Oil-wet Reservoirs Research Articles

An efficient method for imbibition in asphaltene-adsorbed tight oil-wet reservoirs

Spontaneous imbibition (SI) has been proposed as a crucial approach to enhance oil recovery in unconventional reservoirs. Previous research suggests that wettability alteration rather than oil-water interfacial tension (IFT) reduction is the key mechanism for imbibition oil recovery enhancement. However, our experimental results indicate that for asphaltene-adsorbed oil-wet surfaces it's challenging to substantially modulate wettability. In such oil-wet pores, the negative capillary force cannot function as an imbibition driving force, and hence, the method of altering wettability and maintaining the oil-water IFT at relatively high values to enhance imbibition efficiency is insufficiently applicable. When the capillary cannot work, reducing the IFT to ultra-low levels to induce the transformation of the imbibition pattern may be more effective for imbibition efficiency enhancement. In this paper, low-field nuclear magnetic resonance (NMR) was employed to monitor the SI process. The results suggested that for the asphaltene-adsorbed oil-wet tight sandstone, the surfactants combined system with ultra-low oil-water IFT possessed the highest oil recovery, followed by the medium-IFT systems and high-IFT systems. The spontaneous formation of emulsion was observed when the IFT value was reduced to the ultra-low level. Oil droplets can pass through the small pores easily since the deformability of oil is greatly enhanced. The ultra-low IFT system transforms the imbibition pattern from capillary force-driven to gravity-driven, and exhibits the highest oil utilization rate in micropores, mesopores, and macropores among all imbibition agent systems, thereby having the highest total oil recovery. Consequently, the imbibition-enhancing potential of the ultra-low IFT system is considerable and deserves more attention, especially for the oil-wet pores that can hardly be altered to the water-wet state.

Wettability evaluation of shale oil reservoirs and its impact on the post-fracturing shut-in duration of horizontal wells: a quantitative study for Ordos Basin, NW China

Shale oil development in Ordos Basin, China, primarily relies on the displacement of crude oil during the post-fracturing shut-in stage (PFSIS) of horizontal wells. Reservoir wettability significantly influences the shut-in duration and even the development approach. However, due to strong heterogeneity and super tight characteristics, the reservoir usually shows an mixed wettability, and it was usually hard to differentiate the wettability in different pore sizes. With this in mind, this study focuses on core samples from shale oil reservoir in the Longdong region of the Ordos basin to quantitatively analyze the reservoir wettability. Amott method combined with nuclear magnetic resonance is adopted in the paper to meed this end. And the optimal post-fracturing shut-in duration for Huachi and Heshui areas in the Longdong region are determined based on both wettability and field practice analysis as well as numerical simulations. Qualitative wettability evaluation reveals that the reservoir in the Longdong region is weakly oil-wet (oil-wet pores account for 58.9% and water-wet pores for 41.1%), and that larger pores are more water-wet, while smaller pores are more oil-wet. Field practice observes a noticeable two-stage decline in wellhead pressure, with pressure drop rates and water content decline rates following the order of neutral reservoir > weakly oil-wet reservoir > oil-wet reservoir during the post-fracturing shut-in stage. Numerical simulations indicate that the determination of the optimal post-fracturing shut-in duration for horizontal wells should consider reservoir properties, wettability, and injection volume. The final optimal shut-in durations for the Huachi and Heshui areas in the reservoir are determined to be 36 days and 43 days, respectively. Our study qualitatively distinguishes the wettability in different pores sizes and thus determines reasonable post-fracturing shut-in durations in different areas in Longdong region. The research has major implication for building a realistic method of wettability analysis in shale or tight oil reservoir.

