Residual Saturation Research Articles

Experimental Study on the Mechanism and Law of Low-Salinity Water Flooding for Enhanced Oil Recovery in Tight Sandstone Reservoirs.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO42- can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T2 signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

Surfactant-polymer flood with seawater for a high temperature carbonate reservoir

Developing ultralow tension surfactant formulations for carbonate reservoirs at high temperatures (> 100 °C) in the presence of hard brine is challenging. The target carbonate reservoir had been flooded with seawater and changing of the injection brine (softening or low salinity) for enhanced oil recovery was considered expensive. Seawater was presumed to be the injection brine for this study. The goal of this research work was to develop an ultralow tension surfactant-polymer (SP) formulation with seawater for this carbonate reservoir at 115 °C and to evaluate core floods with and without salinity gradient. Phase behavior was studied for many surfactants and ultralow IFT formulations were identified with the optimal salinity near the seawater salinity. SP core floods were conducted in reservoir sand packs at 115 °C; a novel 2-oven technique was used to collect the effluent with no wax formation and minimal hydrocarbon vaporization. The residual oil saturation was reduced to less than 1% in floods with salinity gradient and about 5% in constant salinity floods (at seawater salinity). The novelty of the work lies in developing SP formulations with seawater at a high temperature and studying the effect of salinity gradient. This process can be considered for many off-shore fields which have been waterflooded with seawater.

Research and Application of Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery Reservoir Screening Criteria and Method for Continental Reservoirs in China

CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this study investigated and compared the CCUS-EOR reservoir screening criteria outside and in China, sorted out the main reservoir parameters that affect CO2 flooding, and optimized the indices and scope of CCUS-EOR reservoir screening criteria in China. The weights of parameters with respect to their influences on CCUS-EOR were determined through principal component analysis. The results show that there are 14 key parameters affecting CO2 flooding, which can be categorized into four levels. For the first level, the crude oil-CO2 miscibility index holds the greatest weight of 0.479. It encompasses seven parameters: initial formation pressure, current formation pressure, temperature, depth, C2–C15 molar content, residual oil saturation, and minimum miscibility pressure. The second level consists of the crude oil mobility index, which has a weight of 0.249. This index includes four parameters: porosity, permeability, density, and viscosity. The third level pertains to the index of reservoir tectonic characteristics, with a weight of 0.141. It comprises two parameters: permeability variation coefficient and average effective thickness. Lastly, the fourth level focuses on the index of reservoir property change, with a weight of 0.131, which solely considers the pressure maintenance level. Based on the CCUS-EOR reservoir screening criteria and index weights established in this study, comprehensive scores for CCUS-EOR were calculated for six blocks in China. Among these, five blocks are deemed suitable for CCUS-EOR. Based on the comprehensive scoring results, a planning for field application of CCUS-EOR is proposed. The study provides a rational method to evaluate the CCUS-EOR reservoir screening and field application in continental reservoirs in China.

Factors Influencing the Rheology of Methane Foam for Gas Mobility Control in High-Temperature, Proppant-Fractured Reservoirs

Gas-enhanced oil recovery (EOR) through huff-n-puff (HnP) is an important method of recovering oil from fracture-stimulated reservoirs. HnP productivity is hampered by fracture channeling, leading to early gas breakthroughs and gas losses. To mitigate these issues, foam-generating surfactants have been developed as a method of reducing injected gas phase mobility and increasing oil recovery. This work investigates foam generation and propagation by a proprietary surfactant blend in high-temperature, high-pressure, high-permeability, and high-shear conditions that simulate the environment of a proppant-packed fracture. Bulk foam tests confirmed the aqueous stability and foaming viability of the surfactant at the proposed conditions. Through several series of floods co-injecting methane gas and the surfactant solution through a proppant pack at residual oil saturation, the effects of several injection parameters on apparent foam viscosity were investigated. The foam exhibited an exceptionally high transition foam quality (>95%) and strong shear-thinning behavior. The foam viscosity also linearly decreased with increasing pressure. Another flood series conducted in an oil-free proppant pack showed that swelling of residual oil had no effect on the apparent foam viscosity and was not the reason for the inversely linear pressure dependency. An additional flood series with nitrogen as the injection gas was completed to see if the hydrophobic attraction between the methane and surfactant tail was responsible for the observed pressure trend, but the trend persisted even with nitrogen. In a previous study, the dependence of foam viscosity on pressure was found to be much weaker with a different foaming surfactant under similar conditions. Thus, a better understanding of this important phenomenon requires additional tests with a focus on the effect of pressure on interfacial surfactant adsorption.

