Lower Residual Oil Saturation Research Articles

Optimization of Discontinuous Polymer Flooding Processes for Offshore Oilfields Using a Novel PSO–ICA Algorithm

Recently, discontinuous polymer flooding has been proposed and successfully applied in some offshore oilfields. The performance of discontinuous polymer flooding depends on various operational parameters, such as injection timing, polymer concentrations, and crosslinker concentrations of four types of chemical slugs. Because the number of the operational parameters are large and they are nonlinearly related, the traditional reservoir numerical simulation might not simultaneously obtain the optimal results of these operational parameters. In this study, to simulate the discontinuous polymer flooding processes, a simulation model was built using a commercial reservoir simulator (CMG STARS), in which the mechanisms of the four types of chemical slugs were considered, such as polymer viscosification, adsorption, and degradation. Then, a PSO–ICA algorithm was developed by using the PSO algorithm to improve the exploration ability of the ICA algorithm. The codes were written with MATLAB and linked to CMG STARS to perform optimization processes. Finally, the PSO–ICA algorithm was compared with the ICA and PSO algorithms on benchmark functions to verify its reliability and applied to optimize a discontinuous polymer flooding process in a typical offshore oilfield in Bohai Bay, China. The results showed that the developed PSO–ICA algorithm had lower iteration numbers, higher optimization accuracy, and faster convergence rate than these of PSO and ICA, indicating that it was an effective method for optimizing the operational parameters of discontinuous polymer flooding processes. Compared to the continuous polymer flooding, the discontinuous polymer flooding had a higher oil production rate, a lower water cut, and a lower residual oil saturation. The net present value of the optimal scheme of discontinuous polymer flooding reached 7.49 × 108 $, which is an increase of 6% over that of the scheme of continuous polymer flooding. More research including selecting more reasonable parameters of the PSO–ICA algorithm to increase its optimization accuracy and convergence rate, comparing with other available optimization algorithms, and verifying the performance of the optimal scheme of discontinuous polymer flooding in the practical offshore oilfield will be required in the future.

Iso-Permeability Point Trail Method to Determine the Relative Permeability Curve for a New Amphiphilic Polymer Flooding

Amphiphilic-polymer flooding, which can increase water viscosity, decrease oil viscosity, and improve oil displacement efficiency, is a promising oil exploitation method for heavy oil. Due to oil–water emulsification, shear-thinning, and changes in oil viscosity when determining the relative permeability data of new amphiphilic polymers, the conventional J.B.N. method is not accurate. This paper presents a new method called the iso-permeability point trial method to determine the relative permeability curve by combining the J.B.N. method, the Corey model, and the relationship between water saturation and the relative permeability ratio. To avoid using polymer viscosity, a mathematical equation was derived based on the characteristics of the relative permeability curve. The results indicate that the new method is feasible and the obtained curve is more reasonable and smooth. The influence of concentration, permeability, and oil viscosity on amphiphilic-polymer displacement relative permeability was also analyzed, demonstrating that under the same water saturation, the water relative permeability is lower than that of water flooding but the oil relative permeability is bigger, which manifests as the iso-permeability point moves to the right and results in a lower residual oil saturation. In addition, the aforementioned trends are more obvious when the amphiphilic-polymer concentration is high, formation permeability is low, and oil viscosity is low.

Dealing with unique minerals in petrophysical logs

Most petrophysical equations and methods are designed to deal with hydrocarbons found within mineralogies, such as quartz and feldspars or calcite and dolomite. Petrophysical tools and techniques have also largely been designed to investigate rocks containing these minerals. Hence, when log analysts encounter a field containing unique mineralogies, determining an appropriate petrophysical evaluation process for such unconventional reservoirs can be a challenge. In this paper, we aim to discuss our learnings using two unique case studies. The first is a well which had intersected opalines and logged with conventional modern “western style” tools. The second is a well which has intersected tuffs and volcanics and which was logged with older “Russian style” tools.For opalines, we discuss the potential mineral signatures observed on the well log data and the reservoir potential of the rocks. We find that the unique microporous structure created by opal-CT microspheres/lepispheres, combined with either fracture or matrix-porosity dominant properties, potentially allows for storage of hydrocarbons within the rock. Hence, we hypothesize that opaline reservoirs could be classed as “Low Resistivity Low Contrast” (LRLC) pay and should not be glossed over just because typical hydrocarbon indicators are not seen.For tuffs and volcanics, we first share some of the challenges faced and methods used in conducting modern petrophysical interpretation with data from older Russian-style logs. Again, we discuss the potential mineral signatures observed on the logs and look at properties such as pore throat radii, size, and mineral composition and how that affected reservoir potential. Our findings indicate that the distribution of pore sizes allowed for greater connectivity within the rock, where the pore geometry effects aided in low residual oil saturations.