Nuclear magnetic resonance experiments on the time-varying law of oil viscosity and wettability in high-multiple waterflooding sandstone cores

A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2 spectrum, and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance (NMR) experiments of high multiple waterflooding. A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores. The remaining oil viscosity in the core is positively correlated with the displacing water multiple. The remaining oil viscosity increases rapidly when the displacing water multiple is low, and increases slowly when the displacing water multiple is high. The variation of remaining oil viscosity is related to the reservoir heterogeneity. The stronger the reservoir homogeneity, the higher the content of heavy components in the remaining oil and the higher the viscosity. The reservoir wettability changes after water injection: the oil-wet reservoir changes into water-wet reservoir, while the water-wet reservoir becomes more hydrophilic; the degree of change enhances with the increase of displacing water multiple. There is a high correlation between the time-varying oil viscosity and the time-varying wettability, and the change of oil viscosity cannot be ignored. The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott (spontaneous imbibition) wettability index, which agrees more with the time-varying law of reservoir wettability.

Effect of nanomaterials functionality on the acidic crude oil: Wettability and oil recovery studies

Chemical enhanced oil recovery often involves the injection of chemicals, such as surfactants, polymers, nanoparticles, and macromolecules. These chemicals are to alter the rock-oil-water interactions and mobilize the oil towards the production well. However, they often pose considerable challenges in the harsh environment of the oil-wet reservoirs, such as chemical instability, and high retention/adsorption of chemicals in the near-wellbore. Herein, we investigated the effect of functionalized silica nanofluids on improving oil recovery in the carbonate reservoir as a function of the oil acidity. To do so, we synthesized two types of silica nanofluids functionalized with sulfonate and carboxylate groups. We used two crude oils with different total acid numbers (TAN) of 0.4 and 5.7 mg/KOH. All experiments were ran at 100 °C and salinity of 67–240 kppm to simulate the harsh reservoir conditions of the Saudi Arabia. Spontaneous imbibition oil recovery studies were conducted to assess their effects on oil recovery. Contact angle and interfacial tension were performed at different conditions to examine the oil recovery mechanism. Further, in order to corroborate the previous research and comprehend the principles underlying the oil recovery, we also examined the electrokinetic zeta potential in parallel. Also, to better understand how oil and nanofluid functional groups interact, we conducted a surface complexation model study. In addition, molecular simulation (density functional theory and molecular dynamics) are employed to gain atomistic insights on the implicated molecular interactions between nanosilica particles with calcite surface in seawater brine. DFT simulations predicted that both functionalized nanosilica can form thermodynamically stable complexes with a dry and hydrated calcite surface. Further, MD simulations reveal that a good amount of both functionalized nanosilica are interacting with calcite surface in the diffuse electric double layer of the calcite-brine interface. However, the carboxylated functionalized nanosilica particles interact with rock stronger than sulfonated ones. Further, the carboxylated nanosilica could form stable complexes with naphthenic acids mediated by calcium ions, which supports the synergy effect observed experimentally. The results shed light on much more complex mechanisms behind the oil recovery rather than the common peripheral understanding. This work provides a good insight into the applicability of nanofluids for enhanced oil recovery for further research and field trials.

Application of Electromagnetic Methods for Reservoir Monitoring with Emphasis on Carbon Capture, Utilization, and Storage

