Low Salinity Waterflooding Research Articles

Role of Monovalent and Divalent Ions in Low-Salinity Water Flood in Carbonate Reservoirs: An Integrated Analysis through Zeta Potentiometric and Simulation Studies

The presence of principal ions in the water injected is essential for enhanced oil recovery by formation of water-wet state in carbonates. This study reaffirms this and presents an evaluation of the positive influence of both divalent as wells as monovalent ions on wettability alteration mechanisms during low salinity waterflooding using brines of varying ionic composition, referred to as “smart brines”. Zeta potentiometric analysis and reservoir simulation studies were conducted with diluted and smart brines that were prepared by varying the composition of principal ions. Surface charge of oil-saturated whole core samples of rock in the presence of various diluted and smart brines was estimated by zeta potential measurements. A comprehensive analysis of zeta potentiometric and reservoir simulation studies was done to establish and investigate the linkage between the recovery mechanism and the incremental recovery achieved. It is noted that zeta potential increases with the increasing level of dilution and it can be attributed to electric double-layer mechanism. On the contrary, simulation studies implied a different mechanism where an increase in effluent’s pH and Ca2+ mole fraction along with decrease in moles of minerals and saturation index implied rock dissolution was dominant mechanism. Moreover, the effect of mineral dissolution beyond the injection block is highly doubtful. This study demonstrates that an integrated approach from both zeta potentiometric and simulation studies can be used to provide insights into the underlying science of interactions at pore scale during a low salinity waterflood using smart brines. With the aid of an adequately designed upscaling procedure and protocol, the laboratory results can be further used towards developing field-scale models to obtain with realistic recovery factors with optimized brine composition and salinity.

Fluid-Fluid Interfacial Effects in Multiphase Flow during Carbonated Waterflooding in Sandstone: Application of X-ray Microcomputed Tomography and Molecular Dynamics.

Fluid-fluid interfacial reactions in porous materials are pertinent to many engineering applications such as fuel cells, catalyst design, subsurface energy recovery (enhanced oil recovery), and CO2 storage. They have been identified to control physicochemical properties such as interfacial rheology, multiphase flow, and reaction kinetics. In recent years, engineered waterflooding has been identified as an effective way to increase hydrocarbon recovery and solid-fluid interaction has been assessed as the key mechanism. However, in this study, we demonstrated that in the absence of solid-fluid interactions (in strong hydrophilic porous media), fluid-fluid interfacial reactions can significantly affect multiphase flow and thus lead to an increased hydrocarbon recovery during engineered carbonated waterflooding. We designed a microwaterflooding system to evaluate the interfacial reactions during two phase flow with engineered carbonated waters. Given that salinity controls the amount of dissolved CO2, we injected carbonated high salinity water and carbonated low salinity water to achieve different fluid-fluid reactions. We injected the carbonated water in a sandstone with 99.5% quartz under X-ray microcomputed tomography (μCT) scanning at a resolution of 3.43 μm per pixel. Image processing shows that carbonated low salinity waterflooding can recover 8% more oil than carbonated high salinity waterflooding, while the quartz-rich sandstone remains strongly hydrophilic in both samples. A gradual CT intensity distribution indicates an interfacial phase generation between carbonated brine and crude oil during carbonated waterflooding. Therefore, we attributed the additional hydrocarbon recoveries to the fluid-fluid interfacial reactions. To understand the effects of fluid-fluid reactions on interfacial properties, we performed molecular dynamics simulations to investigate the chemical species distribution at the interface, interfacial tension (IFT) changes, and CO2 diffusion. The MD simulation results revealed a layered structure of the interface, a lower CO2 diffusion coefficient in carbonated high salinity water, a lower IFT in carbonated low salinity water, a swelling hydrocarbon phase in carbonated low salinity water, and more CO2 accumulated at the interface between the hydrocarbon phase and carbonated low salinity water. This work provides a general and fundamental understanding of the influence of fluid-fluid interactions on the interfacial properties between carbonated water and the hydrocarbon interface.

