Oil-wet Carbonate Research Articles

Dynamic Adsorption and Oil Recovery of Nanosilica on Carbonate Rock.

Numerous studies have investigated the use of nanosilica particles for enhanced oil recovery (EOR). Many of these studies focused on experiments involving LHP (lipophobic and hydrophilic polysilicones) and HLP (hydrophobic and lipophilic polysilicones) in water-wet sandstones and oil-wet carbonate rocks. This paper's gap investigates comparing LHP and HLP nanosilica particles in enhancing oil recovery in water-wet and neutral-wet carbonate rocks. Additionally, the effects of LHP and HLP adsorption during injection and their influence on oil recovery have not yet been extensively investigated. This study used Sumatran crude oil from Indonesia, and to support the objectives of this study, several analyses were conducted, including measurements of rock wettability, interfacial tension, fluid stability, zeta potential, UV-vis spectrophotometric adsorption, and coreflood injection as the main experiment under different scenarios. The findings demonstrate that the oil recovery enhancement is influenced by the type of nanosilica used. Specifically, LHP nanosilica exhibited higher oil recovery in neutral-wet carbonate rocks, about 9.78-44.44%, while HLP nanosilica showed better performance in water-wet carbonate rocks in the range of 4.11-41.01% in different injection scenarios. Moreover, a directly proportional relationship was observed between the adsorption of LHP and HLP nanosilica on the rock and fluid and oil recovery, where increased adsorption corresponded to higher oil recovery for each injection scenario with the respective type of nanosilica about 0.06-0.15 mg/g. These results provide valuable insights into selecting the appropriate nanosilica and initial wettability conditions in EOR applications.

CO2-foam flood with wettability alteration for oil-wet carbonate reservoirs

Carbon dioxide (CO2) flooding in carbonate reservoirs often suffers from poor sweep efficiency, attributed to unfavorable mobility ratio, gravity segregation, and reservoir heterogeneity. CO2-foam injection is a promising strategy to control CO2 mobility. The stability of CO2-foam is affected by reservoir wettability. This study aims to systematically investigate the effectiveness of CO2-foam flood coupled with wettability alteration in an initially oil-wet carbonate rock at a pressure below the minimum miscibility pressure. Three types of surfactants, including a nonionic surfactant Soloterra 843, a cationic surfactant CETAC-30, and a zwitterionic surfactant LMDO, were evaluated as potential foaming agents. Contact angle tests were conducted to assess the wettability alteration capability of these surfactants. Bulk foam stability tests and foam rheology tests were conducted under reservoir conditions. Finally, foam core flood experiments were performed using oil-wet carbonate core samples. Results from contact angle experiments indicated that only CETAC-30 was effective at altering rock wettability from oil-wet to water-wet by removing the negatively charged organic acid components from the rock surface. Foam stability and rheological tests revealed that LMDO exhibited highly stable CO2-foam in the absence of crude oil. However, the presence of crude oil adversely affected CO2-foam stability for all the surfactants. Core flooding experiments demonstrated that injecting wettability alteration surfactant, CETAC-30, in form of foam could not only alter the wettability of rocks, but also enhance the foam strength. Continuous gas injection (without foam) increased oil recovery by 14.4 % due to the near-miscibility of CO2 and oil. Both CETAC-30 and LMDO surfactants increased the oil recovery by about 35 % after waterflood, but the wettability altering surfactant showed the highest mobility reduction factor (MRF). These findings provide valuable insights into the complex interplay between near-miscibility, wettability alteration and foam strength in carbonate reservoirs, offering a basis for optimizing CO2-foam flooding strategies for enhanced oil recovery and carbon sequestration.

A novel hybrid enhanced oil recovery technique to enhance oil production from oil-wet carbonate reservoirs by combining electrical heating with nanofluid flooding

