Waterflooding In Carbonate Reservoirs Research Articles

Effects of Sulfate Ions on Crude Oil Adsorption/Desorption on Carbonate Rocks: Experimental and Molecular Simulations.

In the background of the strong oil wettability and low production by water flooding in carbonate reservoirs, low-salinity water containing sulfate ions can significantly change the surface wettability of carbonate rocks and thus increase the sweeping area; however, the absorption and desorption mechanisms of the oil film in the carbonate rock surface remain unclear. This paper analyzed the wettability alternation of carbonate rocks' surface in pure water and sodium sulfate solution. At the same time, MD (Materials Studio) software was used to simulate the formation process of the oil film and the effect of sulfate ions on the desorption of the oil film on the surface of carbonate rocks. The experimental results showed that sodium sulfate solution could accelerate the rate from oil-wet to water-wet and the final contact angle (49°) was smaller than that in pure water. The simulation results showed that dodecane molecules moved to the surface of calcite to form a double layer of the oil film and that the oil film near the calcite surface had a high-density stable structure under the van der Waals and electrostatic action. The hydrating sulfate ions above the oil film broke through the double oil film to form a water channel mainly under the action of electrostatic force and a hydrogen bond and then adsorbed on the calcite surface. A large number of water molecules moved down the water channel based on a strong hydrogen bonding force and crowded out the oil molecules on the surface of the calcite, resulting in the oil film detachment. This work aims to explain the interaction of oil molecules, water molecules, and SO42- ions at the molecular scale and guide the practical application of low-salinity water flooding in carbonate reservoirs.

ABOUT SOME PROBLEMS OF WATERFLOODING IN CARBONATE RESERVOIRS

The features of waterflooding of carbonate (fractured-porous) rocks, caused by the interaction of the system of fractures with the matrix (blocks) of the rock, are considered. It is shown that the slower propagation of the pressure pulse in the rock matrix in comparison with the propagation of this pulse along the fracture system of the formation leads to compression of the rock blocks in the near-wellbore zone of the injection well, as a result of which stress concentration occurs at the ends of vertical fractures, which increases the likelihood of these fractures growing into the roof of the productive formation. It is shown that in order to prevent the development of this process, the growth rate of water injection pressure should be limited in accordance with the time of liquid pressure equalization in the pore space of the rock matrix and in the fracture system. When developing production wells drilled in fractured porous media, in order to prevent the development of the process of closing fractures in the bottomhole zones of these wells, the drawdown reduction rate must also be limited in a similar way. It is noted that when applying technologies for non-stationary flooding of productive reservoirs, the main factor determining their effectiveness is the change in the direction of filtration flows in the reservoir. This leads to the activation of filtration processes in the stagnant zones of the formation and the intensification of the processes of capillary impregnation of low-permeability interlayers with water from more flooded highpermeability interlayers.At the same time, it is important to take into account that when changing the direction of filtration flows at a late stage of development of carbonate reservoirs, in order to prevent reimpregnation of hydrophobic rock blocks with oil, it is more expedient to change the operating modes of production rather than injection wells. It is shown that water flooding of hydrophobic carbonate reservoirs results in incomplete water displacement of oil as a wetting phase from rock blocks. To reduce the residual oil saturation of rock blocks, it is advisable to increase the displacement pressure gradient in the reservoir in combination with a change in the direction of filtration flows in it.

Chemical-Enhanced Oil Recovery by Alkali/Sulfate Smart Water Flooding in Carbonate Reservoirs Using a Green Polymer Extracted from Plantago ovata Seed

Chemical-Enhanced Oil Recovery by Alkali/Sulfate Smart Water Flooding in Carbonate Reservoirs Using a Green Polymer Extracted from <i>Plantago ovata</i> Seed

Role of sulfate ion on wettability alteration and oil mobilization in chalk reservoirs during modified salinity waterflooding

It has often been reported that an increase in sulfate has a positive effect on altering wettability and mobilizing oil during modified salinity water flooding in carbonate reservoirs. However, this understanding is mostly based on experimental studies using outcrop rock material. Therefore, this study aims to reassess the role of sulfate on altering wettability and recovery performance during modified salinity water injection in oil-saturated porous media of chalk reservoirs using real reservoir material. We compare the results with outcrop samples to evaluate the effects of sulfate and rock material on wettability alteration and oil mobilization. We conduct dynamic contact angle measurements and coreflooding experiments in reservoir conditions. Our findings contradict the previous observations, as we discovered that decreasing the sulfate concentration in the displacing fluid causes a shift in the reservoir chalk's wettability to a more water-wet condition, which significantly improves oil mobilization. We also establish that outcrop chalk samples, typically used in laboratory experiments, cannot be used as reliable analogues for reservoir chalk samples with the same geological age. Finally, we use direct pore scale simulations to demonstrate the impact of observed wettability alteration on oil mobilization. Our simulation results align with our experimental findings, indicating that wettability alteration is the primary mechanism in our experiments, as fluid-fluid interactions were ignored, and flow was mainly controlled by the medium's wettability state.

