Oil-wet Carbonate Reservoirs Research Articles

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.

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.

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.

Using magnesium oxide nanoparticles in a magnetic field to enhance oil production from oil-wet carbonate reservoirs

Enhanced oil production can maximise yield from depleted reservoirs, and in the face of dwindling global oil reserves can reduce the need for exploratory drilling during the transition away from fossil fuels. A hybrid technique, merging a magnetic field (MF) and magnesium oxide (MgO) nanoparticles (NPs), was investigated as a potential method of enhancing oil production from oil-wet carbonate reservoirs. The impact of this hybrid technique on rock wettability, zeta potential, and interfacial tension was also investigated. Displacement experiments were carried out on oil-wet Austin chalk – a laboratory carbonate rock analogue – using MgO NPs in deionized water (DW) and salt water (SW), in the presence of an MF up to 6000 G in strength. It was found that the addition of MgO NPs to DW before the spontaneous imbibition of the solution into initially oil-wet rock samples increased the recovery factor (RF, defined as the volume of oil recovered divided by the initial oil in place). For 0.005 wt% and 0.0025 wt% MgO NPs mixed in DW, the RF was 12.5% and 15.9% respectively. When DW was replaced with SW as the imbibing fluid, the RF increased by a further 0.7% of initial oil in place for the 0.0025 wt% MgO NPs. This additional increase in oil recovery was attributed to the presence of potential determining ions, which made the rock more water-wet. To avoid pore-clogging and thus the limited ingress of the solution into the rock, the NPs’ concentration was kept low. This hybrid technique is a cleaner alternative to conventional enhanced oil recovery techniques and will enable oil industries to produce oil more efficiently from existing reservoirs: when used in conjunction with Carbon Capture and Storage (CCS), this provides a useful short to medium-term option to support energy production during the transition to net zero.

Optimization of Low Salinity Water/Surfactant Flooding Design for Oil-Wet Carbonate Reservoirs by Introducing a Negative Salinity Gradient

Engineered water surfactant flooding (EWSF) is a novel EOR technique to reduce residual oil saturation; however, it becomes quite challenging to obtain Winsor Type III microemulsion and the lowest IFT under actual reservoir conditions if only low salinity water is used. The main objective of this study was to design a negative salinity gradient to optimize the performance of the hybrid method. Three corefloods were performed on carbonate outcrop samples. The injection sequence in the first test was conventional waterflooding followed by optimum engineered water injection (2900 ppm) and finally an EWSF stage. The second and third tests were conducted using a varying negative salinity gradient. Engineered water for this study was designed by 10 times dilution of Caspian Sea water and spiking with key active ions. A higher salinity gradient was used for the first negative salinity gradient test. A total of 4300 ppm brine with 1 wt% surfactant was injected as a pre-flush after waterflooding followed by a further reduced salinity brine (~1400 ppm). The second negative salinity gradient test consisted of three post-waterflooding injection stages with salinities of 4600, 3700, and 290 ppm, respectively. Up to 8% and 16% more incremental oil recovery after waterflooding was obtained in the second and third tests, respectively, as compared to the first test. The descending order of brine salinity helped to create an optimum salinity environment for the surfactant despite surfactant adsorption. This study provided an optimum design for a successful LSSF test by adjusting the brine salinity and creating a negative salinity gradient during surfactant flooding. A higher reduction in residual oil saturation can be achieved by carefully designing an LSSF test, improving project economics.

Polymer enhanced foam for improving oil recovery in oil-wet carbonate reservoirs: A proof of concept and insights into the polymer-surfactant interactions

The feasibility of polymer enhanced foam (PEF) for enhanced oil recovery (EOR) in a strongly oil-wet and heterogeneous carbonate reservoir with medium temperature (131 °F) and high salinity was experimentally investigated. An Alkyl Poly-Glycoside (APG) surfactant was firstly selected because of its prominent foam behavior in oil-wet carbonates. The effect of polymer type, flow rate and brine composition on foam strength and stability were systematically investigated, aiming to understand how the interactions between polymer and surfactant could influence the transport behavior and performance of PEF in porous media. It was found that, with either an associative polymer or a nonionic polymer (PAM), the foam strength and foam stability could be largely enhanced, both in the absence and in the presence of oil. A significant improvement in oil recovery efficiency was obtained for PEF with an associative polymer, approximately 5% higher than that achieved for conventional polymer-free foam. The PEF behavior is intimately dependent on the interactions between the polymer and the surfactant. It is hypothesized that the increased foam strength by adding polymer at oil-wet conditions may be resulted from an increase of aqueous phase viscosity, the wettability alteration from oil-wet to less oil-wet, the generation of a highly viscoelastic film and (or) the creation of a more stable pseudo-emulsion film. This study provides a robust approach for PEF mobility control and reservoir conformance in oil-wet and heterogeneous carbonate reservoir under analogous reservoir conditions.