The Controlled-Source ElectroMagnetic (CSEM) method provides crucial information about reservoir fluids and their spatial distribution. Carbon dioxide (CO2) storage, enhanced oil recovery (EOR), geothermal exploration, and lithium exploration are ideal applications for the CSEM method. The versatility of CSEM permits its customization to specific reservoir objectives by selecting the appropriate components of a multi-component system. To effectively tailor the CSEM approach, it is essential to determine whether the primary target reservoir is resistive or conductive. This task is relatively straightforward in CO2 monitoring, where the injected fluid is resistive. However, for scenarios involving brine-saturated (water-wet) or oil-wet (carbon capture, utilization, and storage—CCUS) reservoirs, consideration must also be given to conductive reservoir components. The optimization of data acquisition before the survey involves analyzing target parameters and the sensitivity of multi-component CSEM. This optimization process typically includes on-site noise measurements and 3D anisotropic modeling. Based on our experience, subsequent surveys tend to proceed smoothly, yielding robust measurements that align with scientific objectives. Other critical aspects to be considered are using magnetotelluric (MT) measurements to define the overall background resistivities and integrating real-time quality assurance during data acquisition with 3D modeling. This integration allows the fine tuning of acquisition parameters such as acquisition time and necessary repeats. As a result, data can be examined in real-time to assess subsurface information content while the acquisition is ongoing. Consequently, high-quality data sets are usually obtained for subsequent processing and initial interpretation with minimal user intervention. The implementation of sensitivity analysis during the inversion process plays a pivotal role in ensuring that the acquired data accurately respond to the target reservoirs’ expected depth range. To elucidate these concepts, we present an illustrative example from a CO2 storage site in North Dakota, USA, wherein the long-offset transient electromagnetic method (LOTEM), a variation of the CSEM method, and the MT method were utilized. This example showcases how surface measurements attain appropriately upscaled log-scale sensitivity. Furthermore, the sensitivity of the CSEM and MT methods was examined in other case histories, where the target reservoirs exhibited conductive properties, such as those encountered in enhanced oil recovery (EOR), geothermal, and lithium exploration applications. The same equipment specifications were utilized for CSEM and MT surveys across all case studies.

Anionic-nonionic and nonionic mixed surfactant systems for oil displacement: Impact of ethoxylate chain lengths on the synergistic effect

Compound surfactant system has been extensively studied in enhanced oil recovery (EOR) as the synergistic effect of mixed surfactants can increase the density of surfactants distributed at the oil/water interface, enhancing the interfacial activity and decreasing the interfacial tension. The system can further increase the capillary number and enhance oil recovery for oil-wet reservoirs. Studying the interactions between surfactant molecules is of great significance to the enhancement of practical application performances. In this study, N, N-dihydroxyethyl alkyl amide (CDEA), and Alkylphenol polyoxyethylene carboxylate (APEC) with different EO numbers were mixed to prepare a binary compound oil displacement system. The influence of the EO number on the synergistic effect of the CDEA/APEC system and the EOR potential was measured by interfacial tension, nanomechanical tests and oil-displacement experiments. The results indicate a synergistic effect between CDEA and APEC due to the formation of hydrogen bonds between the hydroxyl groups of CDEA and the EO chains of APEC. An optimal synergistic effect in the system was obtained when the EO number was four. The CDEA/APEC-4 system exhibited an oil/water interfacial tension decrease to 10−2 mN/m at 75 °C and the oil recovery was 57.14 %, which was increased by 19.2 % compared to primary water flooding. However, a longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. Due to the flexibility of the EO chain, the increase in the EO number leads to the bending of APEC molecules. The longer EO chain length weakened the interaction forces between CDEA and APEC, which diminished the synergistic effect of the system, leading to an increase of the interfacial tension. The oil-displacement experiment revealed that the EO chains changed the oil recovery and injection pressure by affecting the interfacial tension of the mixed system. This study has significant implications for the formulation design and optimization of agents for oilfield development.

Integral Effects of Porosity, Permeability, and Wettability on Oil–Water Displacement in Low-Permeability Sandstone Reservoirs—Insights from X-ray CT-Monitored Core Flooding Experiments

Porosity, permeability, and wettability are crucial factors that affect the oil–water displacement process in reservoirs. Under subsurface conditions, the integral effects of these factors are extremely difficult to document. In this paper, waterflooding experiments were carried out using a core flooding system monitored with X-ray dual-energy CT. The mesoscale, three-dimensional characteristics of water displacing oil were obtained in real time. The integral effects of porosity, permeability, and wettability on the waterflooding in the low-permeability sandstone reservoirs were investigated. It was found that if the reservoir rock is water-wet, then the residual oil saturation decreases gradually with increasing porosity and permeability, showing an increasing waterflooding efficiency. On the contrary, if the reservoir rock is oil-wet, the residual oil saturation gradually increases with improving porosity and permeability, showing a decreasing waterflooding efficiency. The porosity, permeability, and wettability characteristics of reservoirs should be comprehensively evaluated before adopting technical countermeasures of waterflooding or wettability modification during oilfield development. If the porosity and permeability of the reservoir are high, water-wet reservoirs can be directly developed with waterflooding. However, it is better to make wettability modifications first before the waterflooding for oil-wet reservoirs. If the porosity and permeability of the reservoir are poor, direct waterflooding development has a better effect on oil-wet reservoirs compared with the water-wet reservoirs.

