Carbonate Core Samples Research Articles

Long-Term Comparison of Nanosilica and Polyacrylamide/Polyethyleneimine Gels as Water Shutoff Agents in Permeable Matrix

Summary The oil and gas industry faces numerous challenges, among which the management of excessive water production is a significant concern. Nanosilica gel is a newly developed silicate gel for water shutoff applications. No investigation has been conducted to evaluate the gel’s performance over an extended period. The objective of this study is to evaluate the long-term performance of nanosilica gel in a permeable matrix over 6 months while also comparing this performance with polyacrylamide/polyethyleneimine (PAM/PEI) gel. Coreflooding experiments were conducted to evaluate the performance of the nanosilica gel of 75/25 wt% (nanosilica/activator) and PAM/PEI gel (9/1 wt%) on carbonate core samples at 200°F. The experiment involved initial permeability assessment, gel placement, and endurance tests up to 1,000 psi. Additional measurements of computed tomography (CT) scan and nuclear magnetic resonance (NMR) were implemented: CT scans visualized density changes, and NMR measured fluid distribution in the pore system. Then, samples were aged at 167°F for 6 months, with endurance tests (up to 1,000 psi) conducted in the first, third, and sixth months to assess gel-plugging efficiency. The results demonstrated nanosilica gel’s remarkable plugging efficiency, achieving a reduction in permeability from 144.85 md to 0.001 md initially and sustaining differential pressures up to 1,000 psi with minimal leakoff rates. After 6 months, nanosilica gel maintained plugging efficiency above 99.98%, while PAM/PEI gel efficiency reduced to 99.85%. The nanosilica gel achieved slightly better long-term plugging performance than PAM/PEI gel with a maximum leakoff rate of 0.25 cm3/min in 6 months (2.165 cm3/min for PAM/PEI gel). CT scan analysis confirmed effective gel placement within the pore systems, and minimal degradation occurred over time with less significant impact on the efficiency of nanosilica gel compared with PAM/PEI gel.

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.

Development of a new hydraulic electric index for rock typing in carbonate reservoirs

Rock typing techniques have relied on either electrical or hydraulic properties. The study introduces a novel approach for reservoir rock typing, the hydraulic-electric index (HEI), which combines the strengths of traditional electrical and hydraulic rock typing methods to characterize carbonate reservoirs more accurately. By normalizing the ratio of permeability and formation resistivity factor (K/FRF) with respect to porosity, the HEI method is applied to two datasets of carbonate core samples: dataset 1 consists of 112 carbonate core samples from the Tensleep formation in the Bighorn basin of Wyoming and Montana, and dataset 2 includes 81 carbonate core samples from the Asmari formation in the south-west of Iran. Statistical analysis confirms the effectiveness of the HEI in predicting permeability, with high determination coefficients for both datasets (resulting in determination coefficients (R2) of 0.965 and 0.904 for dataset 1 and dataset 2, respectively). The results classify the rock samples into distinct rock types, nine rock types for dataset 1 and four rock types for dataset 2, and demonstrate the HEI ability to capture the relationship between hydraulic conductivity and electrical resistivity in carbonate reservoir rocks. Applying the HEI method to the validation dataset yielded highly accurate permeability predictions, with average of determination coefficients of 0.883 and 0.859 for dataset 1 and dataset 2, respectively. Validation of the HEI method further confirms (20% of the dataset was set aside for validation, while the remaining 80% was used for the rock typing approach (5 folds)) its accuracy in predicting permeability, highlighting its robust predictive capacity for estimating permeability in carbonate reservoirs.

An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).