Data-Driven Modeling Approach to Predict the Recovery Performance of Low-Salinity Waterfloods

Low-salinity waterflooding (LSWF) has, in the past decade, attained a lot of attention to enhance oil recovery. In LSWF, diluted water is injected into an oil reservoir to improve oil recovery. The injected low-saline water changes the wettability of the reservoir, which leads to higher oil recovery. The recovery of an oil reservoir can be predicted from simulators, which are tedious, expensive, and time-consuming. Therefore, there is a need for a simple, quick, and inexpensive substitute to predict the oil recovery factor for low-salinity waterfloods. This paper presents a novel empirical correlation based on a feed-forward neural network to predict LSWF recovery efficiency in a heterogeneous reservoir at and beyond water breakthrough. The proposed model is valid for a broad range of dimensionless input parameters—degree of dilution of high saline water, mobility ratio, degree of reservoir heterogeneity, permeability anisotropy ratio, API gravity, and production water cut. The new empirical correlation was developed using 20,000 simulated data points obtained from simulation results to cover a wide range of input values. The LSWF simulation model was developed and validated with a model of a real carbonate reservoir located in the Madison formation in Wyoming. The artificial neural network (ANN) model parameters were optimized by conducting extensive sensitivities of ANN parameters (hidden layer neurons, training algorithms, and transfer functions). Moreover, an interesting trend analysis was conducted to validate the physical behavior of the ANN model, and a comparison with the unseen dataset was performed. To evaluate the performance of the newly developed correlation, three statistical indices were used, including the average absolute percentage error (AAPE). AAPE was 1.69% and 1.84% for the training and testing datasets, respectively. The proposed ANN model is limited to a single-stage, low-saline waterfloods for a 5-spot pattern.

Response Surface Method for Modelling the Effect of CO2 in Brine/Waxy Oil Interfacial Tension during LSW-WAG Enhanced Oil Recovery

Recent research on the combination of low salinity waterflood (LSW) with CO2 water-alternating gas (WAG) has received significant attention due to its effectiveness in recovering residual oil in a mature field. The solubility of CO2 increases with decreasing brine salinity; and the presence of CO2 in the injected water is expected to reduce the water/oil interfacial tension (IFT) leading to the release of trapped oil previously held in the rock by capillary forces. However, to date, little study has been done on the fluid/fluid interaction during the LSW-WAG process involving waxy crude oil and injected brine. In this study, two models have been developed from experimental IFT measurements that can facilitate the prediction of the CO2 effect in the interfacial tension between oil/water interface in the presence and absence of CO2. This objective is achieved by modelling the effect of pressure, brine salinity, and CO2 on oil/water IFT with the response surface methodology (RSM) using the modified central composite design method (CCD) for the experimental design. Based on the developed model, the optimum values of input variables were calculated by analysis of variance (ANOVA) to obtain an acceptable model. The R-squared values demonstrate that the developed models could appropriately predict the experimental results of oil/water IFT from Dulang crude oil and 7 different brine salinity. The results of this study are expected to give insights into the fluid/fluid interaction behaviour during the LSW-WAG recovery process from a mature field with waxy crude oil.

Experimental Studies of Low Salinity Water Flooding in Sandstone Porous Media: Effects of the Presence of Silica and Kaolinite

ABSTRACT In recent years, many studies have been conducted on the method of low-salinity water (LSW) injection and its effect on enhanced oil recovery (EOR) of oil reservoirs. The lower operating cost of this method has led many researchers to study this method on reservoirs that are in the second half of their natural production life. Different mechanisms have been proposed depending on the study of sandstone and carbonate samples, but to date, no broad consensus has been reached on a single mechanism. Among these mechanisms, fine migration has been widely reported as the important factor leading to EOR. In this study, focusing on the type of minerals (different percentages of silica and kaolinite) and creating artificial cores, the effect of water injection with different salinity levels was investigated on fine migration in sandstone samples using core flooding. Three sets of different laboratory tests were performed. In the first set, the effect of type and percentage of minerals was investigated; in the second set the effect of soaking time was evaluated; and in the third set the impact of aging was examined. In all implemented tests, parameters of increase in enhanced recovery, differential pressure, pH, turbidity, conductivity, and permeability were measured to understand the governing mechanisms as well as the influence of the presence of minerals in the process. The results show that unlike previous studies, the presence of kaolinite is not necessary for enhanced recovery, where damage to the formation is irreversible due to the closure of the pores affected by this mineral. Also, by adding the factor of time, the performance of this method can be improved and the parameter of aging exerting a significant effect on tertiary-enhanced recovery. The results of this study can provide a better understanding of fine migration mechanism in the LSW flooding. Based on the results, the effect of the clay particle interactions in sandstone samples can be identified in LSW process as well.