Modelling of CO2 Sequestration in Deep Saline Aquifer Reservoir using Surface Evolver Software

A strategy to mitigate CO2 concentration in the atmosphere is injection of supercritical CO2 in porous sedimentary medium filled with saline water where CO2 gets trapped in the pores. Sequestration is resultant of two processes, drainage and imbibition in accordance with capillary law. Simulation of the pore-scale trapping has been performed on reservoir scale. A simple model reservoir consisting of 1000 tetrahedral subunits was constructed. Using Surface Evolver software, pore volueach subunit. The CO2 pressure and liquid saturation curves of the reservoir displayed hysteretic character, indicating that the evolution of the system is pathway-dependent. The simulated curves illustrate the pathway dependency of the residual gas saturation, an important parameter controlling the amount of CO2 stored in the reservoir, hence the efficiency of the CO2 storage. Our study also shows the existence of critical thresholds in terms of in/out gassing during the drainage or imbibition processes

Design of Multi-Luminescent Silica-Based Nanoparticles for the Detection of Liquid Organic Compounds.

Tracer testing in reservoir formations is utilised to determine residual oil saturation as part of optimum hydrocarbon production. Here, we present a novel detection method of liquid organic compounds by monodisperse SiO2 nanoparticles (NPs) containing two luminophores, a EuIII:EDTA complex and a newly synthesised fluorophore based on the organic boron-dipyrromethene (BODIPY)-moiety. The particles exhibited stable EuIII PL emission intensity with a long lifetime in aqueous dispersion. The fluorescence of the BODIPY was also preserved in the aqueous environment. The ratiometric PL detection technique was demonstrated by using toluene and 1-octanol as model compounds of crude oil. The optimal synthesis conditions were found to give NPs with a diameter of ~100 nm, which is suitable for transport through porous oil reservoir structures. The cytotoxicity of the NPs was confirmed to be very low for human lung cell and fish cell lines. These findings demonstrate the potential of the NPs to replace the hazardous chemicals used to estimate the residual oil saturation. Moreover, the ratiometric PL detection technique is anticipated to be of benefit in other fields, such as biotechnology, medical diagnostics, and environmental monitoring, where a reliable and safe detection of a liquid organic phase is needed.

Increasing Oil Recovery by Varying Surfactant Concentrations and Expanding the Well Drainage Area

Surfactant flooding plays a crucial role in advanced techniques for boosting oil recovery. There remains a significant volume of unrecovered oil in reservoirs, particularly in carbonate reservoirs. These reservoirs often face challenges with low primary and water-flood recovery due to inadequate sweep efficiency, resulting in the presence of bypassed or trapped oil. Chemical flooding approaches, including surfactant flooding, have demonstrated their effectiveness in the retrieval of this trapped oil. The fundamental concept of surfactant flooding involves injecting a surface-active agent, known as a surfactant, to reduce the interfacial tension and mobilize the residual oil saturation. Surfactants have been widely utilized for various purposes in the petroleum industry since its early years, owing to their capacity to modify interfacial interactions between two immiscible fluids in contact with one another. Interfacial phenomena play a significant role in rock-fluid interactions and the interactions between fluids from the reservoir to distribution pipelines. Consequently, surfactants find application in a variety of activities within the petroleum industry. Laboratory experiments, pilot-scale projects, and field-scale initiatives worldwide have yielded diverse outcomes regarding the use of surfactants for enhancing oil recovery. Multiple types of surfactants have been investigated to determine highly effective chemical formulations for enhanced oil recovery, with anionic and non-ionic surfactants being commonly employed in sandstone reservoirs.

