Berea Cores Research Articles

Graphene Nanoplatelets Extend Life of Scale-Inhibitor Squeeze Treatment

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215228, “Graphene Nanoplatelets for Extended Lifetime of Scale-Inhibitor Squeeze Treatment in a High-Temperature Reservoir,” by Suzalina Zainal, SPE, Norzafirah Razali, and Mohamad A. Rodzali, Petronas, et al. The paper has not been peer reviewed. _ Scale-inhibitor squeeze (SISQ) treatment is an established method for offshore fields that allows an extended effectiveness of scale inhibitors in preventing deposition over time. One of the primary issues in SISQ campaigns is the short squeeze lifetime of less than 1 year. The study detailed in the complete paper proposed graphene nanoplatelets (GNP) as a preflush system to extend the lifetime of a conventional SISQ treatment. This carbon-based nanomaterial allowed enhanced adsorption of the phosphonate-based scale inhibitor. GNP as a Preflush System A high-surface-area GNP preflush system was chosen to condition the rock surface to overcome the apparent lack of suitable surfaces available for scale-inhibitor adsorption during SISQ treatment. The GNP was injected to coat the rock surface. GNPs consist of a few graphite layers with thicknesses varying from 0.7 to 100 nm. The carbon-based nanomaterial forms a honeycomb structure, regarded as a good alternative to its predecessor, graphene, because of its lower cost and potential for large-scale production. GNP particle size ranges between 100 and 200 nm. This 2D carbon nanomaterial offers several advantages, such as high surface area, a high aspect ratio with a planar shape, and good mechanical properties with excellent thermal and electrical conductivities. It is also inert toward common reservoir fluid. Experimental Procedure Materials. Injection and formation water (brine samples) were prepared based on compositions listed in Table 1 of the complete paper. Berea core plugs were used for static-adsorption and injectivity experiments. In these two experiments, the core samples were used to provide similar rock properties when comparing performances of the baseline preflush (seawater) vs. nano-preflush systems. The average rock permeability for the candidate oil field is between 200 and 400 md. Dispersion Evaluation in High Divalent Brine. Gum arabic (GA) stabilized the GNP in high divalent brine. The polymer-grafted GNP (P-GNP) samples were evaluated in terms of exfoliated sites as compared with GNP alone. Zeta-potential and particle-size analysis also were performed at different P-GNP concentrations. Static-Adsorption Evaluation. A static-adsorption method was designed to replicate preflush injection of P-GNP before introduction of scale inhibitor. Experiments compared the adsorption of the scale inhibitor onto crushed Berea rock, precoated with P-GNP, with another without pre-coating that used seawater preflush only. Coreflood Evaluation. Because of the scarcity of the native core samples, only Berea core samples were used for the injectivity study, while native core samples were used for the SISQ adsorption/desorption coreflood evaluation. In both types of experiments, a P-GNP preflush system was compared with the baseline (seawater preflush).

A New Method for Optimizing Water-Flooding Strategies in Multi-Layer Sandstone Reservoirs

As one of the most important and economically enhanced oil-recovery technologies, water flooding has been applied in various oilfields worldwide for nearly a century. Stratified water injection is the key to improving water-flooding performance. In water flooding, the water-injection rate is normally optimized based on the reservoir permeability and thickness. However, this strategy is not applicable after oilfields enter the ultra-high-water-cut period. In this study, an original method for optimizing water-flooding parameters for developing multi-layer sandstone reservoirs in the entire flooding process and in a given period is proposed based on reservoir engineering theory and optimization technology. Meanwhile, optimization mathematical models that yield maximum oil recovery or net present value (NPV) are developed. The new method is verified by water-flooding experiments using Berea cores. The results show that using the method developed in this study can increase the total oil recovery by approximately 3 percent compared with the traditional method using the same water-injection amounts. The experimental results are consistent with the results from theoretical analysis. Moreover, this study shows that the geological reserves of each layer and the relative permeability curves have the greatest influence on the optimized water-injection rate, rather than the reservoir properties, which are the primary consideration in a traditional optimization method. The method developed in this study could not only be implemented in a newly developed oilfield but also could be used in a mature oilfield that has been developed for years. However, this study also shows that using the optimized water injection at an earlier stage will provide better EOR performance.