Pore-Scale X-ray Imaging of Wetting Alteration and Oil Redistribution during Low-Salinity Flooding of Berea Sandstone

Observations over a range of scales show that lowering the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration affects the distribution of fluids over the pore and pore-network scale and how this wetting alteration leads to oil recovery. In this work, we observe how oil and brine redistribute in the pores of rocks in response to low-salinity flooding. We use X-ray μ-CT scanning to image tertiary low-salinity waterflooding in two Berea sandstone cores. The wetting state of one core is altered with exposure to crude oil. We characterize the wetting state of both samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the unaltered rock, oil saturation, fractional mineral area covered by oil, and size distribution of oil-filled pores remain constant between high-salinity flooding and subsequent low-salinity floods. In contrast, in the altered sample, we observe a shift in the mineral area covered by oil after low-salinity flooding toward decreasing coverage, consistent with a change to a less oil-wetting state. This change is also reflected in the observed variation in fluid pore occupancy. The wetting alteration results in the redistribution of 22% of oil within the rock, but an additional recovery of just three percentage points. The success of low-salinity waterflooding depends on both a wetting alteration and a pore structure, which facilitates the production of mobilized oil.

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.

Numerical Simulation of the Combined Effects of Low Salinity Water and Alkaline-Surfactant-Polymer Flooding

Low Salinity Water (LSW) and Alkaline-Surfactant-Polymer (ASP) flooding are emerging enhanced oil recovery methods that help recover oil from the reservoir after primary and secondary recovery processes. Experimental studies on LSW and ASP flooding have indicated potential in additional oil recovery. In this paper, numerical simulation was performed to study the combined effects of LSW and ASP flooding. A heterogenous reservoir initially saturated with oil and water was modelled using Eclipse. The wells were completed with an inverse five-spot pattern and the production life of the reservoir was taken to be five years. The results showed that LSW flooding using a salt concentration of 1 000 ppm achieved a higher oil recovery than conventional (high salinity) water flooding with a salt concentration of 35 000 ppm. The oil recovery for conventional water flooding was 59.5% and that of low salinity flooding was 64.1%. The overall oil recovery for LSW combined with alkaline, surfactant and polymer flooding were 64.1%, 70.5% and 62.6%, respectively. The model indicated an increase in overall oil recovery of 91% when alkaline, surfactant and polymer were combined and injected as the same slug as opposed to the injection of the chemicals individually. This was attributed to the synergy of the chemicals. The alkaline and the surfactant reduce the interfacial tension between the oil and water and the polymer improves the mobility ratio thereby increasing sweep efficiency.

Thermodynamic Aspects of pH and Wettability Changes in Low Salinity Water Flooding Oil Recovery

Low salinity water flooding has for decades emerged as a technically and economically viable enhanced oil recovery scheme due to its environmentally attractive nature. In the literature, several reasons have been proposed for its immense success, some of which have been experimentally proven. Among the reasons given, wettability and pH increase have been greatly highlighted. In this paper, we have developed a pH and salinity dependent Gibbs free energy of adsorption model, using established thermodynamic concepts to prove the viability of hydrogen ions adsorption which can lead to pH and wettability increase. Accordingly, we have shown based on theoretical calculations that as salinity decreases, adsorption free energy for hydrogen ions decreases, leading to pH decrease at lower salinities. Our theoretical calculations also agree with optimum salinity ranges reported in the literature.