Chemical enhanced oil recovery under Harsh conditions: Investigation of rock permeability and insights from NMR measurements

Injecting surfactant into a hydrocarbon reservoir stands out as a highly effective method for EOR due to its ability to reduce water/oil IFT and alter rock wettability in certain cases. However, the efficiency of this process is compromised in heterogeneous reservoirs, especially carbonates, characterized by significant permeability variations. This study presents findings from three core flooding experiments on heterogeneous carbonate core samples with different permeabilities. The experiments were conducted under representative reservoir conditions of 100 °C, pressures higher than 3000 psi, and seawater salinities and formation water of 57,745 ppm and 213,768 ppm, respectively. In each experiment, seawater was continuously injected followed by continuously injecting a 2500-ppm solution of in-house synthesized Gemini surfactant. Results revealed that the recovery factor was highest in low-permeability rocks and lowest in high-permeability rocks for both seawater and surfactant floods. Surfactant floods yielded additional recoveries of 31%, 23%, and 19% for low, medium, and high-permeability samples, respectively. Nuclear magnetic resonance (NMR) analysis on short analogous core plugs at different flooding stages confirmed these results. Effluent analysis on the produced aqueous phase indicated that dynamic retention was highest (0.467 mg/gm-rock) in the lowest permeability and lowest (0.146 mg/gm-rock) in the highest permeability rock. NMR analysis suggested that the surfactant's recovery performance and dynamic retention were influenced by the larger surface area of low-permeability rocks, facilitating increased contact with the surfactant. Utilizing NMR monitoring in this work enhances EOR insights through integrated studies and coreflooding experiments and establishes a novel framework for complex reservoir conditions.

2D and 3D Modeling of Rock Mechanical Properties of Khasib Formation in East Baghdad Oil Field

Knowing the distribution of the mechanical rock properties and the far field stresses for the field of interest is an important task for many applications concerning reservoir geomechanics, including wellbore instability analysis, hydraulic fracturing, sand production, reservoir compaction, and subsidence. A major challenge with determining the rock's mechanical properties is that they cannot be directly measured at the borehole. Furthermore, the recovered carbonate core samples for performing measurements are limited and they provide discrete data for specific depths. The purpose of this study is to build 2D and 3D geomechanical models of the Khasib reservoir in the East Baghdad oil field/ Central area. TECHLOG.2015.3 software was used to build the 1D-MEM while Petrel E&P 2018.2 software was used to build the 3D distributions of rock mechanical properties. The Khasib formation has nine units (from K1 to K9). The current results support the evidence that the horizontal stresses are somewhat similar for all layers in the vertical case, but their distribution varies horizontally due to the changes in pore pressures. The pore pressure increases vertically, but its distribution within one layer is different due to the production from different wells. Elastic and strength characteristics of rock, including Young modulus, Poisson ratio, and unconfined compressive strength (UCS), have the same behavior, the highest value of the parameters appeared in the surface layer (K1). This layer is more stiff than other layers that have high porosities and high permeability. The internal friction angle for all formations ranges between 38o-40o, which gives a good harmonization with the limestone friction angle. The 3D distribution of the rock's mechanical properties revealed the carbonate heterogeneity because of its marine depositional environment and complex diagenetic processes. The findings of this study can be used for future geomechanical applications in the East Baghdad oil field including wellbore stability analysis, fault reactivation, and CO2 sequestration.

Designing effective enhanced oil recovery fluid: Combination of graphene oxide, D118 SuperPusher, and Chuback surfactant

Enhanced oil recovery (EOR) is one of the most essential branches of petroleum engineering and aims to maximize oil extraction from reservoirs. This research focuses on the utilization of graphene oxide (GO) in combination with a D118 SuperPusher compound and a natural surfactant (Chuback) to enhance oil recovery. The objective is to optimize the efficiency of the EOR process through a multi-component approach. The application of Chuback leads to a substantial decrease in interfacial tension (IFT), particularly in carbonate rock formations. This is attributed to the unique characteristics of carbonate rocks, which exhibit greater susceptibility to wettability alterations. Moreover, GO nanoparticles (NPs) were synthesized, then characterized and incorporated into the surfactant-polymer system, creating surfactant-polymer-nanoparticle (SPN) fluids. The selection of optimum fluid formulations for the EOR process is facilitated through the utilization of Design Expert, a statistical software tool. Factors such as surfactant concentration, polymer concentration, NPs concentration, and two types of salt concentrations are specifically chosen as variables that can influence the fluid's performance during the flooding step. Parameters including IFT, contact angle (CA) (which affects wetting behavior), and shear viscosity (which impacts fluid flow) are considered responses. The efficacy of the suggested fluid formulation for EOR is validated through core flooding investigations. Core flooding investigations validated the efficacy of the suggested fluid for EOR, with recovery factors of up to 30% and 56% in sandstone and carbonate core samples, respectively. These findings underscore the potential of the proposed approach to significantly enhance oil recovery from both sandstone and carbonate reservoirs.