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.

Experimental measurements and response analysis of resistivity of reservoirs with complex wettability: A case study of Yan’an Formation, Ordos Basin, China

Resistivity logs are commonly used to distinguish oil and water reservoirs. However, the complex hydrocarbon accumulation pattern in the study area leads to complex wettability, which significantly affects the resistivity as well as the density and neutron logs and causes difficulties in fluid-type identification. To understand the resistivity characteristics and accurately identify the fluid types, resistivity experiments of core samples selected by the density and neutron logs are performed. The nuclear magnetic resonance (NMR) is simultaneously measured to determine the rock wettability. Instead of the conventional “aged” method for restoring the original wettability, a new set of experimental procedures is developed for obtaining resistivity and NMR [Formula: see text] spectra of samples with wettability as close as possible to that of the original reservoir. Specifically, samples with and without oil washing are measured separately, and a simple correction method for the resistivity index is developed. Moreover, the difference in the water salinity of different wells is considered. The results find that the resistivity index of samples drilled from possible oil-wet reservoirs indicated by the “abnormal” density and neutron responses varied from 2.807 to 5.388, whereas that of possible water-wet reservoirs was less than 2.0. The [Formula: see text] spectra at different states confirm the wettability of the samples. The resistivity index versus saturation ([Formula: see text]–[Formula: see text]) curves of oil-wet rocks are nearly straight lines other than the theoretical concave lines in double-logarithmic coordinates. Oil washing changes the rock wettability to varying degrees. Furthermore, the resistivity log responses of the reservoirs are accurately interpreted using the experimental data. The resistivity is simultaneously affected by the salinity, wettability, and saturation. Finally, based on the factors affecting the reservoir resistivity, fluid identification plots are established for reservoirs with different wettabilities. The agreement rates of identification using the crossplots and oil test are greater than 90%.

A Comparison of The Performances of Conventional and Low Salinity Water Alternating Gas Injection for Displacement of Oil

This study focuses on identifying the crucial physical and chemical factors, such as gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast, and salinity of injected water for improving oil recovery factor during water alternating gas (WAG) injection. The conventional WAG injection attracts interest from oil and gas industry and hence, has become one of the most reliable enhanced oil recoveries (EOR) techniques. During WAG injection, due to gravity effect, water subsides below oil layer while gas overflow above the oil layer. In fact, water sweeps bottom zones of the reservoir and gas sweep the attic oil at the upper zones of the reservoir. Although the conventional WAG does improve oil recovery factor, there still remains a substantial amount of oil in reservoir pores due to rock-fluid and fluid-fluid interfacial tensions (IFT) that leads to the capillary forces impeding the microscopic displacement efficiency. The low salinity waterflooding (LSWF) was therefore proposed to break the IFT between rock clay and fluids, and further increase oil recovery factor. Recent researches revealed that LSWF alters oil-wet reservoir to water-wet behavior. This wettability alteration is believed to be the main mechanism of LSWF to improve oil recovery. Other mechanisms of LSWF include multi-ion exchange (MIE) between rock clay minerals and injected salt water, pH increase, and fines migration. In this study, the CMG GEM simulator was used to simulate conventional WAG injection and LSWAG injection. The simulation results showed that there is an increase of oil recovery factor of about 6% for WAG injection with low salinity water of 1027ppm to sea water of 51,346 ppm. The simulations have also showed that the physical factors namely, gravity, initial oil phase, injection depth, vertical to horizontal permeability contrast are influential on the displacement efficiency and must be studied thoroughly in the design of LSWAG operations besides the salinity and chemical composition of the injection water.