Analytical solutions for the injection of wettability modifiers in carbonate reservoirs based on a reduced surface complexation model

The potential of tuned-composition waterflooding to enhance oil recovery from carbonate reservoirs has been widely investigated, where wettability alteration is the dominant mechanism. It is hypothesized that the sulfate in seawater adsorbs on the rock surface, removing acidic hydrocarbon species adsorbed thereon. Glycine, the simplest amino acid, has also been investigated as a wettability modifier for carbonates that acts similarly to sulfate.Wettability alteration by the adsorption of sulfate ion and glycine anion has been satisfactorily modeled by extending calcite's surface complexation model (SCM) based on zeta potential measurements. However, determining the relevance of the individual geochemical reactions is obscured by the complexity of the SCM. Moreover, the large number of equilibrium constants and their associated uncertainty result in many degrees of freedom when matching corefloods and spontaneous imbibition experiments.This research determines the chemical reactions in the calcite's SCM that govern wettability alteration and the incremental oil recovery by glycine-enhanced waterflooding in carbonate reservoirs. We found that the wettability alteration by SCM can be approximated by two anion exchange reactions between the wettability modifiers, sulfate and glycine anions, and the carboxylic acids adsorbed on the rock surface. Moreover, the wettability of the system described by the adsorption of carboxylic acids and the incremental oil recovery by waterflooding are linearly correlated with the K value of the reaction of carboxylic acids with the carbonate surface and the concentration of carboxylic acids in the system, which is a function of the total acid number.We present analytical solutions for the two-phase, multicomponent reactive-transport model coupled with anion exchange reactions. To the best of our knowledge, this is the first time the presented analytical solutions are applied to describe enhanced waterflooding in carbonate reservoirs where more than one wettability modifier is injected. The analytical solutions showed that glycine injection enhances oil recovery over waterflooding by the formation of two wettability alteration waves. The number of waves and their types (rarefaction or shock) depend on glycine's and sulfate's concentration at the injection. The improvement in oil recovery by wettability alteration mainly occurs because the more favorable mobility ratio increases the displacement efficiency with no reduction in residual oil saturation. A synergy was found between glycine and sulfate, where the presence of glycine promotes the formation of a wettability-alteration shock by sulfate that improves the displacement efficiency.

Evaluation of sour gas-low salinity waterflooding in carbonate reservoirs - A numerical simulation approach

Although significant amount of H2S (sour gas) rich natural gas is estimated globally, but not much attention has been given to the application of H2S in the oil recovery process. Recent studies on the use of H2S in oil recovery processes showed that H2S has the potential of improving the oil recovery, and it can be even more effective than using CO2 in some processes. H2S can equally dissolve in the water, react with the reservoir rock to change its surface charge, porosity, and permeability. However, previous investigations on H2S oil recovery attributed the improved oil recoveries to the higher miscibility of H2S in the oil, and the reduction in the oil viscosity. Therefore, there is limited understanding on the H2S-oil-brine-rock geochemical interactions, and how they impact the oil recovery process. This study aims to investigate the interactions between H2S, oil, and carbonate formations, and to assess how the combination of H2S and low salinity water can impact the wettability and porosity of the reservoirs. A triple layer surface complexation model was used to understand the influence of key parameters (e.g., pressure, brine salinity, and composition) on the H2S-brine-oil-rock interactions. Moreover, the effects of mineral content of the carbonate rock on H2S interactions were studied. Thereafter, the results of the H2S-oil-brine-rock interactions were compared with a study where CO2 was used as the injected gas. Results of the study showed that the seawater and its diluted forms yielded identical ζ-potential values of about 3.31 mV at a pH of 3.24. This indicates that at very low pH condition, pH controls the ζ-potential of the oil-brine interface regardless of the brine's ionic strength. The study further demonstrated that the presence of other minerals in the carbonate rock greatly reduced the calcite dissolution. For instance, the calcite dissolution was reduced by 4.5% when anhydrite mineral was present in the carbonate rock. Findings from the simulation also indicated that CO2 produced negative ζ-potential values for the carbonate rocks, and these values were reduced by 18.4%–20% when H2S was used as the gas phase. This implies that the H2S shifted the carbonate rock ζ-potentials towards positive. The outcomes of this study can be applied when designing CO2 flooding and CO2 storage where the gas stream contains H2S gas since H2S greatly influences the dissolution of the carbonate mineral.