Understanding pore characteristics through core-based petrographic and petrophysical analysis in a heterogeneous carbonate reservoir: A case study from the Mumbai Offshore Basin, India

Carbonate rocks exhibit complex and heterogeneous pore structures; such heterogeneity is manifested by the occurrence of a wide variety of pore types with different sizes and geometries as a result of depositional and diagenetic processes. These complications substantially increase the uncertainty of predicted rock hydraulic parameters because samples with comparable porosities might have very different permeability values. In this study, small-scale characterisation of porosity and permeability in heterogeneous Eocene limestone samples from the Bassein Formation of the B-X structure of the MK Field in Mumbai Offshore Basin, India, was carried out, employing an integrated framework that incorporates thin-section petrography, routine core analysis, mercury injection capillary pressure and nuclear magnetic resonance data. The pore characteristics of these carbonates range from poor to excellent. The studied samples exhibited large ranges of porosity, permeability and other associated petrophysical attributes. The pore types, as well as their orientations and connectivity, are the primary factors causing the heterogeneity. Because of the complexity of the pore networks, a simple lithofacies classification alone would have been insufficient to link porosity and permeability. The reservoir characteristics in the study area are strongly linked to the development and/or destruction of reservoir porosity–permeability during different phases of diagenesis. Twenty-four carbonate core samples from the limestone unit were studied and classified into microfacies and pore type classes, producing an accurate assessment of reservoir attributes. The comprehensive workflow incorporates the pore volume distributions and pore throat attributes for each rock type. Three carbonate microfacies were identified by petrographic analysis and their petrophysical characteristics, such as porosity, permeability, pore throat size, pore volume and fluid flow factors, were measured. The study demonstrates how macroporosity, mesoporosity and microporosity are associated with various rock types and how they affect permeability and cementation exponents. The results of this study provide a comprehensive experimental framework for geological and geophysical interpretation that can be applied to identify potential reservoir facies and strengthen our understanding of heterogeneous carbonates. The framework can also be used to guide reservoir evaluation of similar heterogeneous formations in other areas.

Stacked ensemble machine learning for porosity and absolute permeability prediction of carbonate rock plugs

This study employs a stacked ensemble machine learning approach to predict carbonate rocks' porosity and absolute permeability with various pore-throat distributions and heterogeneity. Our dataset consists of 2D slices from 3D micro-CT images of four carbonate core samples. The stacking ensemble learning approach integrates predictions from several machine learning-based models into a single meta-learner model to accelerate the prediction and improve the model's generalizability. We used the randomized search algorithm to attain optimal hyperparameters for each model by scanning over a vast hyperparameter space. To extract features from the 2D image slices, we applied the watershed-scikit-image technique. We showed that the stacked model algorithm effectively predicts the rock's porosity and absolute permeability.

Modelling and validation of dry and saturated velocities in carbonates from Saudi Arabia – Part II