Study on the influence of steam state on seepage, production, migration and deposition of offshore heavy oilfields

In this paper, the influence of steam state on seepage, production, migration and deposition are refined, and the superiority of superheated steam is confirmed. Firstly, the relative permeability of oil-water and oil-steam in offshore cores was measured to analyze flowing characteristics. Then the cyclic steam stimulation of long core was conducted with supersaturated, saturated and superheated steam, and the recovery capacity was quantified, the difference in composition of produced oil was analyzed. Finally, the CT scanning and digital core 3D reconstruction were performed to visualize the influence of steam state on migration of heavy oil components. The results show that the temperature has a significantly higher effect on seepage capacity than permeability, which can effectively broaden the co-seepage range and reduce residual oil saturation. The total recovery of superheated steam is 12 % and 7 % higher than the other two steam respectively, and the main recovery cycle is the former four rounds, which accounts for over 85 % of total recovery. The retention of heavy components can reduce porosity by 4 %∼7 %, superheated steam can alleviate blockage and increase the porosity by over 2 %. This work is expected to provide valuable insights into the application of superheated steam in offshore heavy oilfields.

Mechanisms of simultaneous removal of multiple chlorinated hydrocarbons in aquifers by in-situ microemulsion

The chlorinated hydrocarbons (CHs) are typically released to the aquifer as complex mixture, and the contaminant type takes the critical action on the in-situ microemulsion formation and solubilization behaviors. However, few interst has been paid to the solubilization behaviors of microemulsion for multiply CHs and the factors affecting selective solubilization. The current work investigated the effect of hydrogeochemical conditions on microemulsion competitive solubilization, and focused on the selective desorption and removal performance of in-situ microemulsion drenching under the various drenching situations. The results elucidated that the apparent solubility of CH was enhanced with adding inorganic salts and the decreasing temperature. In-situ microemulsion showed a preference for dissolving the more polar CHs (CF) in chlorinated hydrocarbon mixture. The selective solubilization was strengthened with increasing temperature, independent of alcohols and salts. The removal efficiency of microemulsion drenching for multiply CHs could achieve 96.0 %, improving with the tinier particle media and lower flow rates. Compared to other CHs, CF was more likely to be desorbed from aquifer medium in multicomponent systems. Furthermore, the selective desorption for multiply CHs was associated with flow rates, media size and residual saturation of contaminants. The inhibition for preferential desorption was more intense to the increase of injection velocity, media size and residual saturation. This insight of selective solubilization behavior can be used to advances the application of in-situ microemulsion drenching for site remediation of multiply CHs.

Numerical simulation of enhanced throughput of surfactant in Lamadian oilfield

Based on the actual data of Lamadian oilfield in terms of geological structure, reservoir fluid physical properties and production dynamics, a numerical simulation geological model of CMG STARS chemical flooding module is established, which is consistent with the static and dynamic characteristics of the oil reservoir. In order to study the effect of enhanced throughput of surfactants, based on the mechanism of enhanced throughput of surfactants, the numerical model was established by defining parameters such as oil-water interfacial tension at different concentrations, residual oil saturation, oil-water relative permeability curve, capillary pressure, isotonic point change and surfactant diffusion coefficient in the formation, etc. The numerical simulation of surfactant enhanced throughput was carried out to optimize the surfactant enhanced throughput parameters in Lamadian oilfield, and the sensitivity sequence of each injection and production parameter to the surfactant enhanced throughput and oil was determined. The final recommended injection and production parameters are surfactant injection amount (10000m3), injection concentration (0.5%) and brazing time (2d). It is predicted that the cumulative oil increase can reach 1310m3, the initial daily fluid production is controlled at 80m3/d, the daily oil production can be increased by 10m3/d, and the water cut can be reduced by 10%.