COMSOL-based investigation of the characteristics of microscopic water flooding and residual oil distribution in carbonate reservoirs

Carbonate reservoirs are rich in oil and gas reserves; thus, they have great exploitation potential. Therefore research on the microscopic mechanisms of carbonate reservoirs is of great significance. Based on the thin section images of core castings of typical Well 555 and its pore and fracture features in actual reservoirs, this study designed three kinds of images representing the pore and throat structure of real rocks by applying image stitching and binarization processing methods. A microscopic pore model of carbonate rocks was then established using COMSOL numerical simulation software. The microscopic water flooding characteristics and residual oil distributions of different schemes were observed by designing different fracture development forms. The fractures that developed in parallel main lines showed a more obvious influence on water flooding characteristics compared to fractures that developed in vertical main lines. The cluster residual oil was the main residual oil type in the early stage of water flooding in the pure matrix model. With the progress of water flooding, the continuous cluster residual oil gradually turned into mainly discontinuous porous and columnar residual oils. Vertical mainline fractures reduced the amount of residual oil in clusters and replaced it with columnar residual oil. In contrast, parallel main line fractures expanded the unswept area, with the residual oil appearing in contiguous clusters. This study microscopically analyzed the law and characteristics of water flooding in carbonate reservoirs to provide key theoretical support for enhancing oil recovery.

Coreflood Tests to Evaluate Enhanced Oil Recovery Potential of Wettability-Altering Surfactants for Oil-Wet Heterogeneous Carbonate Reservoirs

Summary Oil-wetness and heterogeneity are two main factors that result in low oil recovery (OR) by waterflood in carbonate reservoirs. The injected water is likely to flow through high-permeability regions and bypass the oil in the low-permeability matrix. In this study, systematic coreflood tests were carried out in both “homogeneous” cores and “heterogeneous” cores with a wettability-altering surfactant. The homogeneous coreflood tests were conducted to evaluate surfactant retention, as well as to compare tertiary surfactant flooding with secondary surfactant flooding. The heterogeneous coreflood test was proposed to model bypassing in low-permeability matrix during waterfloods, and dynamic imbibition of surfactant into the low-permeability matrix. Surfactant retention results suggest that retention increases as initial oil saturation decreases. The retention of selected surfactant in the target reservoir cores was measured to be within a range of 0.07–0.12 mg/g-rock, which is economically acceptable. The results of homogeneous coreflood tests showed that both secondary waterflood and secondary surfactant flood can achieve high OR (&amp;gt;50%) from relatively homogeneous oil-wet cores. A shut-in phase after the surfactant injection resulted in a surge in oil production, which suggests that enough time should be given for wettability alteration by surfactants. The results of heterogeneous coreflood tests showed that more oil is bypassed in the tighter matrix by waterflood if the permeability is higher in the flooded layer and this bypassed oil is the target for the wettability-altering surfactant floods. Slow wettability-altering surfactant injection leads to imbibition into bypassed regions. When the oil-wet carbonate reservoirs have large unswept regions after waterflood, wettability-altering surfactants can significantly improve OR if enough time is given for imbibition.

An Electrokinetic Study of Amino Acid and Potential-Determining Ions for Enhanced Waterflooding in Carbonate Reservoirs