Ultrasonic compressional (P-wave) and shear (S-wave) velocity data, obtained from a set of 35 dry and water-saturated (carbonate) core samples, were presented as a first part to this study, in a separate paper by Bakhorji and Schmitt (2022). These carbonate samples were obtained from a prominent reservoir in Saudi Arabia.In this follow-up paper, the velocity measurements, obtained from these 35 core samples, were utilized to, firstly, predict and validate four appropriate rock physics models and to, secondly, derive empirical relationships relating the P- and S-wave velocities to the porosity and calcite content of the samples (over the effective pressure range from 5 MPa to 25 MPa). The derived empirical relationships were validated against the wireline P- and S-wave velocities assuming insitu reservoir pressure conditions. The empirical models predicted the P- and S-wave velocities accurately over the reservoir interval of interest. The shear strengthening / weakening effect, or the saturation effect on the shear moduli, was also modelled and is discussed further.The comparisons of the Biot, Gassmann, Mavko-Jizba-Biot (MJ-Biot) and Mavko-Jizba-Gassmann (MJ-Gassmann) model predictions, with the measured water-saturated P- and S-wave velocities, show that the squirt mechanism was not applicable for our samples. The Gassmann model consistently over-predicts the water-saturated S-wave velocities at low pressure, but closely fits the measured velocities at high pressures, whereas Biot over-predicts the water-saturated velocities in most of the studied samples. We conclude that Biot global-flow is most likely to be the principle dispersion mechanism in these samples.

The Effect of Nano Heavy Metal Oxide Particles on the Wettability of Carbonate Reservoir Rock

Summary Production of oil from carbonate rocks is very challenging due to their inherent nature, such as detection, complex wettability, pore structure, and low recovery factor. Nanoparticles (NPs) are recognized as remarkable materials for a wide range of research and commercial applications due to their physical properties and characteristics. Extensive research in recent years has shown that nanoscience can provide great potential for the development of carbonate reservoirs and enhanced oil recovery (EOR). In this study, the carbonate core plug samples were prepared from an Iranian reservoir. At first, the wettability capacity of the core samples was evaluated. This process was carried out by evaluating wettability changes using the contact angle of base fluid and nanofluid. The potential of the NPs (ZnO, TiO2, and ZrO2) to change the wettability was experimentally tested in the loading NPs from 0.01 wt% to 0.5 wt% by the contact angle method. Wettability studies have shown that nanofluids can influence wettability variability from oil-wet to water-wet quality. About 0.05 wt% of NPs was found to be the optimal concentration to affect wettability change. The same behavior was observed for all nanofluids at the same NP loading; while TiO2 showed better performance with a sharp change from an oil-wet state (θ = 151.9°) to a water-wet state (θ = 111.3°), ZnO, and ZrO2 changed wettability to a moderately-wet condition (θ = 108.6° and 118.6°, respectively) at 0.05 wt% NP loading. We conclude that TiO2-based nanofluids have great potential as EOR agents, and TiO2 is very impressive in its strong water-wettability. The highest oil recovery in the optimal amount for all three nanofluids was obtained as 35.2%, 23.2%, and 25.6%, respectively, for TiO2, ZnO, and ZrO2 nanofluids. Furthermore, we considered the effect of nanofluids on the recovery performance of the brine/oil system for carbonate core samples. The results showed that nanofluids can significantly imbibe into the core sample, and as a result, the final oil recovery is significant.

Investigating Different Fluids and Injection Patterns on the Effect of Reservoir Rock Quality Alteration due to Swelling and Migration of Clay Minerals at Carbonate Reservoirs

Abstract Nowadays, with the progress in technology, the demand for fossil fuels has increased. Therefore, improving the oil recovery from the current oil reservoir is among the crucial issues. Formation damage is a well-recognized subject that causes a reduction in the productivity or injectivity of an oil well. Reducing or controlling formation damage can be effective in improving oil recovery. There are various mechanisms that cause formation damage such as fine migration and clay swelling. In this study, the simultaneous effect of fine migration and swelling on the permeability of a carbonate rock was investigated. Kaolinite and smectite(bentonite) minerals were selected as the representative case for migration and swelling, respectively. Primarily, bottle tests were conducted to study the effect of different fluids on the swelling potential of the kaolinite and smectite. According to the structural feature of the kaolinite, it has the smallest cation exchange capacity (CEC) and consequently a low swelling tendency. Therefore, it showed negligible swelling in the presence of all fluids. According to the high cation concentration of the formation water (FW) and seawater (SW), smectite did not show a high swelling effect. However, diluting the FW and SW increased the swelling tendency of the bentonite. Nanoparticles were not able to control the swelling of the bentonite according to their larger size than the spacing of clay layers. Zirconium oxychloride was also utilized as the swelling inhibitor which showed high efficiency. Eventually, different injection scenarios were tried using synthetic carbonate core samples with specific clay contents, and the best injection plan for formation damage control was determined.