Modeling of multiphase flow in low permeability porous media: Effect of wettability and pore structure properties

Multiphase flow in low permeability porous media is involved in numerous energy and environmental applications. However, a complete description of this process is challenging due to the limited modeling scale and the effects of complex pore structures and wettability. To address this issue, based on the digital rock of low permeability sandstone, a direct numerical simulation is performed considering the interphase drag and boundary slip to clarify the microscopic water-oil displacement process. In addition, a dual-porosity pore network model (PNM) is constructed to obtain the water-oil relative permeability of the sample. The displacement efficiency as a recovery process is assessed under different wetting and pore structure properties. Results show that microscopic displacement mechanisms explain the corresponding macroscopic relative permeability. The injected water breaks through the outlet earlier with a large mass flow, while thick oil films exist in rough hydrophobic surfaces and poorly connected pores. The variation of water-oil relative permeability is significant, and residual oil saturation is high in the oil-wet system. The flooding is extensive, and the residual oil is trapped in complex pore networks for hydrophilic pore surfaces; thus, water relative permeability is lower in the water-wet system. While the displacement efficiency is the worst in mixed-wetting systems for poor water connectivity. Microporosity negatively correlates with invading oil volume fraction due to strong capillary resistance, and a large microporosity corresponds to low residual oil saturation. This work provides insights into the water-oil flow from different modeling perspectives and helps to optimize the development plan for enhanced recovery.

A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs

Summary Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoir that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, carbon dioxide (CO2) enhanced oil recovery (EOR) has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artifacts, long cores were used in the experiments, and to observe the effect of gravity, both 2 in. diameter and 4 in. diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by aging the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, and both CO2 and a mixture of 50% C1 and 50% CO2 were used as miscible injectant. All gas injection experiments were performed using vertically oriented cores, and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are as follows: The effect of miscibility on oil recovery for both continuous gas injection and water alternating gas (WAG). The effect of gravity on gas sweep efficiency compared to waterflooding. The effect of gas-oil interfacial tension (IFT) on oil recovery when using the same oil. The effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions. The effect of immiscible gas injection on subsequent miscible gas injection performance. Impact of CO2 cycle length on ultimate oil recovery. The impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are as follows: As expected, miscibility has a significant impact on displacement efficiency and oil recovery where miscible gas recovered more than 20% extra oil compared to immiscible gas. A significant variation in oil recovery is observed for miscible gas injection (i.e., more than 10 saturation units difference) depending on the minimum miscibility pressure (MMP) between the injected gas and crude oil, even when both experiments are performed at miscible conditions using the same injected gas. The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. During WAG experiments, starting the injection cycles with water or gas did not have any impact on the ultimate oil recovery for both miscible and immiscible cases for one of the reservoirs, while WAG_G (WAG starting with gas injection) recovered more oil for another reservoir. Gravity has a significant impact on oil recovery for both miscible and immiscible gas injections. A significant difference is observed in oil recovery when comparing CO2 injection on 2-in.- and 4-in.-diameter core samples or when comparing horizontal vs. vertical immiscible gas injection and WAG experiment. The longer the CO2 slug size, the higher the oil recovery observed in gas injection experiments. The results of this study provide a rich and rarely available set of experimental data that can help improve and optimize gas and WAG injection in oil-wet carbonates.