CO2-brine mass transfer patterns and interface dynamics under geological storage conditions

CO2 geological storage is a promising carbon negative technology with important application prospects. Dissolution trapping is a reliable method throughout the life cycle of a storage project, because it plays a significant role in minimizing risks. A comprehensive understanding of its mechanism is challenging due to the complex mass transfer process controlled by numerous physical and chemical factors, which needs to be clarified at different scales but still significantly limited in current research. Investigating CO2-brine interfacial mass transfer in real rock cores during imbibition provides valuable insights into the behavior of CO2 in geological formations. This study conducted a series of pore-scale CO2-brine interfacial mass transfer experiments during imbibition in three rock cores using an X-ray micro-computed tomography machine. The dissolution patterns and interface dynamics during the dissolving processes were discussed systematically. The results indicate that the overall slice-averaged and per-cluster mass transfer coefficient between CO2 and brine is in the order of 10−8 m/s, but its specific value depends on the dissolution patterns and bubble sizes. Various dissolution patterns were found in different rock cores. A core-length dissolution finger was formed in the Berea core, causing higher per-cluster mass transfer coefficients around the finger, while lower coefficients elsewhere in the dissolution experiments. The interfacial mass transfer process, coupled with gravity instability, induced remobilization of isolated CO2 bubbles at a much lower capillary number than the critical capillary number. The remobilization of CO2 bubbles can even occur at single-pore scale. CO2 remobilization also created a phenomenon similar to intermittent pathway flow. Interface dynamics of CO2 dissolving processes were revealed for the first time, giving rise to non-uniform dissolutions in CO2 singlets, ganglia, and clusters, respectively.

The evaluation of dodecyl hydroxy sulfobetaine as a high-temperature and high-salinity resistant foaming agent in sandstone reservoirs

For the high temperature (130 °C), high pressure (30 MPa), and high salinity (2.5 × 105 mg/L) of formation water conditions in the target block of the Tarim Basin Oilfield in northwest China, dodecyl hydroxy sulfobetaine surfactant was evaluated for its foaming performance, thermal stability, adsorption performance. The evaluation results showed that the surfactant exhibited good foaming ability and thermal stability than the general carboxy betaine under the above harsh conditions. The static adsorption of the surfactant on the surface of quartz sand particles was less than 1 mg/g with a concentration of less than 0.4%, which met the requirement for foaming agent adsorption. Moreover, the results of core displacement experiments indicated that, when simultaneously injecting 0.4% foaming agent and gas at a volume ratio of 3:7 into the cores of 38 mD, 161.4 mD, and 478.7 mD, foam with low mobility of less than 2 mD/cP could be generated; in the 57.3 mD Berea core, the resistance factor of foam generated by 8 cycles of injecting gas-liquid alternately with gas-liquid volume ratio ranging from 0.2:0.1 to 0.4:0.1 was nearly 20, and the residual resistance factor was greater than 5 after 5 PV of continuous gas injection. The results of the study can guide the selection of foaming agents for gas mobility control in high-temperature and high-salinity sandstone reservoirs.