Chemical Compositions in Salinity Waterflooding of Carbonate Reservoirs: Theory

Higher oil recovery after waterflood in carbonate reservoirs is attributed to increasing water wettability of the rock that in turn relies on complicated surface chemistry. In addition, calcite mineral reacts with aqueous solutions and can alter substantially the composition of injected water by mineral dissolution. Carefully designed chemical and/or brine flood compositions in the laboratory may not remain intact while the injected solutions pass through the reactive reservoir rock. This is especially true for a low-salinity waterflood process, where some finely tuned brine compositions can improve flood performances, whereas others cannot. We present a 1D reactive transport numerical model that captures the changes in injected compositions during water flow through porous carbonate rock. We include highly coupled bulk aqueous and surface carbonate-reaction chemistry, detailed reaction and mass transfer kinetics, 2:1 calcium ion exchange, and axial dispersion. At typical calcite reaction rates, local equilibrium is established immediately upon injection. In SI, we validate the reactive transport model against analytic solutions for rock dissolution, ion exchange, and longitudinal dispersion, each considered separately. Accordingly, using an open-source algorithm (Charlton and Parkhurst in Comput Geosci 37(10):1653–1663, 2011. https://doi.org/10.1016/j.cageo.2011.02.005), we outline a design tool to specify chemical/brine flooding formulations that correct for composition alteration by the carbonate rock. Subsequent works compare proposed theory against experiments on core plugs of Indiana limestone and give examples of how injected salinity compositions deviate from those designed in the laboratory for water-wettability improvement.

Effect of different low salinity flooding schemes and the addition of alkali on the performance of low-salinity waterflooding during the recovery of heavy oil from unconsolidated sandstone

Low salinity waterflooding (LSW) is a promising enhanced oil recovery process. The LSW advantage has been associated to changes in rock wettability toward a more water wet state. This study evaluated the effect of different flooding schemes on the performance of LSW in terms of production rate and incremental oil recovery from sand-pack systems. This work also investigated the main mechanism prompting sand wettability changes during LSW.Flooding Scheme-1 consisted of high salinity waterflooding, low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-2 consisted of low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-3 consisted of alkali aided low salinity flooding and low salinity waterflooding. The main mechanism causing wettability reversal was verified employing contact angle analysis, inductively coupled plasma spectrometry, and scanning electron microscopy.This new study reveals in a straightforward manner the effect of low salinity waterflooding schemes on both production rate and incremental oil recovery. LSW in secondary mode, as conducted in FS-2, expedited the oil production rate by 15% and increased the overall oil recovery by 20% relative to flooding schemes FS-1 and FS-3. Furthermore, this study determined that multi-component ionic exchange was the dominant mechanism for the reversal of sand wettability to a more water wet state.This paper provides new insights for heavy oil producers on the relevance of the flooding schemes during LSW and on the dominant mechanism for wettability alteration during the recovery of heavy oil from unconsolidated sands.

Effect of individual ions on rock-brine-oil interactions: A microcalorimetric approach

Understanding the mechanisms behind the additional oil recovery by low salinity water flooding (LSWF) in carbonates has been difficult because of the complexity of the crude oil + brine + rock system. This study is an attempt to isolate fluid–fluid and rock-fluid interactions through Isothermal Titration Calorimetry (ITC) to get a deeper understanding of the oil recovery process. The results from the fluid–fluid interactions pointed out that the observed endothermic response is determined by the formation of micro-dispersions, in which Mg2+ is more active than Ca2+. The incorporation of Ca2+, Mg2+, SO42- and HCO3- onto the chalk lattice effectively does not need energy from the surroundings to proceed. On the other hand, the incorporation of Mg2+ or Ca2+ into the calcite structure in the presence of SO42- is less energetically favorable due to pair creation.

PH effect on wettability of –NH+-brine-muscovite system: Implications for low salinity effect in sandstone reservoirs

Wettability alteration remains the main mechanism of low salinity water flooding (LSWF) which is controlled by several factors including crude oil composition. Although presence of acidic components in crude oil confirmed to be necessary to enhance wettability during LSWF, yet the effect of basic components remain unclear. In this work we used the concept of surface energy to explicate the dependency of wettability on a high base number (BN) oil as a function of water pH, ion type and salinity. We measured Oil/Brine contact angle and interfacial tension, which then were used to compute Oil/Solid (mica) interfacial tension using Neumann's equation of state. In addition, we measured the zeta potential and simulated the concentration of base components (–NH+ groups) in the oil using a surface complexation model to understand the underlying mechanisms of wettability and interfacial tension alterasion. We found that wettebility is also dependant on the basic components of crude oil where pH plays a major role and salinity and ion type play a secondary role. Increasing pH (from pH=3 to pH=11) decreased the contact angle moving the system to a more hydrophilic or water-wet state (contact angle decreased from 162° to 68° for CaCl2 solution and from 163° to 66° for NaCl solution). We also found that Oil/Solid interfacial tension increased with pH, where changes were more pronounced in the presence of divalent cations compared to monovalent. We hypothesise that changes in the contact angle and Oil/Solid interfacial tension are due to the chemo-physical adsorption of –NH+ groups at the oil surface to the muscovite negative sites. The hypothesis is consistent with the changes in the zeta potential and –NH+ surface concentration computed from the surface complexation model. The results of this study underscore the importance of the basic component on system wettability as a function of pH, providing insights into the low salinity EOR in sandstone reservoirs.

