Static Imbibition Experiments Research Articles

EOR mechanism of fracture oil displacement agent for ultra-low permeability reservoir

Due to the low permeability, small pore throat, and poor pore connectivity of ultra-low permeability reservoirs, fracturing was required to improve the flow environment of oil in the reservoir during its development. The combination of fracturing and oil displacement could reduce the complexity of the development of ultra-low permeability reservoirs. It was feasible to synthesize new surfactants to prepare fracturing oil displacement agents, but the research and development of new surfactants were difficult and costly. This paper aimed to experimentally investigate the imbibition displacement mechanism of fracturing flooding by combining the surfactant of chemical flooding with the fracturing fluid. With the conditions of the ultra-low permeability reservoir in block Y of Changqing Oilfield, the mechanism of remaining oil start-up and fractured oil displacement agent enhanced oil recovery in the ultra-low permeability reservoir was studied by microfluidic model experiment and NMR experiment. A mixture of fracture oil displacement agents was obtained by mixing heavy alkyl benzene sulfonate surfactant, a nonionic surfactant, and a betaine-type amphoteric surfactant. HAS-6C, HAS-5E, and HAS-5G were selected for their interfacial tension reaching 10−3 mN/m. Oil–water​ interfacial tension of HAS-5E was the lowest, which can be reduced to 10−4 mN/m. The ability to alter the wettability of HAS-6C was the most significant, which could make the contact angle go down to 64.5°. The multi-round dynamic and static imbibition experiments showed that the combination of selected surfactant and slickwater can greatly improve the imbibition recovery, of which HAS-6C could enhance oil recovery by 17%. The HAS-5E system with the lowest interfacial tension had the best effect of starting clustered residual oil, and the clustered residual oil saturation was reduced by 48.8%. The HAS-6C system with stronger wettability had the best effect of starting throat-like residual oil, and the throat-like residual saturation was reduced by 10.8%.

Experimental study of oil recovery mechanisms during imbibition in tight sandstone with different fluid displacing agents under ambient and reservoir pressure

This study explores oil recovery mechanisms of static imbibition in a tight sandstone under different imbibition pressures, simultaneously optimizing imbibition agents. To this end, the static imbibition experiments of two common agents, polyacrylamide (PAM) slick water and anion–nonionic surfactants, are conducted under atmospheric and reservoir pressure (20 MPa). The interfacial tension and contact angle of these two imbibition fluids are also measured. Herein, the entire recovery period and imbibition equilibrium time vs. pressure are determined. Based on NMR and high-pressure mercury injection measurements, the contributions of pores with different sizes to the displacement recovery during imbibition are quantified. Under atmospheric pressure, the recovery rate with the surfactant was measured higher than that of the PAM slick water. The main reason was that the former has a lower interfacial tension (0.0961 mN/m), stronger hydrophilicity (average contact angle 27.7°), and stronger oil-displacing effect. Under a reservoir pressure of 20 MPa, the surfactant had lower recovery rate than the PAM slick water, while the latter enhanced the recovery further. Under atmospheric pressure, both agents recovered the crude oil in the medium-sized and larger pores whereas, under reservoir pressure (20 MPa), they mainly recovered oil from the smaller and medium-sized pores. At higher imbibition pressures, both agents recovered more oil from the smaller and medium-sized pores, and less from micropores and larger pores. This indicated that higher pressures can further improve the driving force of fluid replacement, to improve oil production from finer and medium-sized pores significantly. Under atmospheric pressure, both agents reached imbibition equilibrium in approximately 20 days while this period was reduced for the surfactant and slick water to 16 and 12 days, respectively. Based on the results PAM slick water is recommended for EOR purposes in tight sandstone which can be generalized to similar formations around the globe.

Dynamic Imbibition Process Optimization for Ultra-low Permeability Sandstone Reservoirs

Reservoir space of ultra-low permeability sandstone reservoir has complex and special physical properties. The development performance and effects of water flooding in ultra-low permeability sandstone reservoir are determined by the permeability effect. The physical model of imbibition oil recovery is an important experimental method to optimize the formula composition of imbibition system and imbibition technology. Through a lot of oil sands static imbibition experiments for H ultra-low permeability sandstone reservoir, three better imbibition agent systems are screened out. The dynamic imbibition oil recovery technology of the reservoir is optimized by using the core dynamic imbibition experiment and comparative experimental study.

Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs

Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.