Three-dimensional modeling of nanoconfined multiphase flow in clay nanopores using FIB-SEM images of shale

<p>Understanding the flow characteristics within shale nanopores is crucial for enhancing hydrocarbon recovery. However, the flow characteristics of wetting and non-wetting fluids on nanopore surfaces differ significantly, limiting the accurate prediction of hydrocarbon accumulation and migration. This work introduces the Euler-Euler volume of fluid method to establish a multiphase flow numerical model in shale nanopores, considering complex pore topology, slip flow, and capillary effects. Based on natural three-dimensional shale nanoporous systems constructed from FIB-SEM images, single-phase water/oil flow and water-oil forced imbibition simulations are carried out under the complete wetting condition. Results show that the displacement pressure is reduced and the imbibition rate is elevated considering nanoscale slip effects. As imbibition progresses, the pressure and imbibition rate gradually converge toward the values observed in conventional flows. In complete wetting nanoporous systems, water flow experiences high pressure and low velocity, whereas the pressure for oil flow is significantly reduced. Forced imbibition may undergo a transition from capillary force-dominated to viscous force-dominated, with a negative displacement pressure at the initial stage. Furthermore, the fluctuations in water-oil mass flow considering the slip effect are less pronounced than those observed in conventional flows, leading to reduced residual fluid saturation in blind-end pores and pore bodies caused by snap-off events. Pore systems with poor connectivity and narrow throat structures correspond to low displacement efficiency. The findings of this work explain the impact of nanoscale slip effects on flow characteristics in unconventional reservoirs, contributing to the reasonable assessment of fluid flow capacity and facilitating production planning.</p>

The mobilization mechanism of low oil saturation reservoirs

After fracturing with a guar fluid system in Chang 8 oil reservoir, some wells have high oil production, and some have low production and even only produce water. Therefore, a comparative study is carried out in oil-producing and water-producing wells. The results show that: ① Organic wax adsorbed in oil-producing and water-producing well core pores accounts for 95.39% and 56.67%, respectively, making wells strong oil-wet. A certain proportion of inorganic salts and some other oil-wet organic compounds exist in water-producing wells. ② Under the reservoir conditions, the oil wettability of the water-producing well core is strong, and its original formation wettability is also oil-wet. The original wettability of the oil-producing well formation is water-wet, with oil production capacity. ③ The core residual oil saturation using the guar fluid is 24.7%–29.87%. This results in no oil phase permeability or difficulty to mobilize oil in most oil reservoirs. ④ Forced displacement can mobilize oil in large pores and has a significant effect in producing well, with mobilization efficiency of 53.49%. This article elucidates the wettability formation and crude oil mobilization mechanism of two types of wells, providing direction for the development of this type of reservoir.