Enhancement of Oil Recovery in West Qurna-1 Carbonate Reservoir by Injecting Seawater

Seawater injection is a novel emerging technology for enhancing oil recovery in Middle East carbonate reservoirs. This paper investigated the mechanism of seawater injection in Mishrif formation for the West Qurna-1 oil field. The decline in the pressure of West Qurna-1 needs pressure support by water injection, where it is a supergiant oil field. This study is significant because seawater injection technology is considered a future technology in the south of Iraq for several reasons. One of these reasons is the scarcity of fresh water in the Middle East, especially in Iraq, and the second reason is the availability of seawater, which is close to Basra city. This paper aims to study the essential parameters that influence the oil recovery via sweater injection as well as the inherent mechanisms that help increase the oil recovery. Collected five core plugs from producing units of Mishrif formation, MB1, and MB2, having different petrophysics properties where the permeabilities ranged from 6 to 143 md. Two types of water are used formation water and seawater. We conduct core flood experiments on chosen carbonate core samples and formation water from Iraq's West Quran-1 carbonates. The common belief facts that low salinity flooding of oil recovery gives more producing oil for the same volume of water injected due to wettability alteration. The analysis of injected and producing water indicates that higher concentrations of SO4-2 and Ca-2 ions change the wettability of the rock to more water-wet. Consequently, the oil recovery increases by 10-15 % when using seawater, which is richer in these ions.

Synergistic Effects of Aqueous Phase Viscoelasticity and Reduced Interfacial Tension on Nonwetting Phase Displacement Efficiency: An In Situ Experimental Investigation.

This study uses in situ experimental investigation techniques to probe the synergistic effects of aqueous phase viscoelasticity and reduced interfacial tension on nonwetting phase displacement efficiency in natural porous media. Specifically, it examines the efficacy of viscoelastic surfactant (VES) solutions in enhancing oil recovery and investigates the pore-scale displacement mechanisms and VES-oil interactions. To this end, we first performed an extensive rheological characterization to select two VES solutions from multiple CTAB/NaNO3 (CTN) and Cocobetaine/SDS/NaCl (CSN) mixtures. The selected aqueous solutions were then used in unsteady-state imbibition experiments conducted on miniature, water-wet Prairie Shell carbonate core samples. The experiments were performed utilizing a high-pressure, high-temperature two-phase core-flooding apparatus integrated with a high-resolution X-ray imaging system to acquire pore-scale fluid occupancy maps during the displacements. The results indicate that the injection of the selected CSN and CTN solutions into the carbonate samples under capillary-dominated flow regimes boosts the oil recovery by 12 and 2%, respectively, compared to those of the base waterflood. The VES solutions lowered the oil-water interfacial tension and exerted significant shear forces at the entrance of pores. The shear forces could exceed the threshold surface free energy required to deform oil globules, and consequently, large oil clusters were fragmented into smaller blobs and eventually produced from the pore space. The higher oil recovery by CSN flooding was attributed to its stronger viscoelastic properties. The VES injection under the viscous-dominated flow regime intensified the frequency of oil globule fragmentation. As a result, residual oil saturation values were sharply reduced in the rock samples from 44 to 55% during the capillary-dominated flows to approximately 8%. The above-mentioned observations were also verified using morphological analysis of residual oil clusters. The impacts of VES flooding on the pore-scale oil configuration and the fragmentation of large oil clusters were particularly evident at higher VES flow rates.