Experimental investigation on water flooding and continued EOR techniques in buried-hill metamorphic fractured reservoirs

Fractured reservoirs are complicated due to the coexistence of matrix and fracture systems. In particular, the matrix of buried-hill metamorphic fractured reservoirs (BHMFRs) has plenty of micro-fractures and a few dissolution pores rather than common pores in sandstone. The storage and heterogeneity features, such as the storage ratio between matrix and fractures, and the distribution of fractures, significantly affect the performances of waterflooding and EOR techniques. With the objective of finding effective waterflooding mode and EOR techniques in such reservoirs, the BHMFR of JZ25-1S in Bohai Bay in China was taken as an example. First, static imbibition experiments using a novel imbibition cell were conducted. Then, 3D large-scale models of BHMFRs using outcrops were designed based on the similarity criterion and employed to conduct the experiments of waterflooding and followed EOR techniques. The results show that co-current imbibition is principal and gravity is the dominant force of imbibition for BHMFRs. Because imbibition is slow, most of the yield comes from the macro-fractures. Both water-free recovery and waterflooding recovery increase as the decrease of the storage ratio of matrix to fractures. Pulsing cyclic water-injection is better than intermittently cyclic water-injection. In BHMFRs with heterogeneity of fracture density, injection in the area with low fracture density and production in the area with high fracture density can achieve better effects than the reverse scenario for both waterflooding and followed EOR techniques. If gas flooding is selected as the EOR technique, producer should be perforated at the lower layers of the reservoir. Suitable gel particles not only get a good EOR effect by effective plugging, but also can create a more favorable condition for surfactant flooding. In our experiments, another 2–4% of OOIP was produced by PPG flooding. Surfactant can enhance the oil recovery by both removing the adsorbed oil on the fracture surface and promoting imbibition in matrix. 3–5% of OOIP was recovered by surfactant flooding and soaking in our experiments.

Dynamic surfactant-aided imbibition in fractured oil-wet carbonates

Numerous studies based on static imbibition experiments at lab scale have established surfactant-aided imbibition as an improved oil recovery process for fractured oil-wet carbonate reservoirs. However, predicting performance at larger scales and at dynamic conditions (fluid flow through fracture) remains a challenge. In this study, experiments are performed on Estaillades Limestone and Texas Cream Limestone outcrop cores with varying height and diameter with permeability in the range of 8 mD to 150 mD to address this challenge. It is observed that dynamic imbibition process recovers oil faster than static imbibition. Imbibition experiments performed on cores with varying height and diameter show that oil recovery decreases with increasing diameter and height. A 3D fine grid mechanistic simulator was used to perform lab scale validation and analyze recovery mechanism. Numerically simulated velocity and saturation profiles demonstrated the recovery mechanism to be gravity dominated flow. A new scaling function is proposed for surfactant aided gravity dominated processes. Data with same boundary conditions, rock, fluids and varying dimensions can be correlated with the scaling function at early times with no fitting parameters involved. A good correlation is obtained with the data indicating the effectiveness of the scaling function. The scaling is applicable to both static as well as dynamic imbibition.

Scaling of Low-Interfacial-Tension Imbibition in Oil-Wet Carbonates

Summary Primary and secondary oil recovery from naturally fractured oil-wet carbonate reservoirs is very low. Enhanced oil recovery (EOR) from these reservoirs by use of surfactants to alter the wettability and reduce the interfacial tension (IFT) has been extensively studied for many years, but there are still many questions regarding the process mechanisms, surfactant selection and testing, experimental design, and, most importantly, how to scale up the laboratory results to the field. Therefore, the primary objective of this study was to determine the effect of scale on the oil recovery from cores with different dimensions under low-IFT conditions. There was a particular need to perform experiments by use of cores with larger horizontal dimensions because nearly all previous experiments have been performed in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static-imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the produced emulsion. We used microemulsion-phase-behavior tests to develop surfactant formulations used in this study. These surfactants gave ultralow IFT at optimum salinity and good aqueous stability. Although we used ultralow-IFT (approximately 0.002 dynes/cm) formulations for most of the experiments, we also performed tests at low IFT (approximately 0.3 dynes/cm) for comparison. A second major objective of this study was to develop a simple analytical model to predict the oil recovery as a function of vertical- and horizontal-fracture spacing, rock properties, and fluid properties. The model and experimental data were found to be in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different from the traditional scaling groups in the literature. The model is useful for both interpreting the experiments and for scaling the results from the laboratory to the field.