INVESTIGATING ABSORPTION EFFECTS ON OIL DROPLETS IN ENHANCED OIL RECOVERY: A FORCE ANALYSIS APPROACH

This research aims to analyze the forces that affect oil droplets to illustrate that augmenting the mass of an oil droplet fosters favorable conditions for interaction between displaced and displacing fluids. This, in turn, impedes the bypassing of the displacing fluid around the oil droplets. In this investigation, the concept of augmenting the mass of an oil droplet is realized through absorption phenomena, employing coated spinel oxide (cobalt ferrite oxide) nanoparticles (CFO NPs). The synthesis of CFO NPs was successfully carried out in the laboratory using a sol-gel technique, followed by coating with a surfactant and lauric acid. The coated spinel oxide NPs underwent characterization using IR, XRD, and XRF techniques. The procedures started with the calculation of capillary force restrictions for small and large oil droplets. Furthermore, practical experiments involving oil droplets on glass plates at a 30° angle were conducted for different scenarios: without water injection, with water injection, and during the “absorption effect” of CFO NPs. The findings revealed that a large oil droplet exhibits lower capillary pressure restrictions compared to a small oil droplet, with a disparity of 0.02 m/s2 . Consequently, it is comparatively easier for large oil droplets to become free than small ones. Moreover, a large oil droplet exhibits faster movement than small oil droplets due to gravitational effects in the absence of any injections. During the water injection scenario, the water droplets were unable to displace the oil droplet; instead, they passed through the passage beside and above the oil droplet consistently with an increase in the amount of water droplets. However, in the coated CFO NPs scenario, absorption of the coated CFO NPs onto the oil droplet was observed. This resulted in the aggregation of oil molecules, augmenting the gravity of the oil droplet and creating favourable conditions for its displacement. Notably, no water bypass beside the oil droplet was observed in this scenario, unlike the water scenario. Additionally, the aggregation of oil molecules induced corner flow, providing conducive conditions for microemulsion formation, altering wettability, modifying residual oil saturation, and enhancing injection performance. Euler’s equation was employed to analyse corner flow, indicating that the level of oil deformation increases with the rising rotation velocity, potentially leading to an increased recovery factor.

Justification of the boundary values of open porosity and gas permeability using data from flow studies for porous carbonate reservoirs

This paper proposes a method for determining the boundary values of open porosity (KPO_GR) and gas permeability (KPR_GR) of porous-type carbonate reservoir rocks using the example of Tournaisian deposits of one of the oil fields of the Republic of Tatarstan. When justifying the boundary values, two databases on core studies are used: 1) on standard core studies (used mainly to calculate hydrocarbon (HC) reserves); 2) on special core studies (used for technological development projects). In the proposed method, the residual oil saturation factor is not a constant, but is taken from flow studies or calculated from core dependencies. When determining the lower limits of porosity and permeability from both databases, approximately the same boundary values were obtained: KPO_GR = 0.11 fr. un., KPR_GR = 2·10–3 μm2 and KPR_GR = 1.7·10–3 μm2, but they differ from the values, accepted by petrophysicists when calculating the reserves of considered deposit – KPO_GR = 0.09 fr. un., KPR_GR = 1·10–3 μm2. Such a difference in determining the boundary porosity can significantly affect the calculation of hydrocarbon reserves, technological calculations and field development planning.

ABOUT SOME PROBLEMS OF WATERFLOODING IN CARBONATE RESERVOIRS

The features of waterflooding of carbonate (fractured-porous) rocks, caused by the interaction of the system of fractures with the matrix (blocks) of the rock, are considered. It is shown that the slower propagation of the pressure pulse in the rock matrix in comparison with the propagation of this pulse along the fracture system of the formation leads to compression of the rock blocks in the near-wellbore zone of the injection well, as a result of which stress concentration occurs at the ends of vertical fractures, which increases the likelihood of these fractures growing into the roof of the productive formation. It is shown that in order to prevent the development of this process, the growth rate of water injection pressure should be limited in accordance with the time of liquid pressure equalization in the pore space of the rock matrix and in the fracture system. When developing production wells drilled in fractured porous media, in order to prevent the development of the process of closing fractures in the bottomhole zones of these wells, the drawdown reduction rate must also be limited in a similar way. It is noted that when applying technologies for non-stationary flooding of productive reservoirs, the main factor determining their effectiveness is the change in the direction of filtration flows in the reservoir. This leads to the activation of filtration processes in the stagnant zones of the formation and the intensification of the processes of capillary impregnation of low-permeability interlayers with water from more flooded highpermeability interlayers.At the same time, it is important to take into account that when changing the direction of filtration flows at a late stage of development of carbonate reservoirs, in order to prevent reimpregnation of hydrophobic rock blocks with oil, it is more expedient to change the operating modes of production rather than injection wells. It is shown that water flooding of hydrophobic carbonate reservoirs results in incomplete water displacement of oil as a wetting phase from rock blocks. To reduce the residual oil saturation of rock blocks, it is advisable to increase the displacement pressure gradient in the reservoir in combination with a change in the direction of filtration flows in it.