Enhanced oil recovery through synergy of the interfacial mechanisms by low salinity water alternating carbon dioxide injection

During this study, a comprehensive investigation of low salinity water alternating CO2 injection was performed for enhanced oil recovery in oil-wet carbonate reservoirs. A synergy of interfacial mechanisms such as IFT, wettability alteration, CO2 solubility, oil swelling, water shielding effect, and rock dissolution was considered in two and three-phase systems. Results showed that the monovalent ions, such as NaCl or KCl, inhibit the dissolution of carbon dioxide in brine in excess of divalent salt solutions, e.g. CaCl2 or MgCl2 due to the salting-out effect. In addition, more water shielding effect was observed in low salinity formation water than it in low salinity seawater. The significant change in the reservoir wettability of oil/brine/CO2 system compared to oil/brine referred to the CO2 solubility in brine which could cause stronger carbonated water in the reservoir. Consequently, the low salinity alternating CO2 injection overpowers the late-production problem that occurred commonly in conventional WAG injection.

Imidazolium based ionic liquids for enhanced oil recovery on the carbonate reservoir

Improving the oil recovery by changing the wettability using chemicals often possess huge challenges in the harsh oil-wet carbonate reservoirs, such as chemical instability, high retention, lack of deliverability in the deep reservoir, etc. In this study, we investigated the adsorptive behavior of imidazolium-based ionic liquids (ILs) on the carbonate reservoir, and also evaluated their performance in the oil recovery using the high temperature and high pressure coreflood setup. The measured adsorption values are well within the limit of field requirements. In which, the ILs with longer alkyl chains had shown less adsorption than the shorter ones. Next, in the coreflood oil recovery studies, the injection of ILs after waterflooding increased the oil recovery by 12–26% additionally. As expected, the lengthier alkyl chain containing ILs work more effectively than the shorter chain ones. For a case of reference, we also studied a few conventional surfactants (anionic, cationic, nonionic, and zwitterionic). We also extracted the unsteady state two-phase relative permeability curves of the SW and ILs flooding coreflood experiments to understand the flow characteristics of oil and water while injecting SW, and ILs. It was observed that the ILs improved the oils’ flowability, kro, and reduced the water’s mobility, krw. All these experiments were performed at the Saudi Arabian reservoir conditions of 100 °C, and at 4500 psi confining pressure, and at high salinity (TDS = 240, 000 ppm). In addition, we also demonstrated the wettability and interfacial tension (IFT) measurements in order to analyze the oil recovery mechanism. It was noted that both the ILs and surfactants alter the rock wettability from strongly oil-wet into intermediate-wet, while in the IFT measurements, the surfactants outperformed the ILs. Hence, it can be conceded that the oil recovery with ILs was dominated by the wettability modification, and for the surfactants, it was the combined effect of both wettability alteration and interfacial tension reduction. The use of dilute concentration of ILs (10–500 ppm) can be considered as the most profitable, and the best alternative over the costlier surfactant flooding.

Experimental study of electrical heating to enhance oil production from oil-wet carbonate reservoirs

New approaches for enhanced oil recovery (EOR) with a reduced environmental footprint are required to improve recovery from mature oil fields, and when combined with carbon capture and storage (CCS) can provide useful options for resource maximisation during the net zero transition. Electrical heating is investigated as a potential EOR method in carbonate reservoirs. Samples were placed in an apparatus surrounded by a wire coil across which different DC (direct current) voltages were applied. Monitoring the imbibition of both deionized water (DW) and seawater (SW) into initially oil-wet Austin chalk showed that water imbibed into the rock faster when heated in the presence of a magnetic field. This was associated with a reduction in the water–air contact angle over time measured on the external surface of the sample. Without heating, the contact angle reduced from 127° approaching water-wet conditions, 90°, in 52 min, while in the presence of heating with 3 V, 6 V, and 9 V applied across a sample 17 mm in length, the time required to reach the same contact angle was only 47, 38 and 26 min, respectively, while a further reduction in contact angle was witnessed with SW. The ultimate recovery factor (RF) for an initially oil-wet sample imbibed by DW was 13% while by seawater (SW) the recorded RF was 26% in the presence of an electrical heating compared with 2.8% for DW and 11% for SW without heating. We propose heating as an effective way to improve oil recovery, enhancing capillary-driven natural water influx, and observe that renewable-powered heating for EOR with CCS may be one option to improve recovery from mature oil fields with low environmental footprint.