Evaluation of Matrix-Fracture Transfer Functions for Counter-Current Capillary Imbibition

Different functions describing matrix-fracture transfer were tested for counter-current capillary imbibition interaction. The recovery curves obtained from capillary imbibition experiments were used to fit the transfer functions. The exponential coefficients yielding the best fit to the experimental data were obtained and correlated to the effective parameters such as viscosity, IFT, matrix length and diameter, matrix permeability and porosity, and wettability using multivariable regression analysis. In order to obtain the recovery curves, experiments were conducted on Berea sandstone and Indiana limestone samples. Cylindrical samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. More than fifty static imbibition experiments were carried out on vertically and horizontally situated samples where the imbibition took place upward and lateral directions, respectively. Brine–air, brine–kerosene, brine–mineral oil, and surfactant solution–mineral oil pairs were used as fluids. For many matrix shape factors (especially longer and small diameter ones), dividing the recovery curve into three parts were needed as the early, intermediate, and late times, which are typically distinguished by the time required for the imbibition front to reach the closed boundary at the end of the core. Correlations among the exponential coefficients and rock/fluid properties were developed. It was observed that different rock/fluid properties and transfer mechanisms (capillary imbibition and gravity drainage) govern the process for each part. Hence, the analyses done in this study were useful not only for developing explicit transfer functions but also identifying the physics of the counter-current imbibition recovery.

Experimental Investigation of Effective Parameters on Efficiency of Capillary Imbibition in Naturally Fractured Reservoirs

When a matrix is saturated by a non-wetting phase, and the wetting phase fills the fracture network, capillary imbibition may occur. Capillary imbibition can be an effective recovery mechanism in water wet naturally fractured reservoirs (NFRs) where most of the oil is stored in tight matrix blocks.This paper presents the results and analysis of the laboratory experiments with variable parameters such as oil type, rock composition, temperature, permeability, porosity and fluid that invades the matrix. To investigate temperature effect on the efficiency of capillary imbibition mechanism, capillary imbibition tests were conducted under static conditions and at different temperatures, namely 22, 50 and 80°C by using crude oils and carbonate samples taken from the same reservoirs. Also variable core sizes were used to study the block size effect on the oil recovery.The results of static imbibition experiments show that rock and oil properties are the dominant parameters in capillary imbibition. Furthermore, increasing the operational temperature also has a positive role in the process. Therefore, in thermal EOR methods, oil recovery increases due to the enhancement of the imbibition mechanism. Also the lighter oil show high sensitivity to capillary imbibition mechanism than the heavier one and using brine instead of pure water decreased the amount of oil recovery through capillary imbibition.

Primary and Secondary Oil Recovery From Different-Wettability Rocks by Countercurrent Diffusion and Spontaneous Imbibition

Summary This study investigates optimum matrix-oil-recovery strategies in naturally fractured reservoirs (NFRs) for different wettabilities and rock types. We compare the recovery efficiencies of two cases: (a) primary countercurrent spontaneous imbibition followed by the diffusion of a miscible phase (secondary recovery) and (b) primary diffusion of miscible fluid without preflush of matrix by spontaneous imbibition. For these recovery strategies, the effects of the matrix shape factor, matrix wettability, and type of miscible displacing phase on the rate of recovery and development of residual-oil saturation were clarified experimentally. Cylindrical Berea-sandstone and Indiana-limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. The external surface except one end was coated with epoxy. Static imbibition experiments were conducted on vertically situated samples in which the fractures were at the bottom and matrix/fracture interaction took place in an upward direction. Mineral oil and crude oil were used as oleic phases. Brine was selected as aqueous phase for the primary spontaneous-imbibition recovery. For primary- and secondary-miscible-displacement experiments, n-heptane was used as solvent. Wettability of water-wet Berea-sandstone samples was altered by aging to observe its effects on the dynamics of spontaneous countercurrent imbibition and diffusion. Parametric analyses were performed for the appraisal of the secondary-and tertiary-recovery potential of NFRs by immiscible-and miscible-fluid injections. The optimal recovery strategies (recovery rate, recovery time, and ultimate recovery) for different rock properties were identified and classified. In water-wet cases, starting the recovery with capillary imbibition followed by diffusion was found to be the optimal way (i.e., both effective and efficient). For limestone or aged-sandstone samples, starting the recovery by diffusion yielded a faster recovery rate and higher ultimate recovery.

Oil recovery by counter-current spontaneous imbibition: Effects of matrix shape factor, gravity, IFT, oil viscosity, wettability, and rock type

The effects of the matrix shape factor, wettability, gravity, rock type, oil viscosity, and interfacial tension on the rate of capillary imbibition and development of residual non-wetting phase saturation were studied experimentally in this paper. Experiments were conducted on Berea sandstone and Indiana limestone samples. Cylindrical samples with different shape factors were obtained by cutting the plugs 1/2, 1 and 2 in. in diameter and 2, 4, and 6 in. in length. All sides were coated with epoxy except one end to ensure counter-current interaction. Static imbibition experiments were conducted on vertically and laterally situated samples to incorporate the effect of gravity where the imbibition took place upward and lateral directions, respectively. Brine-kerosene, brine-mineral oil and surfactant solution-mineral oil pairs were used as fluids. The rate of imbibition was evaluated for different matrix size, shape factor, wetting/non-wetting phase types and IFT. Conditions at which the shape factor controls the residual oil development were identified. It was observed that the residual oil after capillary imbibition is influenced by the matrix shape factor for the vertically positioned samples (unlike horizontal samples). In the low IFT experiments, surfactant was found to play a strong role on the rate of imbibition and the development of residual oil saturation. Scaling analyses were performed testing and comparing four different scaling groups. The equations were modified to take wettability and gravity effects into account. A new empirically correlated-gravity sensitive characteristic length was introduced.

