we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO2 injection in a tight conglomerate reservoir. The impacts of depletion degree, pore volume injection of CO2 and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure. Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency (first increased and then decreased) with increased CO2 injection volume and soaking time. The lower oil recoveries under excess CO2 injection and soaking time were attributed to limited CO2 dissolution and asphaltene precipitation. This work guides secure and reliable laboratory design of CO2 huff-n-puff in tight reservoirs with high formation pressure.

A Visualization Study of Low-Tension Polymer Flooding for Viscous Oil Reservoirs

Summary Polymer flooding improves the sweep efficiency of viscous oil recovery over waterflooding. The low-tension polymer (LTP) flooding has the potential to improve the displacement efficiency due to low interfacial tension (IFT) without sacrificing sweep efficiency. Compared with ultralow tension (&amp;lt;0.001 mN/m) alkaline-surfactant-polymer (ASP) floods, LTP flooding uses a low concentration surfactant to moderately reduce the IFT (&amp;gt;0.01 mN/m). The objective of this research is to evaluate the performance of LTP floods as a function of IFT for a viscous oil in a 2D sandpack. Over 20 nonionic surfactants/cosolvents were tested. A series of sandpack flooding experiments were conducted in a custom-designed 2D visualization cell. The results show that short-hydrophobic surfactants 2EH-xPO-yEO can reduce the IFT to as low as 0.05 dyne/cm. Flooding experiments were performed in sandpacks with and without connate water saturation. The sandpack was water-wet for the experiments with connate water. For the experiments without connate water, the sandpack was oil-wet. A base-case secondary polymer flood (without any surfactant) with a viscosity ratio (µo/µp) of 10 showed a stable displacement and an oil recovery of 82% at the first pore volume injected (PVI). An LTP flood with an IFT of 0.1 dyne/cm also had a stable displacement front, but a higher oil recovery at 1 PVI [90% original oil in place (OOIP)]. Further reduction in IFT to 0.05 dyne/cm resulted in an unstable displacement and a lower recovery of 65% OOIP. For the experiments without connate water saturation, sandpack was oil-wet; the base-case polymer flood at a viscosity ratio of 10 showed severe fingering and a low oil recovery at 1 PVI (58% OOIP). Adding surfactants did not improve the oil recovery in oil-wet sandpacks.

Discussion on the limit recovery factor of carbon dioxide flooding in a permanent sequestration scenario

Based on practices of CO2 flooding tests in China and abroad, the recovery factor of carbon dioxide capture, utilization in displacing oil and storage (CCUS-EOR) in permanent sequestration scenario has been investigated in this work. Under the background of carbon neutrality, carbon dioxide injection into geological bodies should pursue the goal of permanent sequestration for effective carbon emission reduction. Hence, CCUS-EOR is an ultimate development method for oil reservoirs to maximize oil recovery. The limit recovery factor of CCUS-EOR development mode is put forward, the connotation differences between it and ultimate recovery factor and economically reasonable recovery factor are clarified. It is concluded that limit recovery factor is achievable with mature supporting technical base for the whole process of CCUS-EOR. Based on statistics of practical data of CO2 flooding projects in China and abroad such as North H79 block CO2 flooding pilot test at small well spacing in Jilin Oilfield etc., the empirical relationship between the oil recovery factor of miscible CO2 flooding and cumulative CO2 volume injected is obtained by regression. Combined with the concept of “oil production rate multiplier of gas flooding, a reservoir engineering method calculating CO2 flooding recovery factor under any miscible degree is established by derivation. It is found that when the cumulative CO2 volume injected is 1.5 times the hydrocarbon pore volume (HCPV), the relative deviation and the absolute difference between the recovery percentage and the limit recovery factor are less than 5% and less than 2.0 percentage points respectively. The limit recovery factor of CCUS-EOR can only be approached by large pore volume (PV) injection based on the technology of expanding swept volume. It needs to be realized from three aspects: large PV injection scheme design, enhancing miscibility degree and continuously expanding swept volume of injected CO2.