Summary Reservoir rock wettability plays an important role in waterflooding especially in fractured carbonate reservoirs because oil recovery tends to be inefficient from the mixed-wet or oil-wet rock matrix. Improved oil recovery has been observed by adjusting the concentrations of potential-determining ions (PDIs) to alter the wettability of carbonate rocks. Our previous study showed that the oil recovery from carbonate reservoirs by waterflooding can be enhanced by the addition of glycine, the simplest amino acid. The interaction of glycine anion and oil-wet carbonate surfaces was confirmed in contact angle measurements and yielded the incremental oil recovery in imbibition experiments. This paper presents a surface complexation model (SCM) for the interaction between glycine and oil-wet carbonate surfaces that considers the impact of temperature, pH, salinity, and the concentrations of PDIs. The proposed SCM was tuned based on the zeta potential (ZP) data reported for synthetic calcite in glycine solutions. The tuned model predicts that the strong affinity of glycine for the oil-wet carbonate surface causes the carboxylic acids to desorb from the surface. The concentration of adsorbed carboxylic acids was in qualitative agreement with the water-wetting state of carbonate rocks inferred from the reported contact angle and spontaneous imbibition experiments. Moreover, the model indicates that glycine’s performance as a wettability alteration agent improves significantly at high temperatures. It also suggests that enhanced oil recovery (EOR) by formation brine (FB) with 1 to 3 wt% glycine at high temperatures should be similar to the injection of low-salinity seawater (LSW). The proposed SCM supports glycine’s potential to change the wettability of oil-wet carbonates at high salinity, high hardness, and high temperature.

A molecular insight into the effect of key ions on the detachment of crude oil from calcite surface: Implication for low salinity water flooding in carbonate reservoirs

The detachment of crude oil from calcite surface plays an important role in oil recovery and wettability alteration during low salinity water flooding in carbonate reservoirs. The effects of brine salinities and key ions on the dynamic detachment process have been much of debate in the past decades in theories and experiments due to complex mechanisms behind the crude oil-calcite interactions. Herein, molecular dynamic simulation was used to study the influence of brine salinities and ion concentrations on the detachment mechanism of crude oil from calcite surface by establishing 20 brine-crude oil-calcite molecular models varying salinities and key ion concentrations in brine. Molecular configurations, concentration distribution profiles, interaction energies, H-bond numbers and center of mass (COM) distances were carefully analyzed to characterize the dynamic crude oil detachment performance. The results reveal that reducing the brine salinities and ion concentrations can significantly weaken the interaction intensity between oil and calcite and accelerate the detachment process. Therefore, the oil detachment is induced and the effect of low salinity on oil detachment process is significantly time-dependent. The concentration distribution profiles shows that the strong polar oil molecules, for example acetic acid molecules, can't be detached from calcite surface by tuning the brine salinity and key ions. The present of Mg2+ and Na+ is able to delay the detachment process of oil molecules and as a consequence, result in the impeded oil detachment process according to time-dependent dynamic molecular configurations, interaction energies and COM distances analysis. Furthermore, the present of Ca2+ is able to strengthen the interaction between oil and calcite and in consequence, hinder the detachment of oil molecules from the calcite surface according to the interaction energy, the molecular configuration and COM distances. This study should provide the molecular-scale insights into wettability alteration and enhanced oil recovery by low salinity water flooding in carbonate reservoirs.

Comprehensive investigation of low salinity waterflooding in carbonate reservoirs

Waterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

Interplay Between Ca2+, Mg2+, and SO42– Ions and Their Influence on the Zeta-Potential of Limestone during Controlled-Salinity Waterflooding

Substantially enhanced oil recoveries from carbonate reservoirs have been accredited to the modification of ionic content and salinity of the injection water and subsequent alteration of reservoir rock wettability toward more water-wet. Modification of surface charges at rock/oil/water interfaces is believed to be the main mechanism that controls the process of wettability alteration. This paper presents a systematic zeta-potential measurement study that investigates the individual and relative impacts of Ca2+, Mg2+, and SO42– ions on a limestone rock from the Middle East. The main target of the study is to understand the impact of each potential determining ion individually and in the presence of another ion for insightful explanations of the overall impact of injection water during ionically controlled waterflooding in carbonate reservoirs. The novelty of the current study is the comprehensive investigation of the interplay between potential determining ions and the resultant impact on limestone surface charges. Different modified brines were prepared based on the ionic composition of Arabian Gulf seawater, which is the main source of injection water in the region. Model oil, containing carboxylic acid, was used to represent the oil phase in aging procedures. Interactions at the rock/oil/water interfaces were assessed using zeta-potential measurements of unaged and aged limestone particles. The results show that Ca2+, Mg2+, and SO42– are potential determining ions that can alter surface charges of unaged and aged limestone. SO42– ions were found to have a profound impact on the generation of negative surface charges on limestone as well as in suppressing the preferential ability of Ca2+ and Mg2+ ions to generate positive surface charges. Results also showed that limestone possesses negative surface charges when conditioned in unmodified seawater and twice diluted seawater. Comparing the obtained results from this study with the literature suggests that similarities in the mineralogical composition of carbonates rocks do not necessarily reflect in similar electrokinetic behavior, even under the same experimental conditions. Moreover, this study shows that the zeta-potential of limestone is not linearly correlated with decreased salinity. Furthermore, it is shown that conditioning limestone in sequentially diluted seawater will result in an increase in the magnitude of the negative charges up to twice diluted seawater, after which the magnitude of the negative surface charges will start to decrease. This finding suggests that a different mechanism is responsible for the modification of carbonate surface charges during late stages of sequential low-salinity waterflooding than the mechanism that controls the modification of surface charges during early stages of the process.