The prospects and potential opportunities of low salinity water flooding for offshore applications in sandstones

Low salinity water flooding (LSWF) is an emerging enhanced oil recovery (EOR) technology with enormous potential for offshore applications in sandstones. The objective of this study is to provide a review on LSWF offshore field applications and summarize the key lessons learned. A review was also conducted on the capabilities of existing sulfate removal units (SRUs) for seawater injection in offshore fields. Furthermore, the potential of targeting offshore oil fields with de-sulfated seawater (DSSW) injection, either ongoing or planned, as primary candidates to switch over to LSWF EOR has been investigated.For LSWF field trials, the chance of success can be significantly improved when it is based on key laboratory screening tests such as reservoir condition corefloods. The LSWF field tests implemented in offshore fields mainly comprise of single well chemical tracer tests (SWCTT) and interwell trials. However, the reported interwell field trials are restricted to unconfined pilots, which makes the injection and production allocation difficult. Therefore, confined pilots are recommended for future consideration of LSWF field trials to provide better estimations on swept volumes and accurately determine the improvements in the displacement efficiency.Globally there are more than 80 sulfate removal units in operation for de-sulfated seawater (DSSW) injection in offshore waterflooding. All these offshore fields with DSSW injection either currently ongoing or planned can become potential candidates for screening and switch over to LSWF EOR for the following two reasons: (1) The divalent cations can act as bridges between negatively charged rock surfaces and negatively charged polar oil components to increase the oil-wet tendency. These bridges can become primary targets to be replaced by un-complexed cations in low salinity water for EOR. (2) The de-sulfated seawater injection processes can easily be switched to LSWF by retrofitting the existing sulfate removal units with reverse osmosis (RO) desalination systems and upgrading the facilities to handle larger water volumes. Such retrofitting is considered sufficient to generate low salinity water, which can bring significant gains to increase oil recovery with minimal additional investment. The availability of RO desalination systems on offshore platforms can also provide potential opportunities for the cost-effective implementation of tertiary chemical EOR technologies especially polymer flooding.The novelty of this study is that it provides useful guidelines for reservoir screening and offshore field implementation of LSWF processes. Also, the new potential of evaluating the offshore oil fields with existing DSSW injection for switching over to LSWF has been identified. These findings will have a potential impact on enhancing the LSWF prospects and opportunities for EOR in different offshore fields.

Strategy of water-flooding enhancement for low-permeable polymictic reservoirs

This article pays attention to the issues of increasing the efficiency of the development of oil fields with low-permeable polymictic reservoirs. It is possible to increase the efficiency of this process by improving the technology of their artificial water-flooding. This goal is being realized by identifying the features of the development of low-permeable polymictic reservoirs of fields in Western Siberia and creating a strategy to improve the technology of artificial waterflooding, taking into account the impact on the surface molecular properties of the reservoir system by the stages of their development. The developed strategy was substantiated in stages using hydrodynamic modeling. Also, an assessment was made of the effectiveness of the implementation of low-salinity waterflooding at the late stage of development of low-permeability polymictic reservoirs, the optimal time for changing the waterflooding agent from formation water to fresh water was determined.

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.

Modeling low-salinity waterflooding: a numerical interpretation from experimental carbonate results

Modeling low-salinity waterflooding: a numerical interpretation from experimental carbonate results

Isolating the effect of asphaltene content on enhanced oil recovery during low salinity water flooding of carbonate reservoirs