Enhanced Oil Recovery provides a promising technique to maximise fossil fuel recovery from existing resources, and when used in conjunction with Carbon Capture and Storage/Utilisation provides a way to support a transition to alternative cleaner fuels. A hybrid Enhanced Oil Recovery method by a combination of electrical heating and nanofluid flooding was applied to oil-wet carbonate reservoirs and assessed in terms of the oil production, zeta potential, contact angle, pellet compaction, interfacial tension, and pH values. The hybrid technique consisted of a combination of direct current (up to 30 V) and iron oxide (Fe2O3) or magnesium oxide (MgO) nanofluids. Both nanofluids were injected into oil-wet Austin chalk – our laboratory model of an oil-wet carbonate reservoir – and then electrical heating was started, or vice versa. Introducing electrical heating first increased oil recovery by up to 27% in seawater compared to 16% in deionised water. When Fe2O3 nanofluid was injected, oil recovery further increased to 32% in seawater and 24% in deionised water. The contact angle and zeta potential decreased from 124° to 36° and from −24.4 to −23.7 mV, respectively, when nanofluid was injected in seawater, leading to better nanofluid stability and penetration into the carbonate rock as shown by increased pellet porosity from 6.6% to 14.8%. Moreover, it was found that the interfacial tension was reduced from 72 to 32.7 mN/m in the pre-magnetised samples with Fe2O3 NPs injection compared to 33.2 mN/m in the samples with MgO injection. It was found from our experiments that the effect of the generated electricity on the surface charge was of a temporary nature as the zeta potential of the rock returned to its original value as soon as the power was disconnected. The mechanism underlying the hybrid Enhanced Oil Recovery EOR technique from the laboratory findings was found to be based on electrowetting and nanofluid adsorption. Results indicate that the technique is promising for further improving oil recovery and securing energy supply during the transition to net zero.

Effect of ethylene oxide groups on calcite wettability reversal by nonionic surfactants: An experimental and molecular dynamics simulation investigation

HypothesisEthoxylated nonionic surfactants are promising candidates for enhanced oil recovery (EOR) from oil-wet carbonate reservoirs due to their ability to reverse the mineral wettability. The wettability-reversal efficiency increases with the number of the ethoxy (EO) groups in the surfactant molecule. MethodologyContact angle measurements, scanning electron microscopy (SEM) and molecular dynamics (MD) simulations were combined to investigate the wettability reversal of an oil-wet calcite by three ethoxylated nonionic surfactants with 1, 4 and 8 EO groups, respectively, to directly probe the role of the EO groups and to uncover the molecular mechanism responsible for the wettability reversal. FindingsBoth experiments and simulations consistently show a clear correlation between the number of EO groups and the wettability reversal efficiency of the surfactants, whereby the higher number of EO groups results in greater degree of wettability reversal. This is due to 1) the more hydrophilic surfactant headgroup weakening the carboxylate interactions with the surface by expanding the surface-adjacent water layer, and 2) the physically larger surfactant molecule attracting the carboxylates more strongly, thus aiding in their removal from the surface.

The effect of matrix-fracture permeability contrast on hydrocarbon foam performance in oil-wet carbonate

The effect of matrix-fracture permeability contrast on hydrocarbon foam performance in oil-wet carbonate

Methane foam performance evaluation in fractured oil-wet carbonate systems at elevated pressure and temperature conditions

This study investigates the potential of foam flooding for enhanced oil recovery in oil-wet fractured systems under reservoir conditions. Two surfactants with distinct ionic properties were employed in combination with methane to generate foam via simultaneous injection into propped fractures, aiming to optimize the diversion of gas from fractures to the matrix for improved oil recovery. Core flooding experiments demonstrated the critical roles of total injection rate and foam quality in controlling foam performance. Increasing the total injection rate from 1 to 3 cm³/min enhanced foam generation rates and foam lamella stability, facilitating better interactions between fractures and the matrix. However, beyond an injection rate of 4 cm³/min, there was a decline in apparent viscosity and mobility reduction factor. Foam strength was directly proportional to higher foam quality within the 50 to 80% range, but beyond 85% foam quality, fluctuations in pressure drop signaled the formation of weaker, less stable foams. Micro-scale experiments validated these macroscopic findings, revealing that smaller bubbles were associated with higher flow rates and lower foam qualities. This research contributes valuable insights into both micro and macro-scale in-situ foam generation, which can inform the design and application of foam-based enhanced oil recovery methods in fractured reservoirs.