Surfactant enhanced imbibition in carbonate reservoirs: Effect of IFT reduction and surfactant partitioning

A majority of carbonate reservoirs are preferably oil-wet or intermediate wet. Spontaneous imbibition represents an important mechanism to enhance oil production. Targeting an oil-wet carbonate reservoir with high temperature and high salinity, several surfactant formulations were investigated to improve oil production by imbibition, focusing on the capacity in interfacial tension (IFT) reduction and surfactant partitioning in water and oil phases in addition to dominant wettability alteration effect. Oil production potentials using different surfactants were evaluated by spontaneous imbibition in Amott cells at 95 ​°C. A base case imbibition test was conducted using a high salinity water with IFT value of 15.2 ​mN/m and an oil-wet carbonate core, and the oil production was 6.4% of oil originally saturated in core. Reducing the oil-water IFT to 10° ​mN/m magnitude achieved 4% incremental oil production beyond base case. When the IFT was further reduced to 10 −1 ​mN/m magnitude, the incremental oil production reached 10%. For the case of water-wet core and at the same IFT range, the incremental oil production was 13%. When the IFT was reduced to 10 −2 ​mN/m, the incremental oil production was up to 17% for the tests using oil-wet cores, and up to 23% for the water-wet counterpart. When further reducing the IFT to ultra-low magnitude of 10 −3 ​mN/m, the oil production was close to that using the imbibition agents with IFT of 10 −2 ​mN/m magnitude. For surfactants with no obvious wettability alteration capacity, those surfactants with higher molecular fraction in oil phase and higher adsorption on rock surfaces could remove more oil from the pore wall, and yielded higher imbibition efficiency. This work systematically investigated the major effects of surfactant on oil mobilization during imbibition process, which can help for better understanding of chemical imbibition in carbonates. The findings will shed light on the selection of high performance imbibition agents for carbonate reservoirs.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (>50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

Improving the stability of nanofluids via surface-modified titanium dioxide nanoparticles for wettability alteration of oil-wet carbonate reservoirs

The main challenge of the application of nanofluids for enhanced oil recovery (EOR) in oil-wet carbonate reservoirs is maintaining their stability under high-temperature and high-salinity which is normally seen in reservoir conditions. In this work, surface-modified TiO2 nanoparticles were synthesized by N-(2-Aminoethyl)−3-Aminopropyltrimethoxysilane (AEAPTMS) as a coupling agent for surface modification of nanoparticles. Zeta potential and dynamic light scattering analyses were used to evaluate the stability of the prepared nanofluids. Results indicated that nanofluids had high stability in 90 °C and 20 wt% salinity. The influence of nanofluids on wettability alteration of carbonate rocks was studied by measuring the contact angle value. Untreated rock samples were strongly oil-wet, with water advancing and receding contact angles of 165.1° and 166.2°, respectively. After treatment with 3wt% concentration of surface-modified TiO2 nanoparticles, the rock plate wettability changed to a water-wet state, with water advancing and receding contact angles of 37.6° and 48.2°, respectively. Suggested surface-modified TiO2 nanoparticles were more effective in wettability alteration of the rock surfaces compared to the un-modified TiO2 nanoparticles. Furthermore, higher concentration of nanoparticles, higher the ability of the nanoparticles on changing the rock wettability.