Adopted Factorial and New In-Situ Micro-Designs for Stimulation of Matrix Acidizing of Carbonate Reservoir Rocks

Matrix acidizing has been developed in the petroleum industry for improving petroleum well productivity and minimizing near-wellbore damage. Mud acid (HF: HCl) has gained attractiveness in improving the porosity and permeability of reservoir formation. However, there are several challenges facing the use of mud acid, comprising its corrosive nature, high pH value, formation of precipitates, high reaction rate and quick consumption. Therefore, different acids have been developed to solve these problems, including organic-HF or HCl acids. Some of these acid combinations proved their effectiveness in being alternatives to mud acid in reservoir rock acidizing. The current research deals with a new acid combination based on Hydrochloric–Oxalic acids for acidizing carbonate core samples recovered from Qamchuqa Formation in Kirkuk oilfield, northern Iraq. A new in-situ micro-model adopted laboratory technique is utilized to study the microscale alteration and evolution of pore spaces, dissolved grains and identification of matrix acidizing characteristics. The in-situ micro-model is based on the injection of an identical dose of different concentrations of the new acid combination into thin section samples under an optical light microscope. The adopted procedure aims to provide unique and rapid information regarding the potential for texture and porosity modification that can be caused by the acidizing stimulation procedure. In connection, solubility tests for the untreated and treated reservoir core samples and the density of the combined acids after treatment are conducted based on designed experiments using response surface methodology (RSM). The effect of acid concentration [12% HCl: Oxalic acid (3.8–8.8%)] and acidizing temperature (from ambient to 78.8 °C) on the solubility percentage of the samples and percentage increase in the combined acid density after acidizing were optimized and modeled. The obtained results confirm that the optimum dissolution of the core samples took place using 12% HCl:3.2% Oxalic acid with an optimum solubility (%) of the carbonate core rock of 53.78% at 21.7 °C, while the optimum increase in density (%) of the combined acids was 1.54% at 78.3 °C. The promising results could be employed for matrix acidizing of carbonate reservoir rocks for other oilfields.

Laboratory Testing of Nanosilica-Reinforced Silicate and Polyacrylamide Gels

Summary One of the most common methods used to reduce excessive water production is water shutoff operations. These types of operations include injection of gel for flow profile modification. The most widely used gels are polyacrylamide- and silicate-based gels. As a way to improve and optimize gel characteristics, nanosilica can be added to the gelant solution. In this paper, laboratory testing of nanosilica-reinforced silicate and polyacrylamide gels is presented. Bulk gelation and capillary tubing tests were used for determination of gelation time, and core flooding tests on low permeability carbonate core samples were conducted as a way to assess gel-plugging ability. Tests showed that gelation time for both types of gels was faster when nanosilica was added. The strength of the polyacrylamide-based gel was enhanced. Silicate gel samples with nanosilica led to a 17% higher reduction in permeability compared to pure silicate gel, and polyacrylamide gel with the addition of nanosilica has almost 43% higher permeability reduction compared to pure polyacrylamide gel.

Dissolution behaviour in carbonate reservoirs during WAG injection: A preliminary experimental study

In this study, a core flooding experiment using a water-alternating-gas (WAG) injection was conducted to evaluate its impact on the petrophysical properties of an initially oil-saturated heterogeneous carbonate core sample. Carbon dioxide (CO2) and synthetic formation brine were injected (0.5 pore volume CO2 alternating with 0.5 pore volume brine) alternately following establishment of waterflooding residual oil saturation under reservoir conditions. Gas porosity, gas permeability, NMR (nuclear magnetic resonance) T2 measurements, and X-ray CT scanning were conducted preand post-core flooding. The results show that CO2-WAG injection resulted in substantial additional oil recovery (~30 %) under the applied experimental conditions. The results also show an increase in the permeability of the tested sample from 1.5 to 16 mD, which could be attributed to mineral dissolution. X-ray CT imaging shows signs of excessive mineral dissolution and formation of wormhole structures. It is believed that dissolution within the tested core plug caused the WAG fluids to follow the newly wormhole (causing them to enlarge further), and consequently bypassing many parts of the sample. Therefore, despite a significant increase in oil recovery, a large amount of oil is still left behind.