APPLICATION OF NEUTRON COMPUTED TOMOGRAPHY IN ENHANCED OIL RECOVERY FOR ANALYSING OIL DISTRIBUTION IN BEREA SANDSTONE USING BAGASSE SURFACTANT

The Neutron Computed Tomography (NCT) technique was adopted to study oil content within sandstone. In recent times, oil industries have turned to the Enhanced Oil Recovery (EOR) technique that uses chemicals/surfactants to reduce interfacial tension to maximize oil production from mature oil fields. The Berea core played a crucial role in investigating surfactant effectiveness for liberating trapped oil. The presented research is based on laboratory experiments carried out at the National Research and Innovation Agency and at the Trisakti University, Indonesia. The research proceeded in three steps. The first step was observation on the Berea core that is saturated with a low salinity brine of 40,000 ppm and 60,000 ppm and assessment of the total porosity of the sandstone. The second step included injecting oil into the sample and examining the water distribution. The final step was to inject sugarcane bagasse surfactant with 2% surfactant concentration to extract oil from the sandstone, then it was subjected to NCT analysis. The observations show that the pores are evenly distributed in the middle, the oil content accumulates at the edge, almost no oil remains in the middle of the Berea core after water injection, and the remaining oil returns to the main flow after surfactant injection. The results show that oil movement in the Berea core with 40,000 ppm salinity is better than oil movement with 60,000 ppm. The salinity of the brine can affect the mobility of oil droplets in the Berea core, and surfactant injection processes have better performance at lower salinity and are susceptible to higher salinity.

Morphological and Euler characteristics of nonwetting phases in porous media

The geometric structure variation of the nonwetting phase (NWP) in porous media plays a critical role in numerous energy-related processes. This work conducted a series of gas/liquid displacements in three rock cores using high resolution x-ray microcomputed tomography (micro-CT), including two sandstones and a Berea core with different pore architectures. The morphological and topological characteristics of NWP were investigated at the pore scale in a full cycle of primary drainage (PD), main imbibition (MI), and main drainage (MD). It is found that roof and distal snap-off occurred during drainage, resulting in nonwetting (NW) singlets and ganglia. These NW bubbles occupied 10%–20% NWP volume. Both throat snap-off and pore snap-off were observed in MI, which generally occur at a single-pore scale. The effect of viscous force is significant even at a capillary dominant displacement. The trapped NWP during PD can be partially or totally displaced in MI through further snap-off events or viscous remobilization. Due to the temporal and spatial scale diversion in pore scale events, the amplitude of pressure drop fluctuations among PD, MI, and MD is different. The significant difference in NWP characteristics between PD and MD is connectivity, thus leading to hysteresis.

Study on the synergism of cellulose nanocrystals and janus graphene oxide for enhanced oil recovery

The usage of nanoparticles in enhanced oil recovery (EOR) has been numerous due to their captivating ultra-small size and eccentric thermal, electrical, and interfacial modification properties. However, nanoparticles in their bare form could suffer from several drawbacks due to possible stability issues. The incorporation of a synergist into the preparation of nanofluid has been a promising approach to alleviate stability issues. In the present study, a novel fusion nanofluid (FN) composed of a cellulose nanocrystal (CNC), and an amphiphilic graphene oxide-based Janus nanosheet (AMGO) is presented. We synthesized the CNC using enzymatic hydrolysis and ultrasonic processing from the cellulosic waste extracted from Eucheuma cottonii, a marine-based crop. Moreover, we synthesized the AMGO from a green immobilization method. Subsequently, the CNC and AMGO were combined via sonication to form FN. The CNC, AMGO, and FN were characterized appropriately using spectroscopy and microscopy techniques. As controls, CNC and AMGO were tested alongside FN in terms of rheological properties measurements, contact angle measurements, and the core flooding experiment on Berea and Edwards White core samples. Based on the rheology measurements, FN exhibited a more elastic behavior than CNC, demonstrating better dispersibility that could be attributable to the formation of a more resilient 3D network structure via hydrogen bonding synergisms between CNC and AMGO. Furthermore, FN reduced contact angles from ∼166° to ∼35° in the Berea, and ∼172° to ∼25° in the Edwards White, signifying excellent favorable wettability alteration in both rock types. Through core flooding experiments, FN attained additional oil recoveries of 22.96% and 12.24% from Berea and Edwards White, respectively, which were up to 16.04% and 3.37% more than the control runs. As opposed to CNC, the injection of FN did not result in excessive pressure drop readings, attributing to the better dispersibility and better wettability alteration abilities. Nonetheless, the developed FN comprising CNC and AMGO could be referenced for the future design of greener nanofluid with optimistic EOR efficacies.