Modeling of low salinity waterflooding in carbonates: Effect of rock wettability and organic acid distribution

Carbonate reservoirs hold a substantial amount of our existing oil reserves. However, waterflood recovery from these reservoirs is often low due to their oil-wet nature. Recent studies have shown that oil recovery from oil-wet carbonate reservoirs can be increased by wettability alteration using low salinity brines having carefully modified ionic compositions. In this study, we developed a multiphase, multicomponent, finite-difference reservoir simulator and incorporated an improved mechanistic model to model low salinity waterflood in carbonates. The model considers key geochemical reactions relevant to low salinity waterflooding as reported by many authors recently. However, our modeling approach differs in two ways. Firstly, our model assumes that geochemical reactions of injected brines with the rock take place only on water-wet surfaces of these rocks and at the three-phase contact line; compared to other existing models that consider reactions to occur on the entire rock surface for oil-wet rocks. Secondly, previous models consider organic acids as a single species. In reality, oil is likely to have a mixture of different organic acids of different polarity, chain length, etc. In our model, we consider the oil to have a mixture of different organic acids and studied its impact on wettability alteration and oil recovery. Using this model, single phase and oil recovery experiments reported in the literature were modeled. The effect of rock wettability on geochemical reactions of low salinity brines with carbonate rocks was studied. Similarly, the effect of organic acid distribution on wettability alteration and oil recovery was investigated. Our simulation results showed that the extent of reaction of low salinity brines with carbonate rocks decreased as the rock became more oil-wet due to a decrease in reactive surface area. For example, less delay in effluent sulfate ions was observed in case of oil-wet rocks. The water-wet regions grew as a result of wettability alteration at the three-phase contact line. The initial wettability, extent of wettability alteration, and oil recovery profiles were dependent on the organic acid distribution. Furthermore, the inclusion of only key geochemical reactions (dolomitization, sulfate adsorption, and anhydrite dissolution/precipitation) were found to be reasonable for modeling various experiments reported in the literature. The proposed model will help in improving our understanding of mechanisms responsible for wettability alteration.

Effects of ultrasonic waves on water imbibition into oil-wet carbonate reservoirs (a case study)

In this study, imbibition tests with and without ultrasonic radiation were performed on limestone samples obtained from the Asmari formation, which is the main Iranian oil reservoirs. The test results have shown a significant increase in the oil recovery with ultrasonic radiation. Reducing the interfacial tension (IFT) and thus reducing the capillary holding force of oil is considered a possible mechanism for increasing oil recovery from oil-wet rock. The capillary pressure curve shows that a relatively large increase in the oil recovery from oil-wet samples will occur if the IFT decreases and the gravity force becomes a dominant force.

Surfactant-induced wettability reversal on oil-wet calcite surfaces: Experimentation and molecular dynamics simulations with scaled-charges

HypothesisSurfactant flooding is the leading approach for reversing the wettability of oil-wet carbonate reservoirs, which is critical for the recovery of the remaining oil. Combination of molecular dynamics (MD) simulations with experiments on simplified model systems can uncover the molecular mechanisms of wettability reversal and identify key molecular properties for systematic design of new, effective chemical formulations for the enhanced oil recovery. Experiments/SimulationsWettability reversal by a series of surfactant solutions was studied experimentally using contact angle measurements on aged calcite chips, and a novel MD simulation methodology with scaled-charges that provides superior description of the ionic interactions in aqueous solutions. FindingsThe MD simulation results were in excellent agreement with the experiments. Cationic surfactants were the most effective in reversing the calcite wettability, resulting in complete detachment of the oil from the surface. Some nonionic surfactants also altered the wettability, but to a lesser degree, while the amphoteric and anionic surfactants had no effect. From the tested cationic surfactants, the double-tailed one was the least effective, but the experiments were inconclusive due to its poor solubility. Contributions of specific interactions to the wettability reversal process and implications for the design and optimization of surfactants for the enhanced oil recovery are discussed.