Pore-scale investigation on microemulsion-based quasi-miscible flooding for EOR in water-wet/oil-wet reservoirs: A 3D study by X-ray microtomography

Microemulsion flooding has recently gained attention as an effective chemical-based method for enhanced oil recovery (EOR). The high performance of this technique is attributed to the classical mechanism: plugging effect and divergence of preferential flow path. In this study, miscible behavior was identified as a novel mechanism by which oil recovery was controlled by dissolution process instead of capillary forces. To this end, a new type of solvent-based microemulsion phase was prepared by mixing solvent, water, and surfactant as a flooding fluid. A series of experiments with direct water flooding, microemulsion flooding, and water-alternate-emulsion flooding for EOR were carried out for strong water-wet and oil-wet artificial rock samples. X-ray microtomography was used to visualize the oil configurations in three-dimensional pore spaces. An advanced workflow image processing method was developed for the first time to capture the miscible behavior from a pore-scale view. As suggested in the results, solvent-based microemulsion flooding has a miscible displacement front where the oil phase is gradually solubilized. Therefore, capillary forces can be eliminated because the emulsion-oil interface is invisible but has a compositional gradient, leading to higher oil recovery. Compared with the immiscible waterflooding process, the capillary forces remained dominant, which hinders additional oil recovery. Based on EOR scenarios, we found that the new emulsion flooding could effectively solubilize larger well-connected oil clusters instead of small separate ganglia or singlets. Therefore, considering its miscible behavior, the solvent-based microemulsion flooding can be applied to secondary oil recovery regardless of the reservoirs’ wettability, or to tertiary oil recovery in weakly/strongly oil-wet reservoirs with a well-connected oil phase after waterflooding.

An understanding of oil–water replacement mechanism based on interfacial tension gradient during the well shut-in

Spontaneous imbibition behavior of fracturing fluid retained in reservoirs is considered to be one of the important mechanisms of spontaneous oil–water displacement in tight reservoirs. However, the mechanism of imbibition displacement in oil-wet rocks remains unclear. Inspired by the principle of the Marangoni effect, a mathematical model of oil displacement driven by an interfacial tension gradient in an oil-wet capillary tube was established, and the effects of osmotic pressure and hydraulic mechanical dispersion were coupled in the model. The results show that the key component of this mechanism is the breakdown of the initial capillary equilibrium state due to the diffusion of solute, which changes the pressure distribution in the capillary and drives the water to drive oil out of the pores. This can explain the spontaneous imbibition of low-salinity fracturing fluid into the oil-wet tight sample and displace oil without any external force, despite its low permeability. In addition, the related factors were analyzed, including initial concentration, contact angle, solute type, osmotic behavior, and size of the capillary. The results show that for an oil wet reservoir with high salinity, the connate water interfacial tension gradient plays an important role in oil displacement, and the coupling effect of osmotic pressure and hydromechanical dispersion considerably improves recovery. This can provide new insight into the mechanism of spontaneous imbibition of fracturing fluid.

Experimental Investigation on the Effect of Pore Size on Spontaneous Imbibition Recovery in Oil-Wet Reservoirs

Spontaneous imbibition has been considered as a significant method to enhanced oil recovery (EOR) in unconventional reservoirs. The main impediment to comprehending the variation characteristics of spontaneous imbibition at different pore scales was the reservoir’s opacity. To this end, a series of spontaneous imbibition experiments of visualized oil-wet microtubes with six different diameters (10 μm~60 μm) were performed, as were the corresponding macroscopic core imbibition tests with six different permeabilities under the same conditions. The results showed that formation brine mostly advanced along the wall surface of a capillary during the imbibition process, and some were even isolated within a capillary. The imbibition recovery in the capillary with a diameter of 10 μm was the highest (27.81%), which was more than three times that of the capillary with a diameter of 60 μm (8.3%). There was a good power function decline relationship between capillary diameter and imbibition recovery, and 30 μm appeared to be a critical inflection point in both capillary tube and macroscopic core imbibition tests. In addition, the majority of the detained residual oil clusters not only cut off the continuity of formation brine but also increased the imbibition flow resistance, accelerating the imbibition to balance. This research provides a new perspective for comprehending the imbibition characteristics at different pore scales.