Mobility of Sub-50 nm Iron Oxide Nanoparticles with Ultrahigh Initial Magnetic Susceptibility in Intact Berea Sandstone at High Salinity

Superparamagnetic iron oxide nanoparticles (IONPs), which have been investigated extensively as contrast-enhancing agents in biology, are being explored for subsurface applications such as electromagnetic tomography, fracture mapping, and enhanced oil recovery. However, two key challenges must be addressed: (a) high magnetic susceptibility and (b) colloidal stability and mobility under harsh reservoir conditions of high salinity and temperature. Herein, we synthesize IONPs grafted with poly(2-acrylamido-3-propanesulfonate-co-acrylic acid) poly(AMPS-co-AA) to achieve a high surface grafting density of polymer (49%) with minimal aggregation to yield sub-50 nm IONPs. The IONPs were found to be colloidally stable at 120 °C for a period of one month at pH 8. In crushed Berea sandstone, polymer-grafted IONPs exhibited significantly high mass breakthrough (84%) and low retention (149 μg/g) when used with a sacrificial polymer preflood (0.1% v/v). Intact Berea core experiments showed an 8-fold improvement in mass breakthrough (65%) and a two-thirds reduction in retention (from 433 μg/g to 160 μg/g) when compared to previous studies with IONPs synthesized via coprecipitation. The high grafting density of polymeric stabilizer and small nanoparticle size contribute to the improved mobility in consolidated porous media at high salinity.

The effect of aluminosilicate in anionic–nonionic surfactant mixture on wetness and interfacial tension in its application for enhanced oil recovery

In particular, this study aims to investigate the effect of aluminosilicate nanoparticle in the mixture of anionic (Sulfonated Alkyl Ester) and nonionic (Fatty Ester Oleate) surfactants on the interfacial tension and wettability related to EOR processes. Various experiments were conducted such as measuring interfacial tension between oil and brine using spinning drop tensiometer, measuring contact angle between surfactant-NPs-brine solution and Buff Berea core using optical tensiometer, conducting spontaneous imbibition, and core flooding tests.It is observed that the more anionic surfactant in the mixture the more significant aluminosilicate reduces contact angle and increases interfacial tension (IFT), which promotes contradicting effect on oil recovery. In this study, the IFT prevails and eventually reduces ultimate oil recovery. At spontaneous imbibition tests the ultimate oil recovery is decreased from 58% to 47% and from 63% to 46% for SAE-01A and SAE-01B, respectively. The ultimate oil recovery is reduced from 54% to 35% and from 50% to 39% at core flooding tests (Figure 16) for SAE-01A and SAE-01B, respectively. The aluminosilicate nanoparticle contributes positively as the ratio of SAE and FEO becomes smaller. At surfactant formulation ratio of 1:2 (SAE-01C), the IFT is decreased slightly from 4.36 x 10−3 mN/m to 2.36 x 10−3 mN/m and contact angle is also slightly reduced from 41.9° to 40.3° by adding 250 ppm NPs. The results show that ultimate oil recovery is increased 52% to 61% and from 47% to 49% at spontaneous imbibition tests and core flooding tests, respectively.