Experimental Evaluation of Foam-Assisted Gas Injection in Proppant-Packed Fractured Oil-Wet Carbonate

Experimental Evaluation of Foam-Assisted Gas Injection in Proppant-Packed Fractured Oil-Wet Carbonate

EVALUATION OF CONTINUOUS AND WATER ALTERNATING GAS (WAG) CO2 INJECTION ON X FIELD RECOVERY FACTOR

Indonesia is a country rich in natural resources. The wealth of Indonesia's natural resources is not only limited to agricultural and plantation products, but also from mineral and hydrocarbon mining or oil and gas. Indonesia's oil production has continued to decline in the last 10 years until the national consumption rate is much higher than national production. One of the causes of the decline in oil production in Indonesia is the condition of Indonesia's oil fields, which are currently mature fields. To overcome the problem of old fields that still have economic oil reserves, enhanced oil recovery (EOR) can be used. One of the EOR methods that can be used is the CO2 injection method using continuous and WAG injection schemes. The study was conducted in X field with oil-wet carbonate rock composition with waterdrive and fluid expansion driving mechanism. The basecase production scheme using 5 production wells produces a recovery factor of 34.3%, while continuous CO2 injection produces a recovery factor of 32%, and CO2-WAG produces a recovery factor of 42%. Continuous CO2 injection has the lowest recovery factor because early gas breaktrough occurs due to a large mobility ratio and causes gas fingering, hindering the oil production process. The most suitable injection method is CO2-WAG 1 cycle using a 1:1 ratio, CO2 injection volume of 6.661 MSCF/D, injection water volume of 37.4 MBBL/D with a recovery factor of 43.46%.

Impact of Injection Gas on Low-Tension Foam Process for EOR in Low-Permeability Oil-Wet Carbonates

Low-tension gas (LTG) flooding has been proven in lab-scale experiments to be a viable tertiary enhanced oil recovery (EOR) technique in low-permeability (~10 mD) oil-wet carbonates. Work carried out previously almost exclusively focused on water-wet cores. The application of LTG in oil-wet carbonates is investigated in this study along with the impact of a hydrocarbon (HC) mixture as the injection gas on oil–water microemulsion phase behavior. The optimum injection gas fraction (ratio of gas injection rate to total injection rate of gas and water) for the hydrocarbon gas mixture in oil-wet carbonates regarding the oil recovery rate was determined to be 60% as it resulted in around 50% residual oil in place (ROIP) recovery. It was shown that proper mobility control can be achieved under these conditions even in the absence of strong foam. The effect of HC gas dissolution in oil was clearly shown by replacing the injection HC gas with nitrogen under the same conditions. Furthermore, the importance of ultra-low interfacial tension (IFT) produced by the injection gas and surfactant slug is proven by comparing injection at sub-optimum salinity to injection at optimum salinity.

Synthesis of cost-effective Si-CQD for effective oil separation from core rock

Nanomaterials (NMs) based on carbon are suitable candidates for separating oil from core rock. Nowadays, the application of carbon-based NMs to enhanced oil recovery (EOR) is far less. The production of NMs based on carbon (water-wet) is of great importance due to the high recovery they create in reservoirs. The purpose of this study was to change the wettability of oil-wet (OW) carbonate rock (CR) towards water-wet (WW) conditions using cheap synthetic materials. In this regard, the effect of three quantum carbon dots (CQDs) on saltwaters has been used. The CQDs were synthesized by hydrothermal procedure and tetraethyl orthosilicate (TEOS) was used as the initial source of carbon. In this regard, Si-CQDs indicated great colloidal sustainability in saltwaters solutions. Therefore, to determine the morphological characteristics and structure of the synthesized NMs, Energy Dispersive X-ray (EDX), Scanning Electron Microscopy (SEM), and Fourier-transform infrared spectroscopy (FT-IR) were done. The stability of NMs was investigated using the zeta potential (ZP). The new compound showed acceptable results at a very low concentration of 100 ppm. The findings indicated that the nanofluid (100 ppm Si-CQDs + Seawater (SE)) reduced the interfacial tension value from 23.34 mN/m to 7 mN/m. Also, the results showed the solution of SE + 100 ppm Si-CQDs improved the oil recovery by 24 % and 23 %. Generally, this paper opens the door for the development of carbon-based NMs with the ability to absorb sediments in the porous media of the reservoir for the efficient separation of oil from core rock. Generally, our analysis supports the use of Si-CQDs as an efficient and economical additive for further oil recovery in carbonate reservoirs.