Effect of Heterogeneity on Capillary Pressure and Relative Permeability Curves in Carbonate Reservoirs. A Case Study for Mishrif Formation in West Qurna/1 Oilfield, Iraq

The special core analysis tests were accomplished on a set of core plugs for Mishrif Formation (mA, mB1, and mB2cde/mC units) in West Qurna/1 oilfield, southern Iraq. Oil relative permeability (Kro) data and the Corey-type fit of the data as functions of the brine saturation at the core outlet face for individual samples in the water-oil imbibition process to estimate relative permeability measurements by the centrifuge method were utilized. Identical correlations for oil and water relative permeabilities were extracted by steady-state and unsteady-state methods. For the mA samples, the gas-water capillary pressure curves were within a narrow range (almost identical) indicating that mA is a homogeneous unit. Kro curves for three mB2ab plugs were practically identical, that is referring to the homogeneity in the upper portion of the unit. The mB2 unit has a more solid‐phase concentration than other units. In addition, the general trend of low residual oil saturation is related to the raising in porosity but no reliable correlation between the residual oil saturation to water drive (Sorw) and Klinkenberg-corrected permeability (Kinf). Based on the correlation between the effective oil permeability at the initial water saturation [ko(Swi)] and (Kinf/f)1/2 for the high-permeability lithofacies mB1 plugs, ko(Swi) is approximately equal to or exceeds Kinf. While ko(Swi) was below Kinf for the other samples. New good empirical equations were obtained for effective gas permeability at final water saturation versus Kinf, as well as, for Kro and Krw versus saturation for all lithofacies.

Experimental evaluation of microscopic pore structure and fluid migration characteristics of coal-measure sandstone reservoirs

Research on the microscopic migration characteristics of fluids in coal measure sandstone has always been a hot spot in the evaluation of reservoir properties. In this study, taking the Yan’an Formation sandstone reservoirs in the Block A of the Ordos Basin as an example, the pore structures and fluid migration characteristics of coal-measure sandstones are systematically studied using a large number of thin sections, SEM (Scanning Electron Microscope), NMR (Nuclear Magnetic Resonance), relative permeability and water-flooding test results. The results show that the Jurassic sandstones in the target layer mainly develop lithic quartz sandstone, and the main pore types are intergranular and dissolution pores, followed by a small amount of intercrystalline pores. The surface porosity of the target sandstones mainly ranges from 7.90 to 10.79%, with an average value of 8.78%. The good correlation between porosity and permeability indicates that the target layer is a pore-type reservoir. The T2 relaxation time of the target layer is mainly distributed within 100 ms. Moreover, the reservoir of the Yan’an Formation has a high saturation of movable fluids, which is mainly distributed in 43.17–71.24%, with an average value of 56.90%. Meanwhile, samples with fractures have higher movable fluid saturations. In addition, the average irreducible water saturation of the Yan’an Formation sandstone reservoir is 35.14%, and the final oil displacement efficiency is 51.14% on average. There is a good positive correlation between the oil displacement efficiency and the co-permeability zone. As the co-permeability zone range increased from 15 to 55%, the oil displacement efficiency increased from 30 to 65%. When the cores develop fractures, they have characteristics of high permeability, high oil recovery rate, high oil displacement efficiency in the anhydrous period, low irreducible water saturation and low residual oil saturation.

Low retention surfactant-polymer process for a HTHS carbonate reservoir

Development of surfactant formulations for high temperature (100 °C), high salinity (>50,000 ppm) and especially high hardness (>2000 ppm) reservoirs is challenging. Alkali-surfactant-polymer processes have been developed in the past, but requires soft injection brine. The objective of this work is to develop a surfactant-polymer (SP) process for a high temperature, high salinity (HTHS) reservoir that can be injected with available hard brines (such as sea water) to achieve ultra-low IFT, low residual oil saturation, and low surfactant retention in carbonate rocks. Phase behavior experiments were performed to identify a combination of anionic and zwitterionic surfactants. Four tertiary chemical corefloods were conducted in Indiana Limestone cores to test oil recovery and surfactant retention. A copolymer containing acrylamido-tertiary-butyl sulfonate, SAV10xv was identified to be stable at this HTHS condition. Sodium polyacrylate (NaPA) was identified as a sacrificial chemical to reduce surfactant adsorption. The chemical floods were successful in reducing the residual oil saturation to 8–11%. A preflush of NaPA reduced the surfactant retention from 0.133 mg/g to 0.017–0.038 mg/g of rock. Including the NaPA in the chemical slug was not as effective. The use of this surfactant formulation with a preflush of sodium polyacrylate can enhance the oil recovery in high temperature, high salinity carbonate reservoirs with very low surfactant retention.