Carbon nanodots for enhanced oil recovery in carbonate reservoirs

Enhanced oil recovery (EOR) operations in oil-wet carbonate reservoirs face enormous challenges such as long-term chemical and thermal stability issues, high retention and adsorption, diffusion, and, accordingly, an inability to reach deep into the reservoir. This study investigates the EOR potential of Carbon nanodots (CNDs) in coreflood experiments using both outcrop and reservoir carbonate samples. CNDs have excellent colloidal stability and mobility in the harsh carbonate reservoir environment. We also compared its performance against an in-house Gemini surfactant (GS8) of excellent surfactancy properties. Experiments were performed at the ”typical” Saudi Arabian reservoir conditions.We tested three flooding patterns using different rock permeabilities and additive concentrations in the SW. Based on the results, the added oil recovery with CNDs and GS8 ranged from 3%–23% and 6%–22%, respectively. At the same dilute concentration, CNDs are more effective than GS8 in increasing oil recovery. X-ray coreflood experiments provided a real-time 1-D saturation profile. It allowed gauging the efficacy of each additive in situ while tracking the oil and water saturation in and recovery from the carbonate samples. The saturation profiles were compared qualitatively against the oil recovery data from these experiments. Unsteady state, two-phase relative permeability curves of the X-ray coreflood experiments revealed the flow characteristics of oil and water during the injection of different fluids. Both CNDs and GS8 increased the oil’s relative permeability, kro and reduced the water’s relative permeability, krw.Overall, CNDs proved highly efficient, economical, and more scalable than a leading surfactant candidate. CNDs are based on a simple, single-pot synthesis process and have a proven-stability and mobility in the field. And in dilute concentrations (10–200 ppm), it alters the dynamic wettability of the carbonate reservoir favorably. Potentially, these can boost the oil recovery at depths (from the injector) that are unreachable by the conventional surfactants.

Enhanced oil recovery by spontaneous imbibition of imidazolium based ionic liquids on the carbonate reservoir

Wettability alteration plays an important role in the enhanced oil recovery (EOR), particularly for the oil-wet carbonate reservoir in harsh environments. It is essential to alter the native oil-wet characteristics of the rock matrix into water-wet or intermediate-wet in an attempt to achieve the favorable EOR process. The rate of water imbibition can be greatly improved by altering the rock wettability and by reducing oil–water interfacial tension. This can be achieved by using smart water, surfactants, oilfield chemicals, functionalized nanoparticles, or a combination of these to enhance water imbibition and oil displacement. In this study, a suite of spontaneous imbibition tests was run and investigated the efficacy of eco-friendly imidazolium-based ionic liquids (ILs) on the oil-wet carbonate sample and evaluated their effectiveness for the enhanced oil recovery with the minimal concentration of ILs (≤500 ppm). In this, we have studied the various affecting parameters including; type of ILs, ILs concentration (0–500 ppm), aging time (0–8 weeks), and rock permeability (45 and 250 mD). Subsequently, two conventionally used surfactants (SDS and CTAB) were also screened for the same study in order to set the reference case. All these experiments were performed on the Indiana limestone core samples, and experimental condition was set as high temperature (100 °C) and high brine salinity (TDS: 240, 000 ppm) in order to represent the typical Saudi Arabian reservoir condition. Overall, it was observed that a maximum of 34% increment of oil recovery was recorded for IL case over the seawater. Whereas only 11% of increased recovery was achieved with the use of conventional surfactants than the seawater. It is also noted that the longer chain containing ILs had shown better recovery (34%) than the shorter chain containing ILs (27%). Furthermore, NMR T2 relaxation distribution and NMR T2D responses were acquired for the same study. This helps to estimate the rate of water invasion and oil recovery both qualitatively and quantitatively. NMR measurements confirm that seawater was ineffective in all the pores, however a very little recovery was contributed from the macropores. At the same time, ILs showed almost double the recovery compared to seawater, and all types of pores (micro-, meso, and macropores) contributed to the recovery. This suggests that ILs diffused in all type of pores due to their greater diffusiophoresis tendency than the seawater case. NMR T2D measurements correlated well with the gravimetric Amott cell imbibition test results in regards to oil and brine saturations and recovery at different stages of the imbibition process. Overall, this can be concluded that ILs are potentially strong EOR agent, which has the capability to increase the oil recovery at harsh reservoir conditions and it is cost-effective and more economically viable when compared to other conventional chemicals.

Experiments and numerical simulations of chemical enhanced oil recovery in fractured carbonate rocks

Secondary oil recovery from naturally fractured, oil wet carbonate reservoirs is challenging due to high permeability fractures and unfavorable capillary forces. A series of new tertiary surfactant coreflood experiments in fractured oil wet limestone cores were performed in which surfactants lowered the IFT and formed viscous microemulsions upon mixing with crude oil and brine. The viscous microemulsions cause favorable transverse pressure gradients that result in increased oil recovery. The effects of surfactant slug size, salinity and injection rate were investigated experimentally. In all cases, the injected surfactant solutions recovered significantly more oil than waterflooding. Numerical simulations were used to interpret the experimental results. The experimental oil recovery and pressure drop data were matched by reducing the fluid mobility in the fracture. A new experiment verified that a viscous phase formed in the fracture, which resulted in a significant improvement in oil recovery.