CALCULATION OF AN ALTERNATIVE DEVELOPMENT SYSTEM FOR THE MAIN DEPOSIT OF THE DANILOVSKOYE OIL AND GAS CONDENSATE FIELD

The article provides a calculation of an alternative development system for deposit 3 (Main deposit ) of the Danilovskoye oil and gas condensate field. At the time of the analysis, this deposit is in the pilot development stage, with six development variants proposed in the trial operation project, which assume a principled arrangement of wells along an areal homogeneous grid. At the same time, due to the need to maintain the energy of the formation (that is, certain values of thermodynamic conditions), three provide for a transition to pressure maintenance, with the resulting four-point scheme of effect on the deposit (intensity 1:2; one well for injection, two for production). In the alternative model under consideration, the development method also involves a subsequent transition to pressure maintenance, but with a more active, five-point waterflooding system (intensity 1:1, equal ratio of production and injection wells), if necessary, as will be shown in the work, easily convertible to a nine-point one. The latter is an objective advantage, since the formation has low permeability and high vertical and lateral heterogeneity, and during waterflooding, zones not affected by the impact may appear, and, consequently, zones with high residual oil saturation. When calculating the characteristics of the proposed alternative method, modeling using the Peaceman method is used. Peaceman’s method is based on determining the well-reservoir connectivity of each individually opened cell, used to calculate flow rates (taking into account different values of average water cut for wells). The method is classical and, although it includes a large number of limiting assumptions, it is applicable everywhere and can provide sufficient justification for the effectiveness of the chosen development variant. General recommendations for the development of the entire field are also given (taking into account the low viscosity and lightness of oil and the properties of reservoir rocks). Such as the use of acid fracturing technology, the use of surfactants, hydrochloric acid treatments (HAT) and a complexing phosphorus-containing reagent — AFC.

Interplay of interfacial tension and capillarity: Optimizing surfactant displacement efficiency in reservoirs

Surfactant treatments play a crucial role in formation cleaning and wettability alteration for reservoirs characterized by low porosity and permeability. One effective approach to enhance oil recovery in such formations is spontaneous imbibition (SI) driven by capillarity, which enables surfactants to infiltrate tight rock matrices. Through the reduction of oil/water interfacial tension (IFT), surfactants effectively diminish residual oil saturation, leading to improved oil recovery. However, excessive IFT reduction can hinder capillarity, resulting in inefficient surfactant penetration. On the other hand, forced imbibition (FI) does not rely on capillarity for surfactant penetration, and thus, improved recovery is primarily driven by IFT reduction. Consequently, achieving the optimal surfactant conditions necessitates a delicate equilibrium between IFT reduction and maintaining adequate capillarity to facilitate surfactant penetration. In this study, we explored the performance of three surfactant types (cationic, anionic, and zwitterionic) for oil recovery through SI and FI experiments, assessing their effects at both Darcy and pore scales. All tested surfactants successfully lowered IFT as anticipated but exhibited distinct impacts on wettability, as indicated by contact angle measurements. Consequently, the use of SI in Amott cell experiments did not yield favorable oil recovery improvements in Berea rock compared to the water baseline. Pore-scale assessments using Micro-CT revealed that the surfactants disrupted the connectivity of the oil phase within the rock, leading to reduced SI efficiency. In contrast, distinct recovery trends emerged with FI. To replicate the experimental results, we conducted pore-scale and Darcy-scale simulations, which serve as valuable tools for surfactant screening and optimization. This study underscores the importance of balancing IFT reduction and wettability alteration in surfactant screening to achieve optimized recovery efficiency based on the predominant recovery mechanisms.