Miscibility tracking in reservoirs with lateral compositional variation

Miscible gas injection is a proven enhanced oil recovery method for medium-light oils. Miscibility is typically assessed with the slimtube experiment, which aims at identifying the minimum pressure (MMP) above which the displacement process is multi-contact miscible and leads to low microscopic residual oil saturation. During implementation of a miscible gas injection scheme, there will often be areas close to producing wells where the reservoir pressure is below the MMP and the question then arises whether the process can still be considered miscible. Another complicating factor occurs in reservoirs with significant lateral fluid composition and pressure variations, where it is not intuitively clear how the MMP varies aerially.We employ 1D compositional reservoir simulation to investigate the impact of flowing bottom-hole pressures below MMP on the development and propagation of a miscible front. For systems with lateral fluid variation, we find that MMP is controlled by the reservoir fluid composition near the injection well as the injection gas will never actually contact the original fluid near the producer. We also find that a miscible displacement can be maintained even if the average reservoir pressure is slightly below MMP, as long as the local pressure at the gas-oil front exceeds MMP. Lastly, we define the minimum density difference as the overall minimum over time of the difference between oil and gas density observed at a fixed point in the system and we demonstrate that it extrapolates towards zero linearly versus pressure for the fluid systems investigated thereby enabling determination of the dispersion-free MMP with a maximum of three pressure iterations only.

Electrostatic Effect on Core-Shell Micro-spheres with Mixed Charges as Adaptive Plugging Agents for Enhanced Oil Recovery.

Core–shell micro-spheres (MS) with both negative and positive charges in the core and only negative charges in the shell were developed as adaptive plugging agents for in-depth conformance control for enhanced oil recovery. The MS were designed to propagate deeply into the reservoir due to the small particle size and electrostatic repulsion between the MS and the sandstone at the initial stage of injection and form aggregates by electrostatic attraction between the cores with mixed charges when the shells degraded at a given time during transportation, leading to an effective plugging of the highly permeable layers with low residual oil saturation. The self-assembling and plugging behaviors of the MS have been studied by Monte Carlo simulation. The results show that charge density (Dcharge), fraction of positive charge (Fp), MS concentration, temperature, and salinity are the key factors influencing the self-assembling behaviors. The electrostatic interaction would become stronger with the increase in Dcharge when it is larger than 0.5. The MS are more likely to form aggregates when Fp approaches 0.5. The higher the concentration of the MS, the stronger the electrostatic interaction between the MS. In addition, electrostatic interactions between the MS become stronger with the increase in temperature and decrease in salinity. Simulation results prove that the MS with mixed charges can effectively and adaptively plug highly permeable layers with low residual oil saturation through self-assembling by combination of electrostatic interactions along with physical bridging, leading to the improvement of oil recovery. Furthermore, block charge distribution will be helpful for the MS with mixed charges to form larger aggregates than that of the random mode to effectively plug the highly permeable layers.

Oil production performance and reservoir damage distribution of miscible CO2 soaking-alternating-gas (CO2-SAG) flooding in low permeability heterogeneous sandstone reservoirs

Miscible CO 2 -SAG flooding is an enhanced form of CO 2 flooding, which mitigates the inadequate CO 2 -crude oil interaction by adding a CO 2 soaking period just after CO 2 breakthrough (BT). The addition of the soaking process results in improvements in the recovery of residual oil during the secondary CO 2 flooding process, which may vary across the reservoir, and lead to differential changes in the distribution of permeability decline and wettability variation due to asphaltene precipitation. In this work, CO 2 -SAG and simple miscible CO 2 flooding experiments were carried out at reservoir conditions (90 °C, 23 MPa) on low permeability long composite cores with progressively decreasing permeability in the direction of injection. The results show that the overall oil recovery factor (RF) was 72.8% after CO 2 -SAG flooding, 11% higher than simple miscible CO 2 flooding (61.8%). The oil RFs of individual core plugs decreased progressively along the core (i.e., with decreases in initial permeabilities). The inadequate interaction occurs more for those cores with low permeability and high residual oil saturation close to the outlet. Consequently, recovery is improved more in lower permeability cores, particularly in medium sized pores of these cores. By contrast, the permeability decline of core plugs after CO 2 -SAG flooding was 8–20%, 1.0–4.5% higher than that after simple miscible CO 2 flooding. The permeability decline of the cores close to the injection end showed a slight increase, and continued to decrease along the injection direction after CO 2 flooding. However, the overall decline in core permeability at the injection end was greater than that at the outlet. The soaking process led to a more homogeneous distribution of permeability decline and a greater increase in permeability decline. The distribution of wettability variation was consistent with the distribution of residual oil saturation after CO 2 flooding. The wettability variation was larger and the cores in middle had the biggest values after SAG flooding. • Oil recovery is improved more for lower permeability cores at the outlet, particularly in medium sized pores after SAG flooding. • The soaking process leads to a greater increase in permeability decline due to asphaltene precipitation. • The distribution of wettability variation is consistent with the distribution of residual oil saturation after CO 2 flooding.