CO2 huff-n-puff experimentation and numerical simulation for 3D printed rock samples

3D printed rock samples advance the experimental research of fluid flow physics in the petroleum industry. 3D printed replicas can be flexibly tailored to different experimental setups, in addition to the low cost of creation with uniform materials. The conducted experiments, on 3D printed samples, have less geometrical uncertainties, which is related to the accurately described structure of the pore network. The difficulties of describing fluid-rock interaction are diminished because of the compositional uniformity of the 3D-printing material. Therefore, 3D printed replicas were used, in this paper, to demonstrate the CO2 effects on oil recovery through a huff and puff experiment. The CT scan of a Berea core sample was reconstructed using image processing to prepare a 3D printable object. The two samples, i.e., the 3D printed gypsum replica and its original Berea core sample, were inserted simultaneously in a newly designed experimental setup to conduct the huff and puff experiment under the same conditions. The oil recovery was reported at three different CO2 injection pressures and temperatures. After running the experiment, the synthetic core sample was broken laterally and longitudinally to examine the CO2 action in the sample visually. As a pioneer study, the CO2 effect on a 3D-printed core sample was pictured, which can be used to explain the physics of CO2 diffusion in porous media. Finally, a supporting simulation model was created based on the CT scan to simulate the experiment. The simulation results matched the recovery results for the 3D printed replica and generated oil composition crosssections similar to the pictured ones.

An evaluation of organic acids implementation in stimulating tight Saudi reservoirs: A case study on Sarah sandstone formation

Sandstone formations are stimulated with mud acid when matrix acidizing is most competent. In terms of high-pressure, high-temperature (HP-HT) conditions, the corrosive impact of hydrochloric (HCl) acid prompted the need to explore other alternatives to mud acid. This study examines the efficiency of organic acids in stimulating Sarah sandstone, a tight gas formation of potential.The optimum injection of acid volume was tested on Berea cores. Besides, the mineralogy of outcrop rocks of Sarah formation was identified using X-ray diffraction (XRD) aided by Scanning Electron Microscopy (SEM). Formation mineralogy led to the selection of acetic-hydrofluoric (C₂H₄O₂-HF) and oxalic-HF (C₂H₂O₄-HF) as proper acids for stimulation experiments. Bentonite water-base mud was used to alter the permeability of three fresh Sarah sandstone core samples. The organic-HF acids were used to stimulate two core samples, while mud acid (HCl-HF) was tested in the third core for comparison. Energy-dispersive X-ray spectrometer (EDX) and SEM were utilized to study the impact of acids on porous media.Experiments conducted in Berea core samples led to the execution of five pore volumes (PV) of preflush and one PV of main treatment as the optimum volume during the acidizing trials. XRD and SEM identified pore-filling clay minerals causing the low permeability of Sarah formation. Furthermore, the water-base mud injected decreased the permeability further by 80%. Oxalic-HF and acetic-HF mixtures recovered the initial permeability of core samples by 46% and 35%, respectively. SEM-EDX results showed how organic acids have partially unblocked the pathways of the structural pores leading to permeability enhancement.This research not only recommends the use of oxalic-HF Acid for acidizing Sarah sandstone formation but also spotlights the ability of organic acids to employment as preflush in hydraulic fracturing operations.

Relationship of Various Interfacial Tensions of Surfactants/Brine/Oil Formulations to Oil Recovery Efficiency

Chemical enhanced oil recovery aims to increase the oil recovery of mature oil fields. The interfacial tensions (IFTs) between the aqueous solution, the oil phase, and other possible phases are important for designing and estimating a chemical formulation effectiveness. Ultralow (<10–² mN·m–¹) IFTs are needed to increase the capillary number and help mobilize trapped oil droplets. Five types of equilibrium IFTs (EIFTs) have been defined as follows: (I) the un-pre-equilibrated equilibrium IFT; (II) the un-pre-equilibrated EIFTs in the presence of rock; (III) the pre-equilibrated EIFTs in the presence of oil; (IV) the pre-equilibrated EIFT in the presence of rock and oil; and (V) the effluent EIFT. Among the five types of EIFTs, the fourth and fifth were found to be the most important for the highest oil recovery performance in core flood tests, because they capture the effects of surfactant partitioning into the oil phase and the adsorption losses on the rock surface. For three surfactant formulations tested with Berea core flood experiments, the one with the lowest type-IV EIFT (∼0.01 mN·m–¹) had the highest oil recovery ratio (78%), and the one with the highest type IV EIFT (∼0.2 mN·m–¹) had the lowest oil recovery ratio (55%). The other EIFTs correlated less well with the oil recovery performance. Identifying surfactant formulations that have low or ultralow EIFTs, especially of type IV or V, is critical for screening formulations appropriate for core flood tests and target field applications, and for predicting the oil recovery performance.