Performance evaluation of surface-modified silica nanoparticles for enhanced oil recovery in carbonate reservoirs

The purpose was to prepare a (3-glycidoxypropyl)-trimethoxysilane (GPTMS)-SiO2 nanofluid and analyze the effect of nanofluid injection on carbonate reservoirs. GPTMS-modified silica nanoparticles (SNPs) were investigated by Fourier transform infrared spectroscopy (FTIR) and elemental analysis. FTIR spectra of C-H stretching vibrations at 2950 cm−1, indicating silica surface modification with GPTMS, were observed when the GPTMS in the feed was greater than 0.7 mmol/g. Further, a stable nanofluid was obtained when the amount of grafted silane was close to 0.73 mmol/g, the theoretical maximum amount of grafted silanes. To evaluate the performance of surface-modified SNPs for enhanced oil recovery in carbonate reservoirs, wettability alteration tests comprising flotation test and contact angle measurements using powder and plug samples of carbonates, respectively, were performed with different SNP concentrations. Powder samples were successfully changed from oil-wet to water-wet, and the contact angle of the plug sample decreased by up to 62.8% as a result of the reaction of the nanofluid; however, it did not reduce interfacial tension (IFT) as effectively as IFT reducer additives. A coreflooding test was conducted to determine the effective parameters of the enhanced oil recovery with the GPTMS-nanofluid, such as SNP concentration, injection rate, and rock properties. The nanofluid injection increased oil recovery by approximately 20% compared to conventional waterflooding through incremental oil recovery, mainly attributed to wettability alteration. Therefore, we expect the nanofluid to dramatically increase the oil recovery in strongly oil-wet carbonate reservoirs under high-salinity conditions.

Systematic observations of enhanced oil recovery and associated changes at carbonate-brine and carbonate-petroleum interfaces

Enhanced oil recovery (EOR) from carbonates is obtained by injection of controlled ionic strength brines containing “active ions” (e.g., SO42−, Mg2+, Ca2+). It is generally believed that this occurs through the interaction of the active ions at the carbonate-brine interface (e.g., within a thin brine layer separating the petroleum and the carbonate phases). Here, in-situ observations show how one active ion, SO42−, alters behavior at the carbonate-petroleum interface. Displacement of petroleum from initially oil-wet carbonate rocks using brines with variable SO4 concentrations systematically changes oil recovery, in situ contact angles, and connectivity of the oil phase, confirming that the active ion alters interactions at the oil/brine/carbonate interface, as expected. Measurements of model calcite-fluid interfaces show that there is no measurable sorption of SO4 to carbonate-brine interfaces but reveals that the carbonate-petroleum interface is altered by previous exposure to SO4-containing brines. These results suggest that EOR in carbonates is controlled indirectly by active ions. We propose that this may be due to a reduced oleophilicity of the carbonate caused by chemical complexation between the active ion and petroleum’s acidic and basic functional groups. This mechanism explains how both anions and cations act as active ions for EOR in carbonates.

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.

Influence of carbon nanodots on the Carbonate/CO2/Brine wettability and CO2-Brine interfacial Tension: Implications for CO2 geo-storage

Understanding the interfacial and wettability phenomena of the CO2-brine and rock-CO2-brine system plays a key role in the geo-storage of CO2 and in their security containment. Carbon nanodots (CNDs) have been identified as a promising surface-active agent for altering the wettability from strongly oil-wet into water-wet in the carbonate reservoirs, thus it contributed for the oil recovery increment in the carbonate formations. However, no consideration was given to the application of CNDs for the enhancement of CO2 geological storage and containment security in the carbonate formations. In the current study, we assessed the impact of CNDs on the residual and structural trapping of CO2 in the carbonate reservoir. The contact angles (θ) of the CO2-brine-carbonate rock system were studied before and after the treatment of CNDs for both the clean and crude oil-aged samples. Subsequently, we also investigated the CO2-seawater interfacial tensions (IFT) with and without CNDs addition. All these measurements were performed as a function of CNDs concentration (0–1000 ppm), temperature (20–80 °C) and pressure (14.7–3000 psi). The results showed that the clean carbonate rock remained strongly water-wet before and after CNDs-treatment. The oil-wet carbonate sample was turned into CO2-wet at all investigated temperatures when the pressures increased to 1000 psi, however, it turns to be weakly water-wet upon treatment with CNDs at the highest pressure (3000 psi). Specifically, at 3000 psia and 20 °C, the contact angle of oil-wet carbonate reduced from 122° to 86° with the addition of CNDs at the increased concentration of 1000 ppm. Such wettability modifications in carbonate formations will enhance the efficacy of CO2 storage potential, and eventually, this will help to de-risk their security containment. The θ generally demonstrated a declining trend with the increase of CNDs concentration but it slightly increased with the rise in temperature and pressure. These results suggest that warmer reservoirs and increased storage depth could be unfavorable for CO2 storage in carbonate formations. Thus, the pre-injection of a minimal concentration of CNDs in the formation would improve CO2 storage effectively. Also, no significant change was observed in the CO2-seawater IFT in the presence of CNDs, which indicates that the capillary trapping of CO2 could be favorable due to their lower contact angle and high CO2-brine IFT as the most suitable condition to maintain the high capillarity. The study demonstrates that the highly stable, freely soluble, easy detectable, scalable, and economically viable CNDs has the potency to enhance the containment security of CO2 in carbonate formation.