CFD Simulation of the Oil Displacement in Micromodel for Enhanced Oil Recovery Application

Diminishing hydrocarbon reserves in oil reservoirs and the need to sustain continuous oil production have prompted researchers to further investigate Enhanced Oil Recovery (EOR) techniques. Researchers also test run these processes before EOR fluid injection into the reservoir to maximise oil production whilst minimising reservoir damage and fluid loss. This study aims to simulate oil displacement during the injection of two different types of EOR injection fluid, namely of water and polymer, using a commercial CFD software known as ANSYS Fluent. A heterogeneous 2D micromodel that has randomised pore network was selected as the basis of the flow system. By doing so, it is hoped to replicate a reservoir prototype using an innovative approach in a 2D geometry that appropriately simplifies complex reservoir properties represented. Initially, micromodel is fully saturated with crude oil. Then, water and polymer are injected separately on a case-to-case basis at flowrate of 0.8 mL/min. Visual inspection of the phase fraction contour results found that polymer flooded micromodel had smaller regions of oil volume fraction as compared to that of water flooded micromodel. Polymer flooded micromodel also had smaller and more branched fingering front as compared to water flooded micromodel. The analysis found that polymer flooding had better oil displacement efficiency as compared to traditional water flooding due to higher mobility ratio, reduced viscous fingering and lower residual oil saturation.

Pore-scale imaging of displacement patterns in an altered-wettability carbonate

High-resolution X-ray imaging combined with a steady-state flow experiment is used to demonstrate how pore-scale displacement affects macroscopic properties in an altered-wettability microporous carbonate, where porosity and fluid saturation can be directly obtained from the grey-scale micro-CT images. The resolvable macro pores are largely oil-wet with an average thermodynamic contact angle of 120°. The pore-by-pore analysis shows locally either oil or brine almost fully occupied the macro pores, with some oil displacement in the micro-porosity. We observed a typical oil-wet behaviour consistent with the contact angle measurement. The brine tended to occupy the larger macro pores, leading to a higher brine relative permeability, lower residual oil saturation, than under water-wet conditions and in a mixed-wet sandstone. The capillary pressure was negative and seven times larger in the carbonate than the sandstone, despite having a similar average pore size. These different displacement patterns are principally determined by the difference in wettability.

Capillary desaturation curve: does low salinity surfactant flooding significantly reduce the residual oil saturation?

Different oil displacement experiments conducted on sandstone and carbonate samples show that low salinity water (LSW) injection can reduce the residual oil saturation (ROS). Recently, surfactant flooding (SF) in combination with low salinity water (known as low salinity surfactant (LSS) flooding) is proposed as a potentially promising hybrid enhanced oil recovery (EOR) process. A lower ROS is reported for a LSS process compared to that seen in SF or with LSW at the same capillary number. The capillary desaturation curve (CDC) is a well-known tool to study the effect of viscous and capillary forces on ROS for different EOR techniques. In this study, ROS data of various LSW, SF, and LSS flooding experiments at different capillary numbers are collected to develop a CDC to analyze the performance of the hybrid LSS method. This can help to analyze the effect of the hybrid method on an extra improvement in sweep efficiency and reduction in residual oil. A lower ROS is observed for LSS compared to LSW and SF in the same capillary number range. Our study shows different behaviors of the hybrid method at different ranges of capillary numbers. Three regions are identified based on the capillary number values. The difference in ROS is not significant in the first region (capillary number in the range of 10−7–10−5), which is not applicable in the presence of surfactant due to the low interfacial tension value. A significant reduction in ROS is observed in the second region (capillary number in the range of 10−5–10−2) for LSS compared to SF. This region is the most practical range for SF and LSS flooding. Hence, the application of LSS provides a noticeable benefit compared to normal EOR techniques. In the third region (capillary numbers greater than 10−2), where the surfactant flooding is a better performer, the difference in ROS is negligible.