A multi-mechanistic approach to the oil recovery study of a family of amphiphilic polysaccharides

Chemical enhanced oil recovery (cEOR) remains one of the most potent tertiary recovery techniques. However, it is expensive and rarely environmentally friendly. Bio-based amphiphilic polymers have been suggested as an alternative to eradicating the challenges of conventional cEOR because of cost-effectiveness, and sustainability. Unfortunately, few in-depth studies exist in the literature to investigate the prospects of these materials. A new family of amphiphilic polysaccharides was synthesized by hydrophobic modification of cellulose sulphate, and the EOR functionalities were tested. The novel biopolymers exhibited the ability to alter rock wetting properties. In terms of recovery, one of the variants of the synthesized bio amphiphilic polymer (D-I) was able to reduce residual oil saturation to 12% at harsh conditions of 60,000 ppm salinity at 75 °C. Micromodel visual analysis revealed that the performance of the novel materials was due to the combination of mobility control, IFT lowering and emulsification, wettability alteration, and viscoelasticity. With a performance commensurate to that of a commercial hydrophobically modified polymer, it can be said that the novel amphiphilic polysaccharides can stand as a viable cEOR agent for oilfield applications.

Relationship Between Residual Saturations and Wettability Using Pore-Network Modeling

Summary The relationship between residual saturation and wettability is critical for modeling multiphase processes like enhanced oil recovery, CO2 sequestration, and geologic storage of hydrogen. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Observations from traditional coreflooding experiments show a minimum in the trends of residual oil saturation (Sor) around mixed-wet conditions. Amott indices, however, provide an average measure of wettability because of their intrinsic dependence on a variety of factors such as the initial oil saturation, aging conditions, rock heterogeneity, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore-network modeling (PNM), we show that Sor varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the Sor decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, the calculation of Amott indices for the PNM data sets shows that a plot of the Sor vs. Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. In this research, we employ a numerical approach to quantify trends of Sor against the traditional definition of wettability. Through the analysis of our numerical work and literature experiments, we find that under isolated conditions (constant initial saturation), linear trends exist between Sor and wettability. This can have important implications for low salinity waterflooding, water-alternating-gas enhanced oil recovery, or CO2 sequestration where the effects of wettability are critical to understand phase trapping.

Impact of wettability on capillary phase trapping using pore-network modeling

The impact of rock wettability on phase mobility and capillary trapping is significant in the valuation of geologic carbon sequestration scenarios. Wetting conditions of CO2/brine/rock systems can vary from site to site and over time due to changes in temperature, pressure, salinity, mineral composition and surface roughness. Therefore, effective predictability of CO2 mobility and trapping in underground formations requires a thorough exploration of the relationship between wetting conditions and phase saturation over a wide range of contact angles. In this paper, we use pore-network modeling to investigate the effect of wettability on phase mobility and capillary trapping. We simulate different wetting and nonwetting conditions during secondary flooding cycles where the initial phase saturations are varied significantly. Characteristic initial-residual (IR) saturation curves and the locus of residual phase connectivity and saturation are determined for each wettability condition.Simulations show that when the receding phase is the wetting phase, there is reduced trapping of that phase owing to piston-like advance by the nonwetting phase and sustained layer flow of the wetting phase. Such flow regimes cause nonlinearity in the characteristic initial-residual (IR) saturation curve, which is not captured by traditional trapping models. A proposed extended Land-based model matches the IR trends for all wettabilities. Simulations also show that the loci of residual phase saturation and phase connectivity are a strong function of wettability. When the receding phase is strongly nonwetting, the locus remains nearly constant in phase connectivity, while at increasingly wetting conditions, the locus forms a closed-loop in the saturation-connectivity space, where the endpoint of the locus is constrained by pore topology as residual saturations approach low values.