Waterflooding In Carbonate Reservoirs Research Articles

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.

Response of Non-Polar Oil Component on Low Salinity Effect in Carbonate Reservoirs: Adhesion Force Measurement Using Atomic Force Microscopy

While the effect of polar-oil component on oil-brine-carbonate system wettability has been extensively investigated, there has been little quantitative analysis of the effect of non-polar components on system wettability, in particular as a function of pH. In this context, we measured the contact angle of non-polar oil on calcite surface in the presence of 10,000 ppm NaCl at pH values of 6.5, 9.5 and 11. We also measured the adhesion of non-polar oil group (–CH3) and calcite using atomic force microscopy (AFM) under the same conditions of contact angle measurements. Furthermore, to gain a deeper understanding, we performed zeta potential measurements of the non-polar oil-brine and brine-calcite interfaces, and calculated the total disjoining pressure. Our results show that the contact angle decreases from 125° to 78° with an increase in pH from 6.5 to 11. AFM measurements show that the adhesion force decreases with increasing pH. Zeta potential results indicate that an increase in pH would change the zeta potential of the non-polar oil-brine and calcite-brine interfaces towards more negative values, resulting in an increase of electrical double layer forces. The total disjoining pressure and results of AFM adhesion tests predict the same trend, showing that adhesion forces decrease with increasing pH. Our results show that the pH increase during low-salinity waterflooding in carbonate reservoirs would lift off non-polar components, thereby lowering residual oil saturation. This physiochemical process can even occur in reservoirs with low concentration of polar components in crude oils.

Amino Acid as a Novel Wettability Modifier for Enhanced Waterflooding in Carbonate Reservoirs

SummaryReservoir wettability plays an important role in waterflooding, especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were conducted at room temperature with deionized (DI) water, and then at 368 K with three saline solutions: 243 571-mg/L salinity formation brine (FB), 68 975-mg/L salinity injection brine 1 (IB1), and 6898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. The primary mechanism is that the glycine solution weakens the interaction between polar oil components and positively charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The secondary mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.The amino acids tested in this research are nontoxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.

Low salinity water flooding in carbonate reservoirs – dissolution effect

One of the most significant research subjects in the industry of oil is the low salinity water injection techniques (LSWI). This is because there are possible benefits of raising recovery in oil as opposed to the conventional injection of seawater. Recent research has been done to find out the causes of less salinity with the injection of water in carbonated rocks presented significant findings. The primary mechanisms that are thought to lower salinity water injection are carbonate rocks dissolution, fines migration and alteration of wettability to more water wet. However, many researchers have elected to oppose the mechanism of dissolution and instead attributed high recovery of oil to be the primary wettability modification mechanism. Additionally, previous researchers provided no evidence characterizing about the rock and fluids produced in a detailed manner. This research work provides a detailed description of the underlying mechanisms, the core flood laboratory and the spontaneous imbibition in carbonate rocks. In the experiment, we carried out a series of steps using a limestone core with low permeability. This core was obtained from a nearby oilfield in Iraq and used it to study how dissolution and fines migration mechanisms take place. Moreover, in the process of carrying out the experiment and before its starting, SEM imaging analysis was used. In this case, as we carried out the experiment, we had to inject two-phase flow of sea water (SW), de-ionized water (DW) as well as soltrol-130. This was done in a sequential manner at 50 °C as well as 0.02 ml per minute. As the experiment progressed, the concentration of ions and pH value of the extracted water were measured in a continuous manner. The results obtained indicate that the rate of change in concentration of Ca2+ ions is directly proportional to the effluent pH value. By just balancing the mass, we were able to easily see the rate at which limestone dissolved as the experiment progressed. The maximum increase in pH was registered when fresh water was injected (pH=9.2). An increase in pH value can have a positive effect on altering wettability in that it can increase the alkalinity of flood water. To notice fines migration, the Scanning Electron Microscope (SEM) and Energy Dispersive Spectroscopy (EDS) are used to scan the images of the inlet and outlet of the core plugs after completion the experiment. This method can indicate that dissolution can induce fines dislodgement for the surface of the rock. The two mechanisms of fine migration and carbonate rock dissolution can significantly increase recovery of oil and at the same time inject water low in salinity.

Low salinity water flooding in high acidic oil reservoirs: Impact of pH on wettability of carbonate reservoirs