Efficiency of water-alternating-gas process in water-wet and oil-wet reservoirs by results of core flooding experiments on long core samples

Efficiency of water-alternating-gas process in water-wet and oil-wet reservoirs by results of core flooding experiments on long core samples

An Investigation on the Process of Reimbibition of Oil and Its Impact on Oil Recovery in the Yates Field

Summary In mixed- to oil-wet reservoirs characterized by intense natural fracturing where the dominant displacement mechanism is gravity drainage, surfactant injection can lead to a shift in wettability and incremental oil production. In some cases, oil can also reimbibe back into the rock matrix after the oil saturation has been reduced upon initial exposure to surfactant, suggesting limited permanence in the wettability shift. The reimbibition phenomenon is investigated in this paper using Amott cells. Three cationic surfactants (C12-, C12–16-, C16-based) with interfacial tensions (IFT) between 0.18 and 0.95 mN/m were preselected to be evaluated. Current application of the C12-based surfactant in the Yates field is considered successful based on incremental oil recovery seen during the treatment. Silurian dolomite (SD) rock samples were flooded with Yates crude oil before being aged at 60°C for 6 weeks. For the imbibition tests, the aqueous surfactant solution was set as the external phase within the Amott cell, and the recovery of oil was recorded periodically. After the imbibition tests ended, the rock samples were placed in an inverse Amott cell with the Yates oil as the external phase. Baseline tests were first conducted to show that without a surfactant in the oil or brine, no imbibition occurred. With a surfactant concentration of 3,000 ppm, oil recovery at the end of the imbibition tests varied from 34 to 60% of the original oil volume in the core sample. During the reimbibition test, a large amount of oil was able to reimbibe into the rock, displacing the brine. Most of the displacement occurred within the first 2 weeks. The net oil recovery, taken as the final volume of oil recovered in the imbibition test minus the final volume of oil reimbibed into the rock, ranged from 0 to 18%. Given the possibility of surfactant dilution in field applications, another set of tests was conducted with 1,500 ppm. A reduction in oil recovery during imbibition was observed for all the tested surfactants. Partition coefficients were determined for each of the tested surfactants, and the ion-pair mechanism was used to explain the net oil recovery results. Lastly, the impact of rock permeability on reimbibition was investigated. Results show increasing permeability may lead to a linear response in oil reimbibition; therefore, minimizing the permeability range when selecting rock samples may be necessary when conducting the reimbibition test. The importance of oil reimbibition is demonstrated in the experimental study, and we make an argument for conducting both the imbibition and reimbibition tests to better evaluate surfactant efficacy. The improved understanding of wettability alteration should lead to advancements in chemical enhanced oil recovery (EOR) designs for field treatments.

Carboxyl/alkyl composite silica-based amphiphilic nanoparticles enhanced spontaneous imbibition of low permeability sandstone rocks at reservoir conditions

In recent years, hydrophilic silica nanoparticles (HSNPs), as an effective and economic agent, have been demonstrated to exhibit great potential in changing the wettability of oil-wet reservoirs to water-wet. Nevertheless, due to the absence of amphiphilic nature, they hardly reduce the oil-water interfacial tension (IFT), which restricts their application in enhanced oil recovery. Therefore, this paper intended to synthesize carboxyl/alkyl composite silica-based amphiphilic nanoparticles (CSANPs) by grafting triethoxy(octyl)silane and hexanedioic acid on the surface of HSNPs through condensation and esterification reactions under specific conditions, and their structures were characterized with the assistance of advanced techniques. The characterization results indicated that the synthesized CSANPs had one hydrophobic surface composed of carbon chains and one hydrophilic surface composed of carboxyl groups. Then, the nanofluid (CSANF) was formulated by dispersing synthesized CSANPs in formation water to evaluate its stability, interface activity, wettability, and spontaneous imbibition. The evaluation results revealed that the CSANF could remain stable for one month under simulated reservoir conditions without aggregation and precipitation, which was attributed to the enhancement of mechanical barriers (electrostatic repulsion + steric effects) between CSANPs dispersed in the CSANF. The macroscopic contact angle measurement confirmed that the core slice surface treated with the CSANF became water-wet and therefore accelerated CSANF spontaneous imbibition. Because of amphiphilic structure, the CSANPs possessed a strong ability to reduce the oil-nanofluid IFT and improve the oil-nanofluid interfacial film strength, which was conducive to decrease oil discharge resistance during spontaneous imbibition. The highest imbibition recovery factor of the CSANF with a concentration of 0.05 wt% was obtained under the gravity and capillary forces. Finally, the low field nuclear magnetic resonance (NMR) results showed that the CSANF first entered micropores, then mesopores, and finally macropores.