Effect of high-multiple water injection on rock pore structure and oil displacement efficiency

Experimental methods, including mercury pressure, nuclear magnetic resonance (NMR) and core (water-oil) displacement, are used to examine the effects of high-multiple water injection (i.e. water injection with high injected pore volume) on rock properties, pore structure and oil displacement efficiency of an oilfield in the western South China Sea. The results show an increase in the permeability of rocks along with particle migration, an increase in the pore volume and the average pore throat radius, and enhanced heterogeneity after high-multiple water injection. Compared with normal water injection methods, a high-multiple water injection is more effective in improving the oil displacement efficiency. The degree of recovery increases faster in the early stage due to the expansion of the swept area, and the transition from oil-wet to water-wet. The degree of recovery increases less in the late stage due to various factors, including the enhancement of heterogeneity in the rocks. Considering both the economic aspect and the production limit of water flooding, it is recommended to adopt other technologies to further enhance oil recovery after 300 PV water injection.

Improvement of oil recovery factor in tight reservoirs: A laboratory approach based on carbon dioxide enhanced oil recovery methods

Production from unconventional oil reservoirs has always been a critical issue for the oil industry. In this regard, we implemented a set of experimental scenarios containing CO2/N2 cyclic injection, the foams generated by nitrogen and carbon dioxide, cyclic carbon dioxide injection, and a combined effect of carbon dioxide and surfactant enhanced oil recovery methods. As water injection has reached a plateau around two pore volume injection, we continued the tests from two pore volume injection for different scenarios. It was observed that CO2/N2-foam has the highest oil recovery factor of 34.9%; however, CO2-foam, regarding more feasibility than N2, witnessed the highest oil recovery factor after CO2/N2-foam. On the other hand, the incremental oil recovery factor for surfactant flooding, carbonated water flooding, and carbonated water with surfactant flooding is measured at 4.9, 8.5, and 10.6%, respectively.

Effect of oil chemistry on the performance of low-salinity waterflooding in carbonates: An integrated experimental approach

Chemical enhanced oil recovery (cEOR) relies on the interactions between surface-active components (SACs) of the oil-in-place and injected chemicals to induce favorable physico-chemical changes. This study investigates the effect of oil chemistry on the performance of chemically-tuned waterflooding (CTWF) in carbonate rocks. Coreflood experiments were performed at 90°C using four model oils, each containing a single SAC (acetic acid, decanoic acid, stearic acid or quinoline) to evaluate the effect of oil composition on oil recovery. Complementary characterization techniques including thermal gravimetric analysis (TGA), attenuated total reflectance (ATR-FTIR) and zeta potential (ζ) were used to understand the underlying rock-oil-brine interactions that take place during CTWF, including SAC adsorption to the rock surface, strength of adsorption, partitioning into the brine phase, and electrostatic interactions, respectively. Sessile drop contact angle measurements were also performed to quantify the wetting behavior of the different SACs. Results of this study show that oil chemistry plays a significant role in triggering different oil-brine-rock interactions. Characterization of those interactions is crucial to explain the discrepancies in oil recovery observed in the CTWF literature. In this study, differences in the underlying oil-brine-rock interactions translated into significant variation in oil recovery ranging between 8.9 and 43.9 % after one pore volume injected (PVI). ATR-FTIR results showed that in-situ soap generation was detected for oils with longer chain carboxylic acids, whereas no soaps were observed for oils that have acetic acid or quinoline. Combined with sessile-drop contact angle measurements, a relationship is observed between SAC partitioning into the brine phase and water-wetting behavior. Additionally, TGA measurements suggested that long chain carboxylic acids chemisorb to the rock surface, making wettability alteration to a less oil-wetting state during CTWF more challenging, whereas intermediate chain carboxylic acids only physisorb leading to a more pronounced wettability alteration to a less oil-wetting state, ultimately yielding the highest recovery of ∼49.9 %. Finally, TAN was found to be an insufficient oil descriptor, where oils with the same TAN yielded different CTWF effects. Hence, a more robust oil analysis is crucial for more accurate prediction and modeling of CTWF behavior.