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.

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.

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.

Detecting pH and Ca2+ increase during low salinity waterflooding in carbonate reservoirs: Implications for wettability alteration process

Wettability alteration appears to be an important physiochemical process during low salinity waterflooding (LSWF) in carbonate reservoirs. However, the leading factor(s) behind wettability alteration remains unclear. In particular, the relative contribution of calcite dissolution induced pH and Ca2+ increase has not been explicitly quantified. We thus hypothesized that the pH increase plays a significant role in the wettability alteration, whereas the increase of Ca2+ plays a minor role. To test this hypothesis, we performed a geochemical study and examined the effects of salinity level on calcite dissolution and pH increase against the recovery factor profile obtained from the literature. The calcite dissolution was evaluated by equilibrating different brines with calcite. The equilibrated pH and brine compositions were then to be employed to quantify the Ca2+ increase and calculate surface species and electrostatic force between oil-brine-calcite interfaces.Our results show that low salinity water (LSW) indeed triggers calcite dissolution, which induces the pH increase from 1 to 2 units, whereas only causes less than 10% increase of Ca2+ concentration in the low salinity water. Surface complexation modelling implies that Ca2+ concentration variation may not lead to significant chemical surface species variation on calcite surfaces, but the pH increase would play an important role on oil-brine interfaces especially for the oils with high base component (-NH+). Moreover, geochemical modelling shows that at least 5 times dilution of the original brine is required to obtain a pH increase from 6.5–7.0 to 8.0–8.5, which seems to be essential for triggering the wettability alteration. We argue that high salinity formation brines with the low initial pH (5.5 to 6.5), high basic component oils, and at least five-time dilution could be the three key favourable elements to trigger the low salinity effect in carbonate reservoirs. This work provides a practical framework to screen potential carbonate reservoirs and predict LSWF performance.

Gradual or Instantaneous Wettability Alteration During Simulation of Low-Salinity Water Flooding in Carbonate Reservoirs

Injection of low-salinity water into carbonate reservoirs has gained attention as a viable and efficient enhanced oil recovery approach through wettability alteration as prevailing mechanism. However, modeling and implementation of wettability alteration during simulation of low-salinity water injection are challenging because of the complex ion interactions and chemical reactions in the brine and oil mixture as well as on the rock surface. It is noteworthy that wettability alteration is usually considered instantaneous in black oil simulation. The main purpose of this work was to put this assumption into perspective; thus, it aims at discerning under what circumstances the instantaneous wettability alteration approach is plausible during simulation of low-salinity water flooding. To answer this question, an approach was proposed to consider gradual wettability alteration during simulation of low-salinity water flooding and the results were compared with instantaneous wettability alteration method. The results show that the impacts of simultaneous increase in $${\text{SO}}_{4}^{2 - } ,{\text{Ca}}^{2 + }$$ concentrations and temperature cause the difference between gradual and instantaneous wettability alteration to be more noticeable at the early times of injection. Therefore, the results highlight that the impact of gradual consideration would be important at the early time of low-salinity water flooding process.

Kinetics of Calcite Dissolution and Ca-Mg Ion Exchange on the Surfaces of North Sea Chalk Powders.

Calcite dissolution and Ca–Mg ion exchange on carbonate rock surfaces have been proposed as potential mechanisms occurring during smart waterflooding in carbonate reservoirs. However, there is still a lack of fundamental understanding of these reactions to quantitatively evaluate their effects in the reservoir flooding process. Especially, the data on precipitation and dissolution kinetics are insufficient. In this work, the equilibration kinetics of calcite dissolution and Ca–Mg exchange was experimentally studied. The behavior of three powders was compared: pure calcium carbonate, Stevns Klint outcrop chalk, and North Sea reservoir chalk. It was found that the equilibration time for calcite dissolution was of the order of seconds for a given surface-area-to-liquid-volume ratio. The existing theory of calcite dissolution could well reproduce our observations. The Ca–Mg exchange showed two-step kinetics: the first step was fast, and it dominated the process within the first hour of reaction; the second step was slow, and it continued longer than the time of observation (2 weeks). Characteristic times for the two steps were extracted by fitting the experimental curves. A two-layer adsorption model was proposed to characterize the kinetic process and successfully matched with experimental data. The findings were further extended to flow-through scenarios. By comparing with literature data and surface complexation models, it was concluded that calcite dissolution alone was unlikely to be able to explain the additional recovery reported in the literature. The Ca–Mg exchange process could dominate the fluid–rock interactions at a high temperature in pure calcium carbonate rocks, while competitive adsorption of cations appeared to control the process at a lower temperature. Different carbonate rocks possess different properties with regard to the ion-exchange process.