The effect of middle phase emulsion and interfacial tension of Sodium Lignosulfonate surfactant synthesized from bagasse to Enhanced Oil Recovery

Enhanced Oil Recovery (EOR) is an effort to increase oil recovery after primary recovery and secondary recovery. One method used is chemical injection using surfactants. Sodium Lignosulfonate (SLS) is one of the anionic surfactants commonly used in the EOR process. Sodium Lignosulfonate can be made by bagasse synthesis, as an alternative to the use of lignosulfonate surfactant. The purpose of this study was to determine the effect of the middle phase emulsion and interfacial tension on the recovery factor results. The method used is the core injection. The injection fluid used is Sodium Lignosulfonate surfactant which has been tested for its characteristics. This research uses core flood devices and synthesized Berea cores. Core injection is carried out in several variations of salinity and surfactant concentration. The results of the study show that the largest recovery result is at 1.5% 15000 ppm with a recovery factor of 5.34% where the emulsions are the least among other compositions but the emulsions are stable at 48 hours and the IFT value is also relatively low at 4.34 mN/m. The lowest recovery results are at 1.5% 4000 ppm with a recovery factor of 3.24% where the emulsions are highest but the emulsions are stable at 336 hours, and the IFT value is relatively high at 10.40 mN / m. Based on this study it can be concluded that if the middle phase emulsion is quickly stable and the IFT value is low it will result in enhanced oil recovery.

Experimental Determination of CO2 Diffusion Coefficient in a Brine-Saturated Core Simulating Reservoir Condition

CO2 diffusion coefficient plays a crucial part in saline aquifers for the CO2 storage and the safety of long-term sequestration. Therefore, it is particularly important to measure the diffusion coefficient accurately. As far as we know, there are currently no CO2 brine diffusion data in real cores under reservoir temperature and pressure conditions. In this paper, a study on the CO2 diffusion coefficient diffused in a brine-saturated Berea core along the radial direction was conducted at temperatures of 313.15 K to 373.15 K and pressures of 8 MPa to 30 MPa. On account of the experimental results, the effect of permeability, NaCl concentration, temperature and pressure on the CO2 diffusivity is analyzed. The results in this study indicate that the diffusion coefficient increases with increasing permeability, pressure and temperature and decreases with increasing NaCl concentration. However, the relationship between pressure and the diffusion coefficient is not linear. As the pressure gradually increases, the effect of pressure will become weak. In addition, an empirical correlation of the relationship between temperature–pressure and the CO2 diffusion coefficient could be obtained based on the experimental data. The data in this paper fill the blank on the study of the CO2 diffusivity in brine under reservoir conditions, which has positive significance for the study of supercritical CO2 diffusion in a brine-saturated core.

Photon-magnon response to fluid variability and saturation levels in sandstone reservoirs

Abstract The need to recover high viscosity heavy oil from the residual phase of reservoirs has raised interest in the use of electromagnetics (EM) for enhanced oil recovery. However, the transformation of EM wave properties must be taken into consideration with respect to the dynamic interaction between fluid and solid phases. Consequently, this study discretises EM wave interaction with heterogeneous porous media (sandstones) under different fluid saturations (oil and water) to aid the monitoring of fluid mobility and activation of magnetic nanofluid in the reservoir. To achieve this aim, this study defined the various EM responses and signatures for brine and oil saturation and fluid saturation levels. A Nanofluid Electromagnetic Injection System (NES) was deployed for a fluid injection/core-flooding experiment. Inductance, resistance and capacitance (LRC) were recorded as the different fluids were injected into a 1.0-m long Berea core, starting from brine imbibition to oil saturation, brine flooding and eventually magnetite nanofluid flooding. The fluid mobility was monitored using a fibre Bragg grating sensor. The experimental measurements of the relative permittivity of the Berea sandstone core (with embedded detectors) saturated with brine, oil and magnetite nanofluid were given in the frequency band of 200 kHz. The behaviour of relative permittivity and attenuation of the EM wave was observed to be convolutedly dependent on the sandstone saturation history. The fibre Bragg Grating (FBG) sensor was able to detect the interaction of the Fe3O4 nanofluid with the magnetic field, which underpins the fluid mobility fundamentals that resulted in an anomalous response.