ABSTRACT Polar compounds in oil, especially asphaltene and resin, have important implications on the oil recovery from carbonate reservoirs; yet their isolated effects, independent of other oil properties, are not well understood. Thus, two different crude oils with similar densities and resin contents, but with dissimilar asphaltene contents, were selected to better understand asphaltene’s effect on: wettability alternations upon water injection, IFT changes, and areal sweep efficiency. It was found that crude oil with greater amount of asphaltene hinders the wettability alteration by undiluted and diluted seawaters, due to sustained hydrophobicity caused by polar compounds adsorbing onto the rock surface. Conversely, crude oil with lower amount of asphaltene, combined with low salinity waters, resulted in pronounced wettability alteration. Based on image analysis of the surface of carbonate rocks, higher areal sweep efficiencies were obtained for non-asphaltenic crude oil (around 35%, versus 6% to 30% for asphaltenic crude oil), using seawaters diluted ten-and fifty-fold, corresponding to the lowest contact angle values measured (36° and 22°, respectively). Asphaltene is thus deemed to play a key role in the wettability alteration of carbonate rocks, consequently affecting the performance of enhanced oil recovery during low salinity water injection.

Investigation of permeability decline due to coupled precipitation/dissolution mechanism in carbonate rocks during low salinity co-water injection

Low salinity water injection is a promising water-based enhanced oil recovery (EOR) method for carbonate rocks. However, permeability impairment resulted from competition between mineral scale precipitation and rock dissolution is not well understood due to complex injection water/formation brine/rock interactions. In this paper, simultaneous effects of rock dissolution and mineral scale precipitation in low saline co-water injection on permeability performance were investigated. A dynamic flow of water with varying ion composition considering scale precipitation/rock dissolution coupling with geochemical reactions (using PHREEQC) was developed. The proposed model was validated with outlet ion concentration of single phase coreflood data. Then, permeability decline curves were obtained for each mixing ratio of formation brine and diluted sea water. The results show that in case of co-water injection, mineral scale precipitation is the dominant mechanism in early times of flooding and can be comparable with rock dissolution quantitatively in longer time. This result is in contrast with results of sequensive injection available in literature due to lack of sufficient mixing zone between injected water and formation brine and small pore volume of injection. In addition there are three different regions in permeability curve of co-water injection which is reflecting the competition between mineral scale precipitation and rock dissolution mechanisms. Moreover, as the share of formation brine increased more than 0.5, mineral precipitation became dominant and permeability curve decreased monotonically. The model can be used for distinguishing share of different mechanisms of permeability variation during low salinity waterflooding.

Pore scale visualization of fluid-fluid and rock-fluid interactions during low-salinity waterflooding in carbonate and sandstone representing micromodels

Low Salinity Waterflooding (LSWF) has become a popular tertiary injection EOR method recently. Both fluid-fluid and fluid-rock interactions are suggested as the contributing mechanisms on the effectiveness of LSWF. Considering the contradictory remarks in the literature, the dominating mechanisms and necessary conditions for Low Salinity Effect (LSE) varies for different crude oil-brine-rock (CBR) systems. The aim of the present study is to investigate LSE for an oil field in the Middle East that is composed of separate sandstone and limestone layers. Contact angles and Interfacial Tension (IFT) are measured to have more insight on the CBR under investigation. Visual experiments were conducted in micromodels to determine the dominating mechanisms of LSE. Experiments were conducted under water-wet and oil-wet conditions for both sandstone and limestone representing micromodels. Several secondary and tertiary injection scenarios were performed with different levels of salinities. Consecutive injection of high-salinity and low-salinity water illustrated that LSE occurs under certain conditions. For both rock types, during the secondary high salinity injection, the oil trapping mechanism was mostly snap-off under water-wet condition, while fingering/bypassing was dominant under oil-wet conditions. LSWF causes diminutive changes of saturation redistribution in water-wet micromodels. Even in rare occasions that oil ganglia started to reshape or redistribute, it became trapped again in the downstream pores of the model, and not produced effectively. Contrary to this, LSWF was very effective under oil-wetting conditions. Continuous oil films, which exist in oil-wet condition, are beneficial for the effectiveness of LSE. Measured IFT and contact angles cannot justify the observed LSE. Additionally in the designed micromodels, any contribution of clay or fine migration to the LSE is ruled out. Spontaneous formation of the micro-emulsion was a very weak mechanism in our experiments and did not contribute to pushing oil out of the dead end pores or divert the flow path to the un-swept areas. Visual investigations suggested that formation of the visco-elastic interface can be the dominating mechanism for LSE in the investigated CBRs which is more effective in the case of oil-wet system due to the lack of snap-off trapping mechanism.