Experimental investigation of wettability alteration of oil-wet carbonate surfaces using engineered polymer solutions: The effect of potential determining ions ([Mg2+/ SO42−], and [Ca2+/ SO42−] ratios)

Engineered water polymer flooding (EWPF) is a promising method to improve oil recovery in carbonate reservoirs holding more than half of the world's oil reserves. It involves combining engineered water (EW) and polymer flooding (PF) to modify rock wettability, reduce mobility ratio, promote polymer stability, and lower required polymer concentration. However, limited studies addressed the simultaneous effect of engineered water compositions (i.e. potential determining ions (PDIs)) on the viscosity of polymer and wettability alteration of various carbonate surfaces. Accordingly, this study aimed to investigate the effect of salinity, PDIs, and polymer functional groups (partially hydrolyzed polyacrylamide (HPAM), and acrylamide tertiary butyl sulfonic acid (ATBs)) on the wetting properties of calcite, chalk, and dolomite surfaces as well as the viscosity of solutions at static conditions. The experimental protocol included viscosity, contact angle (CA), pH, and static adsorption tests. Two combinations of PDIs were considered in the study: [Mg2+/SO42−], and [Ca2+/SO42−]. The results revealed that the polymer becomes more tolerant to the salinity as the sulfonation degree increases, given the same molecular weight. However, at a polymer concentration of 5000 ppm, the HPAM polymer showed higher viscosity than the ATBs-based polymers, as the formation brine (FB) was diluted to 100 folds (100DFB). The tendency of shifting the wettability of carbonate surfaces towards a more water-wet state using EW and EWP treatment solutions decreased in the following order: Chalk ≥ Calcite˃ Dolomite. The study also indicates that, the wettability alteration towards favorable condition is dependent on the initial wettability of the carbonate surface. The higher level of oil-wetness detected in aged dolomite, compared with calcite and chalk, resulted in less effectiveness of EWP for dolomites. However, the low polymer interaction with dolomite surfaces indicates a positive impact on reducing polymer consumption. Moreover, the HPAM polymer was more effective in altering the wettability of dolomite towards a water-wet state compared to the ATBs-based polymer. The overall results indicate that ATBs-based polymer is a potential candidate for optimizing the effectiveness of EWPF in carbonates.

Development of sulfate-based smart water for improving the oil recovery from the calcite formation: New insights from molecular simulation

Wettability plays a huge role in the process of oil displacements, particularly in highly complex oil-wet carbonate reservoirs. Recently, sulfate ions were witnessed to have a great potency to alter the wetting state of calcite. Though the role of sulfate ion studied extensively, still the mechanism of their wettability modification is yet to be fully understood. It is expected due to the complex surface chemistry of rock in the presence of monovalent and divalent ions. In this study, we constructed a rock-oil-brine model at a molecular level and run the simulation on the wettability dynamics with various ions. The most abundant surface structure of calcite {1014}, was considered for this atomistic simulations. The model oil consisted of n-heptane and 10% octanoate ion as a polar component and sulfate-based salts were used as smart water. Two distinct hydration layers were found on the calcite surface. The contact angle measurements were made to find the effectiveness of smart water solutions in altering the wettability of the surface. Monovalent cations were observed to form a strong electric-double-layer while the divalent cations were preferred to get distributed in the bulk; most of them were attached to polar oil ions removing them from the calcite surface thus changing the wettability.