Experimental study of combined low salinity and surfactant flooding effect on oil recovery

A new generation improved oil recovery methods comes from combining techniques to make the overall process of oil recovery more efficient. One of the most promising methods is combined Low Salinity Surfactant (LSS) flooding. Low salinity brine injection has proven by numerous laboratory core flood experiments to give a moderate increase in oil recovery. Current research shows that this method may be further enhanced by introduction of surfactants optimized for lowsal environment by reducing the interfacial tension. Researchers have suggested different mechanisms in the literature such as pH variation, fines migration, multi-component ionic exchange, interfacial tension reduction and wettability alteration for improved oil recovery during lowsal injection. In this study, surfactant solubility in lowsal brine was examined by bottle test experiments. A series of core displacement experiments was conducted on nine crude oil aged Berea core plugs that were designed to determine the impact of brine composition, wettability alteration, Low Salinity Water (LSW) and LSS flooding on Enhancing Oil Recovery (EOR). Laboratory core flooding experiments were conducted on the samples in a heating cabinet at 60 °C using five different brine compositions with different concentrations of NaCl, CaCl2 and MgCl2. The samples were first reached to initial water saturation, Swi, by injecting connate water (high salinity water). LSW injection followed by LSS flooding performed on the samples to obtain the irreducible oil saturation. The results showed a significant potential of oil recovery with maximum additional recovery of 7% Original Oil in Place (OOIP) by injection of LS water (10% LS brine and 90% distilled water) into water-wet cores compared to high salinity waterflooding. It is also concluded that oil recovery increases as wettability changes from water-wet to neutral-wet regardless of the salinity compositions. A reduction in residual oil saturation, Sor, by 1.1–4.8% occurred for various brine compositions after LSS flooding in tertiary recovery mode. The absence of clay swelling and fine migration has been confirmed by the stable differential pressure recorded for both LSW and LSS flooding. Aging the samples at high temperature prevented the problem of fines production. Combined LSS flooding resulted in an additional oil recovery of 9.2% OOIP when applied after LSW flooding. Surfactants improved the oil recovery by reducing the oil-water interfacial tension. In addition, lowsal environment decreased the surfactant retention, thus led to successful LSS flooding. The results showed that combined LSS flooding may be one of the most promising methods in EOR. This hybrid improved oil recovery method is economically more attractive and feasible compared to separate low salinity waterflooding or surfactant flooding.

Effect of ionic strength in low salinity water injection processes

Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks.&#x0D; The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions.&#x0D; Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies.&#x0D; Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

Application of a new bio-ASP for enhancement of oil recovery: Mechanism study and core displacement test