Experimental study on the mechanism of adsorption-improved imbibition in oil-wet tight sandstone by a nonionic surfactant for enhanced oil recovery

In recent years, production from tight oil reservoirs has increasingly supplemented production from conventional oil resources. Oil-wet formations account for a considerable proportion of tight oil reservoirs. Surfactant can change wettability and reduce interfacial tension, thus resulting in a better oil recovery. In this manuscript, a nonionic surfactant was introduced for tight oil-wet reservoirs. The oil recovery in the oil-wet sandstone due to spontaneous imbibition was 8.59% lower than that of the water-wet sandstone due to surfactant. The 0.1% surfactant solution corresponded to the highest imbibition recovery rate of 27.02% from the oil-wet sample. With the surfactant treatment, the treated core quickly changed from weakly oil-wet to weakly water-wet. The capillary force acted as the driving force and promoted imbibition. The optimal surfactant adsorption quantity in the oil-wet sandstone was observed in the sample at concentrations ranging from 0.1% to 0.3%, which also corresponded to the highest oil recovery. Analysis of the inverse Bond number N B − 1 suggested that the driving force was gravity for brine imbibition in the oil-wet cores and that it was capillary force for surfactant imbibition in the oil-wet cores. When the surfactant concentration was lower than the critical micelle concentration, the surfactant concentration was negatively correlated with the inverse Bond number and positively correlated with the oil recovery rate. When the surfactant concentration was higher than the critical micelle concentration, the oil recovery increased with a smaller interfacial tension. Nuclear magnetic resonance suggested that the movable pore and pore throat size in the oil-wet sample decreased from 0.363 μm in the untreated rock to 0.326 μm with the surfactant treatment, which indicated that the surfactant improved the flow capacity of the oil. The findings of this study can help to better understand the adsorption impact of surfactants on the characteristics of the oil/water and solid/liquid interfaces. The imbibition mechanism in oil-wet tight sandstone reservoirs was further revealed. These systematic approaches help to select appropriate surfactants for better recovery in oil-wet tight sandstone reservoirs through imbibition.

Enhanced Oil Recovery by Cyclic Injection of Wettability Alteration Agent for Tight Reservoirs

Low primary recovery factor and rapid production decline necessitates the proposal of enhanced oil recovery methods to mobilize the remaining oil resource of tight reservoirs, especially for oil-wet ones, and wettability alteration by injecting a chemical agent such as a surfactant is a promising option. A discrete-fracture-network-based mathematical model is developed with consideration of the displacement mechanisms and complicated physical-chemical phenomena during EOR by wettability alteration, and this model numerically solved by the fully implicit method. Simulation cases are conducted to investigate the production performance and key factors of cyclic injection of a surfactant. Cyclic injection can significantly improve the production of oil-wet tight reservoirs, and the ultimate recovery factor can be increased by 10 percent. The reason is that a surfactant can alter the wettability of a reservoir from oil wet to medium or even water wet, which triggers spontaneous imbibition and favors oil movement from a matrix into a fracture. Better EOR results can be achieved with decreasing oil viscosity, increasing matrix permeability, or decreasing fracture spacing. Cyclic surfactant injection is applicable to reservoirs with an oil viscosity of less than 7 mPa·s, a matrix permeability bigger than 0.01 mD, or a fracture spacing smaller than 150 m. It is favorable for the wettability alteration method by maintaining capillary pressure and reducing residual oil saturation as much as possible.