Synergistic study of xanthan-gum based nano-composite on PELS anionic surfactant performance, and mechanism in porous media: Microfluidic & carbonate system

Rising global energy demand and decrease in world fossil fuels reserves draw attention toward production from trapped oil in the reservoirs. CEOR methods are proved and efficient methods which can be applied for increased oil recovery. In this research, the EOR potential of a novel nanocomposite and a developed surfactant was evaluated in the presence of various ions and the production enhancement mechanisms were studied using glass micromodel. Primary, the synergistic effect of the nanocomposite and the natural surfactant on Interfacial tension (IFT) reduction and wettability alteration was studied. After quantitative analysis and investigation of the various mechanisms, it was understood that the presence of the nanocomposite in the surfactant solution alters the wettability of an oil-wet carbonate surface to a water-wet one. Adding nano-composite to surfactant solution can improve the wettability alteration ability of the surfactant up to 60.02%. The adsorption tests revealed that combining the nanocomposite with surfactant solution can reduce surfactant adsorption by 18.99 %. The Zeta potential test was utilized to evaluate the stability of the solution. The zeta potential of the nano/surfactant solution was equal to −28 which illustrated a stable solution. In addition, the zeta potential measurements demonstrated the wettability alteration mechanism. After investigating the properties of the nano-surfactant solutions in the presence of different ions, optimum concentrations were determined and the mechanisms of the nano-chemical EOR method were visually investigated by injecting the desired solutions into the glass micromodel. Eventually, five different injection scenarios were designed for the core flood tests to evaluate the performance of each solution in the porous medium. The achieved final recovery for PELS, PELS/NaCl, and PELS/NaCl/NC solutions were 48.05%, 55.62%, and 60.38%, respectively and the Alternative injection scenario was the best injection plan.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Aqueous formate solution for enhanced water imbibition in oil recovery and carbon storage in carbonate reservoirs

This paper presents an experimental study of the injection of aqueous formate solution into oil-wet carbonate porous media at different formate concentrations and acidity levels. The research was motivated by the potential use of aqueous formate solution as a wettability modifier in enhanced oil recovery and/or a carbon carrier in geological carbon storage in carbonate reservoirs. However, the wettability alteration of carbonate rocks by formate has not been tested at elevated concentrations of formate or in any coreflood. The experimental program in this research consists of aqueous stability, wettability alteration, and three dynamic imbibition experiments with fractured carbonate cores with varying formate concentrations up to 30 wt% and initial pH between 6 and 7.With an excess amount of calcite powder, the 20 wt% formate solution in 15000 ppm NaCl brine showed essentially the same pH history as the base NaCl brine, where calcite dissolution caused the solution pH to increase to a stable value near 9. None of the samples studied in this research showed solid precipitation. Material balance of dynamic imbibition data indicated that the imbibition of formate into the matrix was most significant in coreflood #1, in which 30 wt% formate solution was injected into a fractured carbonate core. A large gradient in formate concentration between the fracture and the matrix likely caused the rapid mass transfer. Then, calcite dissolution and the resulting formate species caused wettability alteration to enhance water imbibition, which in turn expelled the oil in the matrix.The incremental oil recovery factor was 9.1 % for 30 wt% formate (pH = 7; coreflood #1), 2.9 % for 5 wt% formate (pH = 7; coreflood #2), and 7.0 % for 5 wt% formate + HCl (pH = 6; coreflood #3). A greater oil recovery factor resulted from a greater concentration of formate and a reduced pH. This is the first time corefloods were performed with aqueous formate solution at elevated concentrations up to 30 wt%.

Investigation of the Coupled Effect of IFT Reduction and Wettability Alteration for Oil Recovery: New Insights.

Interfacial tension (IFT) reduction and wettability alteration (WA) are both important enhanced oil recovery (EOR) mechanisms. In oil-wet formations, IFT reduction reduces the magnitude of negative capillary pressure, releasing trapped oil. WA changes the negative capillary pressure to positive conditions, helping the entrance of the aqueous phase, and the displacement of the oil phase. In most cases, IFT reduction and WA happen at the same time. However, studies regarding the coupled effect provided different, sometimes conflicting observations. It requires further study and better understanding. In our study, oil-aged Indiana limestone samples were chosen to represent oil-wet carbonate rocks. Static contact angle and spinning drop method were adopted for wettability assessment and IFT measurement, respectively. Spontaneous imbibition was adopted to reflect on the oil recovery mechanisms in different cases. The impact of IFT reduction, WA, and permeability on the coupled effect was discussed by choosing four pairs of comparison tests. Results showed that when the coupled effect took place, both a higher IFT value and a stronger WA performance resulted in faster and higher oil recoveries. The importance of IFT reduction was enhanced in the higher-permeability condition, while the importance of WA was enhanced in the lower-permeability condition.