Analysis of counter-current gas–water capillary imbibition transfer at different temperatures

Gas water counter-current matrix–fracture interaction due to capillary forces was studied. The focus was on the rate of capillary imbibition and the development of residual gas phase under low (20 °C) and high temperatures (90 °C). Berea sandstone and Indiana limestone samples with different shape factors were obtained by cutting the plugs 1, 2.5, and 5 cm in diameter and 2.5, 5, and 10 cm in length. All sides were coated with epoxy except one end. Static imbibition experiments were conducted on vertically and horizontally situated samples where the matrix–fracture interaction took place upward and lateral directions, respectively. The effects of the matrix shape factor, wettability, surface tension, and core position on the recovery rate and ultimate recovery were investigated. The experimental scheme followed was useful in identification of the development of residual gas saturation for fully counter-current matrix–fracture interaction. We investigated and clarified to what degrees the rock/fluid properties (wettability and matrix shape factor) and existing conditions (temperature, causing lowered IFT and brine viscosity, and gravity) become effective on the residual gas saturation. It was observed that the residual gas saturation is sensitive to the matrix shape factor. The effect of surface tension on the recovery rate and ultimate recovery was also critical. The vertical cases yielded different recovery rates and ultimate recoveries with increasing temperature. Lower residual gas saturation with increasing temperature was obtained only for large diameters. That was attributed to the reduction in surface tension. Finally, critical matrix and fluid properties were correlated to the residual gas saturation and different dimensionless groups were tested for scaling.

Dynamics of Capillary Imbibition When Surfactant, Polymer, and Hot Water Are Used as Aqueous Phase for Oil Recovery

Capillary imbibition is an oil recovery mechanism in naturally fractured reservoirs if rock matrix is water wet and there is enough water in fractures in contact with matrix. It, however, may not yield an effective recovery under certain circumstances even if these conditions are maintained. Heavy matrix oil, high interfacial tension (IFT), oil-wet matrix sample, and limited contact area of matrix with water in fractures require additional effort to enhance the oil recovery by capillary imbibition. Chemicals and heat can be injected into naturally fractured reservoirs to improve the capillary imbibition recovery performance. With the involvement of low IFT fluid, heat, and polymer solution in the process, capillary imbibition dynamics may change and this entails an identification of the dynamics of the process through laboratory experiments before injection of these expensive fluids into oil reservoirs. In this study, the dynamics of capillary imbibition was studied experimentally. Static imbibition experiments were conducted on oil- and water-wet rock samples under different boundary conditions and saturated with different types of oil. The analyses were conducted using three indicators, namely the capillary imbibition rate, ultimate oil recovery, and shape of the recovery profile. Based on these indicators, the dynamics of capillary imbibition of different aqueous phases were evaluated for different oil types and matrix properties. The conditions that cause weak or strong capillary imbibition were identified.

Scaling capillary imbibition during static thermal and dynamic fracture flow conditions

To incorporate the effect of temperature, previously reported scaling formulations were modified considering the wettability, change in oil properties, and thermal expansion. The results of static imbibition experiments conducted using different types of heavy-oil samples at different temperatures up to 90 °C were used to verify the formulation. The modified scaling formulations responded well if the thermal expansion effect is included, except in high-temperature crude oil imbibition cases. The results obtained through water injection experiments in artificially fractured core samples with matrix permeabilities ranging from 300 to 0.075 mD were used to verify the numerical model of core scale displacements. Then the convergence constant in Aranofsky's abstract recovery–time relationship was correlated to an imbibition group consisting of the injection rate and matrix properties. Three different formulations were presented and tested. Good agreement with the experimental observations could be achieved when the wettability and permeability of the matrix and the flow rate in fracture is included in the formulations. When the matrix size is included in the regression analysis, not all correlation types yielded a good agreement with the experimental data. This study will provide an insight into the scaling of the laboratory scale experiments to the reservoir conditions and constitute a base to define matrix fracture interaction in numerical models dealing with fractured reservoir modeling.