The evaluations of Alkaline-Biosurfactant-Biopolymer (ABsBp) flooding for enhancement of oil recovery applications were explored. A lipopeptide biosurfactant (surfactin) and a biopolymer (schizophyllan) in combination with alkali (Na2CO3) were experimentally investigated to evaluate the possibility for EOR studies using native Omani reservoir cores and Berea core plugs. The selected oil reservoir was high permeability (500–1000 mD) sandstone type, the reservoir temperature of 50 °C, and less than 80% water cut. The crude oil was also procured from the selected Omani reservoir, having 27.15 API. The interfacial tension (IFT) values of 0.02–0.1mN/m were observed at comparatively lower biosurfactant and alkali concentrations. The effect of other chemicals and biosurfactant on biopolymer was also studied on its viscosity at reservoir temperature, and no adverse effect was observed on biopolymer performance in the presence of alkali and biosurfactant. The injection of a 0.5 PV slug of 1.1% (w/v) Na2CO3, 20% (v/v) biosurfactant (400 ppm) and 20% (v/v) biopolymer (600 ppm), followed by 3 PV of biopolymer (600 ppm) drive showed 14% and 32% of additional oil recovery from reservoir cores and Berea cores respectively. This is the first report of Alkali-Biosurfactant-Biopolymer application using surfactin and schizophyllan, showing additional oil recovery from Omani reservoir cores and Berea sandstone cores.

Effect of fines migration and mineral reactions on CO2-water drainage relative permeability

CO2-water drainage relative permeability is usually measured in laboratory using a three-stage unsteady-state flooding on cores. This three-stage flooding involves injecting water, then CO2-saturated water, and finally water-saturated supercritical CO2. The injection of CO2-saturated water has been previously found to generate fines due to mineral dissolution. The generated fines can flow with injected fluids and cause pore blockage.This paper examines the effect of fines migration and mineral reactions on CO2-water drainage relative permeability measurements, using a sintered glass core and eight Berea sandstone cores. Three-stage and two-stage flooding are performed on the cores. Three-stage flooding sequence is same as literature. Two-stage flooding involves injection only of water and then water-saturated CO2, to avoid the chemical reactions brought about by CO2-saturated water injection and thereby reduce mineral reactions. Pressure difference across the cores and volumes of water produced are recorded. These data are used to generate CO2-water drainage relative permeability functions.Inductively Coupled Plasma Optical Emission Spectrometry (ICP-OES) analysis of the produced water and Scanning Electron Microscopy (SEM) images of the cores confirm mineral reactions occurred during CO2-saturated water injection in Berea cores. For Berea cores, CO2 relative permeability is reduced (by 21%–48%) during three-stage flooding when CO2-saturated water is injected. The reduction in CO2 relative permeability is found to be a function of water salinity and pore volumes of CO2-saturated water injected. Experiments performed on the glass core suggest that the error in CO2 relative permeability caused by the absence of CO2-saturated water is negligible. Therefore, we propose that CO2-saturated water be omitted during CO2-water drainage relative permeability measurements.

Enhanced gas recovery by CO2 injection: Influence of monovalent and divalent brines and their concentrations on CO2 dispersion in porous media

This study aims to experimentally investigate the roles of different brine types and concentrations on the longitudinal dispersion coefficient (KL) during enhanced gas recovery by CO2 injection. Core flooding process was used to simulate the displacement of CH4 by supercritical CO2 in a Buff Berea core sample at a pressure and temperature of 1400 psig and 50 °C respectively, and a CO2 injection rate of 0.3 ml/min. Individual NaCl, KCl, CaCl2 and MgCl2 solutions were prepared as test brines with ionic strengths (IS) of 1M, 2M, and 3M. The results revealed that, at lower IS of 1M, MgCl2 and CaCl2 brines had the lowest KL while the monovalent brines showed relatively higher KL. Divalent brines showed a higher degree of salting out effects at higher concentrations resulting in higher KL. The salting and drying out effects of divalent brines were responsible for higher CH4 recovery at 2M IS as CH4 comes out of solution. A hyperbolic-type relationship exists between the two properties (KL and IS), where KL decreases from 0 to 1M IS, and then increases sharply at IS > 1M – this behaviour is most pronounced in the divalent brines. Lowest contamination of the recovered CH4 was found to be between formation water salinities of 5–15 wt%, regardless of salt type, during EGR by CO2 injection and sequestration. This study will not only present new knowledge on EGR process but will also provide an avenue for establishing a screening criterion based on formation water salinity for effective EGR process. This is a first experimental investigation which establishes the relationship between salt types and concentration and the KL in porous media.