Transport of Associative Polymers in Low-Permeability Carbonates

Carbonate reservoirs are heterogeneous from pore scale to field scale. Waterflood in carbonate reservoirs often leaves behind a substantial amount of oil due to pore-scale and large-scale bypassing. Polymer flooding can improve sweep efficiency and oil production. Most EOR polymers cannot be transported through low-permeability (< 30 mD) rocks. Hydrophobically modified associative polymers (APs) associate with each other during passage through pore throats and give a larger flow resistance than conventional polymers (Flopaam) of the same molecular weight. The goal of this work is to investigate the transport of associative polymers in low-permeability carbonate reservoirs (less than 50 md). An associative polymer similar in molecular weight to Flopaam 3330 was investigated in this study. Polymer rheology and the effect of salinity were studied at 60 °C. Mechanical shearing and aggressive filtration were used to modify the particle size distribution in polymeric solutions and improve transport through tight cores. Single-phase polymer transport experiments were performed in outcrop Edwards Yellow and Indiana limestone cores. Mechanical shear degradation reduced the particle size and improved the transport of the associative polymer in low-permeability carbonate cores. The permeability reduction factor and the residual resistance factor were higher for the sheared AP polymers than those for the sheared Flopaam polymer. The resistance factors for the associative polymer were higher than those for Flopaam for a given shear viscosity. Coreflood experiments with AP showed the evidence of two propagation fronts: polymer concentration front and pressure gradient stabilization front due to polymer network formation and polymer adsorption. As AP polymer concentration increased, permeability reduction factor, resistance factor, residual resistance factor and polymer adsorption increased. All the coreflood experiments suggest successful polymer transport in low-permeability carbonate cores even at significantly high polymer concentrations with pre-shearing.

Carbonated waterflooding in carbonate reservoirs: Experimental evaluation and geochemical interpretation

Abstract Carbonated water flooding (CWF) appears to be an important means in enhanced oil recovery (EOR) in carbonate reservoirs. While a few CWF coreflooding experiments have been done to reveal the controlling factor(s) behind incremental oil recovery, few has examined the impact of calcite dissolution on the contribution of the proposed mechanisms, and fewer have looked beyond the impact of calcite dissolution on different length scale (from core to reservoir). We thus conducted a series of core flooding experiments to investigate the residual oil saturation and recovery factor during waterflooding with and without carbonation. We also imaged the core plugs using a computed tomography scanner to examine the evolution of calcite dissolution along the core plug. Furthermore, we performed 1D reactive transport modelling at core- and reservoir-length-scale to delineate the impact of calcite dissolution process during carbonated waterflooding. Coreflooding experiments confirm that lowering salinity increases oil recovery from 53% to 64.5% without carbonation. However, low salinity carbonated water at secondary mode yielded 47.6% and 52% oil recovery, between 1 and 5.4% less recovery compared to formation brine flooding without carbonation, lower than the formation brine flooding without carbonation. Carbonated waterflooding also resulted in a significantly increases of permeability. CT images clearly show the generation of wormholes along the core, accounting for the low recovery and increased rock permeability. 1D reaction transport modelling at core-scale reveals the calcite dissolution taking place throughout the core plugs, supporting the wormholes evolution from CT images. One-dimensional reactive transport modelling at reservoir-scale shows the calcite dissolution distance from wellbore increases from 13 to 45 m with increasing flow rate from 0.05 to 1 m/day. Taken together, our results imply that calcite dissolution may deteriorate heterogeneity of reservoirs particularly near the wellbore. This may significantly undermine the contribution of oil-swelling, viscosity reduction, IFT reduction and wettability alteration on incremental oil recovery, as well as wellbore stability. However, the negative impact of calcite dissolution may not prevail at in-depth of reservoirs because the calcite dissolution would reach equilibrium at a certain distance, which is also associated with injection rates.