A Crucial Role of the Applied Capillary Pressure in Drainage Displacement

SummaryWaterflooding has been applied either along with primary production to maintain reservoir pressure or later to displace the oil in conventional and heavy-oil reservoirs. Although it is generally accepted that waterflooding of light oil reservoirs in oil-wet systems delivers the least oil compared to either water-wet or intermediate-wet systems, there is a lack of systematic research to study waterflooding of heavy oils in oil-wet reservoirs. This research gives some new insights on the effect of injection velocity and oil viscosity on waterflooding of oil-wet reservoirs.Seven different oils with a broad range of viscosity ranging from 1 to 15 000 mPa·s at 25°C were used in 18 coreflooding experiments in which injection velocity was varied from 0.7 to 24.3 ft/D (2.5×10−6 to 86.0×10−6 m/s). Oil-wet sand (with contact angle of 159.3 ± 3.1°) was used in all the flooding experiments. Breakthrough time was precisely determined using an in-line densitometer installed downstream of the core. Oil-wet microfluidics (164.4 ± 9.7°) were used to study drainage displacement at the pore scale.Our observations suggest the crucial role of the wetting phase (oil) viscosity and the injection velocity in providing the driving force (capillary pressure) required to drain oil-wet pores. Capillarity-driven drainage can significantly increase oil recovery compared to injecting water at smaller pressure gradients. Increasing viscosity of the oil being displaced (keeping velocity the same) increases pressure gradient across the core. This increase in pressure gradient can be translated to the increase in the applied capillary pressure, especially where the oil phase is nearly stationary, such as regions of bypassed oil. When the applied capillary pressure exceeds a threshold, drainage displacement of oil by the nonwetting phase is facilitated. The driving force to push nonwetting phase (water) into the oil-wet pores can also be provided through increasing injection velocity (keeping oil viscosity the same).In this paper, it is demonstrated that in an oil-wet system, increasing velocity until applied capillary pressure exceeds a threshold improves forced drainage to the extent that it increases oil recovery even when viscous fingering strongly influences the displacement. This is consistent with the classical literature on carbonates (deZabala and Kamath 1995). However, the current work extends the classical learnings to a much wider operational envelope on oil-wet sandstones. Across this wider range, the threshold at which applied capillary pressure makes a significant contribution to oil recovery exhibits a systematic variation with oil viscosity. However, the applied capillary pressure; that is, the pressure drop observed during an experiment, does not vary systematically with conventional static parameters or groups and thus cannot be accurately estimated a priori. For this reason, the scaling group presented here incorporates a dynamic capillary pressure and correlates residual oil saturation more effectively than previously proposed static scaling groups.

Displacement behavior and mechanism of long-term water flooding in sandstone oil reservoirs

Sandstone oil reservoirs with huge bottom water and high permeability are generally developed with high flow rate. After long-term water flooding (LTWF), the water flooding characteristics are quite different from that of original reservoir. In this paper, the effects of the PV number, viscosity, and displacement rate during LTWF are studied through experiments. The mechanism is analyzed based on analysis of changes in oil composition, rock mineral composition and wettability. The oil-water relative permeability curves, oil recovery and wettability were obtained with new experiments methods, which avoids the oil metering error by measuring oil and water separately. The research indicates that when the viscosity increases, the water phase permeability decreases, the residual oil saturation increases, and the water content rate increases earlier. A higher water flooding rate results in a higher ultimate recovery. A higher asphaltene content results in a higher viscosity and more oil-wet reservoir conditions. After LTWF, the wettability tends to water-wet, which is more favorable for heavy oil recovery. Moreover, LTWF reduces the clay content, which creates a more water-wet surface and a larger reservoir pore throat environment. This research provides insightful characteristics of offshore sandstone oil reservoirs, which can be used to enhance oil recovery.