Laboratory Investigation of Nanofluid-Assisted Polymer Flooding in Carbonate Reservoirs

In the petroleum industry, the remaining oil is often extracted using conventional chemical enhanced oil recovery (EOR) techniques, such as polymer flooding. Nanoparticles have also greatly aided EOR, with benefits like wettability alteration and improvements in fluid properties that lead to better oil mobility. However, silica nanoparticles combined with polymers like hydrolyzed polyacrylamide (HPAM) improve polymer flooding performance with better mobility control. The oil displacement and the interaction between the rock and polymer solution are both influenced by this hybrid approach. In this study, we investigated the effectiveness of the injection of nanofluid-polymer as an EOR approach. It has been observed that nanoparticles can change rock wettability, increase polymer viscosity, and decrease polymer retention in carbonate rock. The optimum concentrations for hydrolyzed polyacrylamide (2000 ppm) and 0.1 wt% (1000 ppm) silica nanoparticles were determined through rheology experiments and contact angle measurements. The results of the contact angle measurements revealed that 0.1 wt% silica nanofluid alters the contact angle by 45.6°. The nano-silica/polymer solution resulted in a higher viscosity than the pure polymer solution as measured by rheology experiments. A series of flooding experiments were conducted on oil-wet carbonate core samples in tertiary recovery mode. The maximum incremental oil recovery of 26.88% was obtained by injecting silica nanofluid followed by a nanofluid-assisted polymer solution as an EOR technique. The application of this research will provide new opportunities for hybrid EOR techniques in maximizing oil production from depleted high-temperature and high-salinity carbonate reservoirs.

Experimental study of the low salinity water injection process in the presence of scale inhibitor and various nanoparticles

In this work, the process of low salinity water injection (LSWI) into reservoirs at various salt concentrations was simulated in order to study the change in the oil recovery factor during oil production. The simulation results of the recovery factor were compared with the experimental data. The results demonstrated that the simulation data were in good agreement with the experimental results. In addition, the formation damage (rock permeability reduction) in carbonate core samples was evaluated through coreflood experiments during LSWI in the range of salt concentration and temperature of 1500–4000 ppm and 25–100 °C, respectively. In the worst scenario of LSWI, the rock permeability has reached about 83% of the initial value. Our previous correlation was used to predict the formation damage in LSWI. In this case, the R-squared value between predicted and experimental data of rock permeability ratios was more than 0.97. Furthermore, the recovery factor during LSWI was analyzed with and without the use of DTPMP scale inhibitor (diethylenetriamine penta (methylene phosphonic acid)), and various nanoparticles (TiO2, SiO2, Al2O3). The results of the coreflood experiments showed that the use of scale inhibitor provides an increase in the recovery factor by more than 8%. In addition, the highest recovery factor was observed in the presence of SiO2 nanoparticles at 0.05 wt.%. The oil displacement during LSWI in the porous media with SiO2 particles was better than TiO2 and Al2O3. The recovery factor in the presence of SiO2, TiO2, and Al2O3 with DTPMP was 72.2, 62.4, and 59.8%, respectively. Among the studied nanoparticles, the lowest values of the oil viscosity and interfacial tension (IFT) between oil and water were observed when using SiO2. Moreover, the contact angle was increased by increasing the brine concentration. The contact angle with the use of SiO2, TiO2, and Al2O3 at 0.05 wt.% was reduced by 11.2, 10.6, and 9.9%, respectively.

Synergistic SmartWater based surfactant polymer flooding for enhanced oil recovery in carbonates

SmartWater flooding has been recognized as an efficient and practical technology to synergize with different enhanced oil recovery methods for increasing oil recovery. This article aims to investigate the beneficial synergy effect between the SmartWater and surfactant-polymer (SP) flooding for carbonate reservoirs. Both zeta potential and contact angle measurements revealed that a favorable wettability alteration was induced with SmartWater. Coreflooding experiments were performed using preserved carbonate core samples at reservoir conditions. Results demonstrated that SP flooding combined with SmartWater achieved higher oil recovery with less chemical consumption when compared to conventional SP flooding.