Understanding the behavioral trends of the effect of water salinity and sand size on oil recovery in sandstone reservoirs

Enhanced oil recovery techniques are deployed to subsequently improve oil production having already employed primary or secondary recovery techniques or both methods simultaneously. Literature have shown that salinity impacts on oil recovery due to wettability alteration, but grain size which is closely related to the mechanical behavior and petrographical properties is also one of the main parameters controlling the phenomenon. There is need to investigate the effect of these two parameters in oil recovery. This study considered the effects of water salinity in the range of 0 to 20,000 ppm and sand grains of 45 to 300 µm on oil recovery. Flooding experiments and statistical analyses of the designed experiment was used to determine the residual oil saturation. The properties of sand samples such as bulk and pore volumes, porosity as well as, wet and dry weight for the various groups were also analyzed. Gauss-Newton algorithm with Levenberg-Marquardt modifications were the numerical scheme executed in MATLAB to formulate residual oil saturation model. The optimum percentage recovery for the core flooding experiment in each groups are 82.4%, 81.1%, 79.4%, 81.1% and 78.8% for A4, B4, C4, D4 and E5 respectively. Based on the experimental results, the 300 µm sand grains and salt concentration of 15,000 ppm should be used for operations in this reservoirs because, those conditions guarantee oil recovery as high as 82%. High oil recoveries correspond to low residual oil saturation and vice-versa. The recovered residual oil percentage had no direct correlations with the net dry and wet weights of the samples. The 45-micron grains had the least pore volume and it was observed that the percentage recoveries had no direct correlations with the core sample weights. During validation of the formulated residual oil saturation model, the model gave a good prediction of the experimental data within the 95% confidence interval, and from the statistical analyses, residual oil saturation decreased with decrease in water salinity. Thus, the larger the size of a grain, the lower its superficial area exposed to the wetting and non-wetting fluids which subsequently impacts on oil recovery.

Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions

Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature which indicated better connectivity of the phases, consistent with the lower residual oil saturation. Mean curvature and associated capillary pressure were positive for the water-wet case but decreased to a negative value for the mixed-wet case pointing to forced displacement from oil-wet pores. This analysis explained why the relative permeabilities for the mixed-wet case were lower than for the water-wet case for the same fractional flow.

Impacts of pore structure and wettability on distribution of residual fossil hydrogen energy after imbibition

Due to the heterogeneity of the pore structure, there is still much residual fossil hydrogen energy in the pore space. In this study, the distribution of residual fossil hydrogen energy after imbibition with liquid nanofluid (LNF) has been studied through the. Firstly, relevant properties of the LNF were tested, including particle size, wettability alteration, and interfacial tension (IFT). Then, one micromodel under both oil-wet and water-wet conditions was used to elucidate the difference of residual oil after imbibition. Moreover, the difference of imbibition processes with oil-wet and water-wet models was further studied. Finally, the influence of dimensions and coordination numbers of pores was investigated. Besides, the impact of fluid type on imbibition efficiency was also compared through microfluidic experiments. Results show that the residual oil saturation is significantly higher in the oil-wet micromodel than in the water-wet micromodel, even the wettability alteration additive was used. There are four kinds of locations for residual oil after imbibition in water-wet micromodel, while only three kinds of locations for residual oil in oil-wet micromodel. The imbibition rate and residual oil saturation in small pores are higher than the larger ones. Due to the unbalanced force at pore throats, a micromodel with a high coordination number has lower residual oil saturation. Besides, the lower residual oil saturation is obtained by adding the LNF. This paper provides a micro-visual method to understand the imbibition process under different wettability and pore structures in fossil hydrogen reservoirs.

Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock

Differential imaging X-ray microtomography combined with a steady-state flow apparatus was used to elucidate the displacement processes during waterflooding. We simultaneously measured relative permeability and capillary pressure on a carbonate rock sample extracted from a giant producing oil field. We used the pore-scale images of crude oil and brine to measure the interfacial curvature from which the local capillary pressure was calculated; the relative permeability was found from the imposed fractional flow, the image-measured saturation, and the pressure differential across the sample.The relative permeabilities indicated favourable oil recovery for the mixed-wettability conditions. The pore-scale images showed that brine started to flow through pinned wetting layers, micro-porosity and water-wet pores, and then filled the centre of the larger oil-wet pores. Oil was drained to low saturation through connected oil layers. The brine relative permeability remained low until brine invaded a connected pathway of smaller throats at a high brine saturation. The interface between the oil and brine had a small average curvature, indicating a low capillary pressure, but we observed remarkable saddle-shaped interfaces with nearly equal but opposite curvatures in orthogonal directions. This implies good oil phase connectivity, consistent with the favourable recovery and low residual oil saturation attained in the experiments.This work illuminated displacement processes from both macro-pores and micro-pores which have important implications for improved oil recovery and, potentially, on carbon storage. In future, the measured relative permeability, capillary pressure and pore-scale fluid distribution could be used to benchmark and validate pore-scale models.

Experimental Program Investigates Miscible CO2 WAG Injection in Carbonate Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 188471, “Experimental Data Acquisition and Modeling for the Study of Miscible CO2 WAG in Carbonate Reservoirs Under Oil-Wet Conditions,” by T. Joubert, S. Duchenne, M. Bourgeois, SPE, R. de Loubens, SPE, and M. Petitfrere, Total, prepared for the 2017 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 13–16 November. The paper has not been peer reviewed. Prediction of miscible water-alternating-gas (WAG) injection performance relies on proper calibration of thermodynamical and petrophysical models. Swelling, miscibility, and stripping phenomena must be captured in the equation of state (EOS), and the oscillations of gas and water saturations require using history-dependent relative permeabilities. This paper provides a robust methodology for miscible CO2 WAG experimental-data acquisition and history matching. Introduction Miscible CO2 injection in oil reservoirs leads to low residual oil saturations in the swept areas. However, macroscopic sweeping can be poor because of the high mobility of CO2. One way of improving macroscopic sweep is to inject CO2 in the presence of mobile water to reduce its mobility (in tertiary or WAG modes). The prediction of WAG efficiency and the sizing of surface installations rely partly on the ability of the three-phase relative-permeability model to calculate proper mobility for each phase in any part of the reservoir. Numerous three-phase relative-permeability models have been proposed in the literature. Among these models, one proposed by Larsen and Skauge (1998) is considered by the authors as a starting point for simulation work. The experimental program discussed in this paper was launched in order to clarify several points, including the existence and the amplitude of residual oil saturation in miscible flooding and the validity of existing three-phase models. Experimental-Program Definition for WAG Study The experimental program is composed of several coreflooding experiments performed at reservoir conditions of 260 bar and 94°C. Materials and methods are discussed in detail in the complete paper. Flow Regions and Saturation Paths. WAG mechanisms involve alternating two fluids of different density and mobility properties at the injection well. These differences lead to gas migration toward the top of the reservoir. The consequence is a large variability of flow sequences in space as illustrated in Fig. 1, which shows a cross section between two vertical wells from a WAG phenomenological simulation. Several saturations paths were extracted to identify six flow regions that can be grouped into three categories: Two-phase flow with monotonous saturations variations (Flow Regions 1 and 2) Two-phase flow with oscillating saturations (Flow Regions 3 and 4) Three-phase flow with oscillating saturations (Flow Regions 5 and 6) Depending on reservoir properties and the development plan, the proportions between these flow regions can vary significantly and should be assessed for a given reservoir before the experimental-program definition. A reliable three-phase relative-permeability model should be valid over each flow region, or at least over the most significant one for a given case.

An investigation into polymer flooding in high temperature and high salinity oil reservoir using acrylamide based cationic co-polymer: experimental and numerical simulation

In this study, the new type of polymer was considered for rheological study and core flooding test in high temperature and high salinity (HTHS) condition. This polymer is called co-polymer Zetag 8187G which is used as flocculant in water industry. By studding the rheological properties of this polymer compared to one of the commercial polymer for HTHS condition, Zetag 8187G was considered for polymer flooding in sandstone core at 185 °F and 150,000 ppm of salinity in present of divalent ions (Ca2+, Mg2+) in experimental and simulation cases due to better stability compared to other. The core flooding results showed this co-polymer swept the oil toward low residual oil saturation in porous media. In addition, the core flooding results showed that was not occurred significant damage in rock during polymer flooding using Zetag 8187G. More than, in the simulation case, the change of relative permeability curve during water and polymer flooding was obtained using history matching of production data. The experimental and simulation results show this polymer can applicable in oil industry as well as application in water industry.