Wettability alteration has been identified as an important mechanism during low salinity water flooding in carbonate reservoirs. Oil composition, in particular, acidic and basic functional groups, plays an important role in regulating wettability. In this paper, we explored the potential of low salinity effect in reservoirs with high acidic components (acid number = 4.0 mg KOH/g and base number = 1.3 mg KOH/g) with a combination of approaches (e.g., contact angle and zeta potential measurements, and surface complexation modelling). We measured the contact angles of oil on calcite surfaces in presence of aqueous ionic solutions at different pH (3 and 8), salinity (0.01 and 1 mol/L), ion type (CaCl2 and Na2SO4) and temperatures (25–100 °C).Our results show that both salinity and ion type significantly affect contact angle at pH = 8. However, at low pH (pH 3), the oil-brine-calcite system becomes strongly water-wet with minor effect from salinity, ion type, and temperature. Lowing salinity drives the zeta potential of both oil-brine and brine-calcite to be strongly negative, particularly in the presence of Na2SO4 at pH 8, confirming the contribution of the electrical double layer to low salinity effect. Geochemical modelling reveals that breakage of electrostatic bridges between oil and calcite increases linearly with acid number, implying a higher potential of low salinity effect in high acidic oil-bearing carbonate reservoirs.This study provides an insight into how acid number parameter influences the wettability of oil-brine-carbonate system, and underscores the significance of acid components in wettability alteration of carbonate reservoirs, assisting in a better prediction and screening of low salinity EOR in carbonate reservoirs.

Wettability Alteration and Enhanced Oil Recovery Induced by Proximal Adsorption of Na+ , Cl− , Ca2+ , Mg2+ , and SO42− Ions on Calcite

The underlying mechanism of wettability alteration is vital for enhancement of oil recovery (EOR) by water flooding in carbonate reservoirs, such as calcite rock. Based on first-principles molecular dynamics simulations and core-flooding measurements, the authors find that proximal adsorption of ions in brine affects the wettability of calcite: Some ions primarily disturb the interfacial water structure, while others modify the effective surface charge, thus inhibiting and enhancing oil recovery respectively. This study provides needed insight into the physics of wetting at the atomic scale for EOR.

Effect of Initial Wettability on Performance of Smart Water Flooding in Carbonate Reservoirs—An Experimental Investigation with IOR Implications

In this paper, the effects of salinity and active ions on wettability alteration in carbonate reservoirs with different initial wettability conditions with implications in smart water flood design, optimization, and performance analysis are experimentally investigated. Contact angle measurement was used as the main tool to study the alteration in wettability. Other analytical techniques such as pH measurements along with energy-dispersive X-ray spectroscopy (EDS) were used to support the analysis. Initial wettability of the tested carbonate samples ranges from strongly water wet to preferentially water wet, neutral wet, oil wet, and strongly oil wet (5 cases or groups) condition. Four different synthetic brines, namely high salinity (Hsal), low salinity (Lsal), and smart waters 1 and 2 (SW1 = a Mg brine, and SW2 = a Mg and sulfate brine) were prepared and used by adjusting the salinity and ion concentration to study their effects on wettability alteration. Low-salinity brine (Lsal) proved to be more effective than high-salinity brine (Hsal) for the wettability alteration of calcite surfaces at intermediate (neutral) or oil-wet conditions. The smart brine containing only the Mg2+ ion (SW1) was able to alter the wettability of calcite surfaces in intermediate or oil-wet states. The sulfate ion played a catalytic role in wettability alteration by the magnesium ion, and the process was faster, as indicated by higher wettability alteration index values. High-salinity brine (Hsal) is a good choice for design of water floods in reservoir rocks with initial wettability in the range of strongly water wet to neutral wet conditions. In the wettability alteration process of oil-wet samples, brine with a high magnesium ion concentration was slower than brine containing high concentrations of both magnesium and sulfate ions. This can be attributed to the catalytic role of the sulfate ion compared to that of the magnesium ion. Finally, the results showed that the initial wettability of the reservoir rock plays a major role in design of a proper water flood to maximize oil recovery from carbonate reservoirs. The results obtained from this research work suggests that some effective smart water flooding scenarios can be developed and executed incorporating different smart brines to manage the reservoir rock wettability and maximize the oil recovery from carbonate oil reservoirs.

Low Salinity Waterflooding in Carbonate Reservoirs: Review of Interfacial Mechanisms

Carbonate rock reservoirs comprise approximately 60% of the world’s oil and gas reserves. Complex flow mechanisms and strong adsorption of crude oil on carbonate formation surfaces can reduce hydrocarbon recovery of an oil-wet carbonate reservoir to as low as 10%. Low salinity waterflooding (LSW) has been confirmed as a promising technique to improve the oil recovery factor. However, the principal mechanism underpinning this recovery method is not fully understood, which poses a challenge toward designing the optimal salinity and ionic composition of any injection solution. In general, it is believed that there is more than one mechanism involved in LSW of carbonates; even though wettability alteration toward a more desirable state for oil to be recovered could be the main cause during LSW, how this alteration happens is still the subject of debate. This paper reviews different working conditions of LSW, previous studies, and field observations, alongside the proposed interfacial mechanisms which affect the colloidal interactions at oil–rock–brine interfaces. This paper provides a comprehensive review of studies on LSW in carbonate formation and further analyzes the latest achievements of LSW application in carbonates, which helps to better understand the challenges involved in these complicated multicomponent systems and potentially benefits the oil production industry.

Predicting the rock wettability changes using solutions with different pH, through streaming potential measurement

The high reactivity of the carbonate rocks at various pH makes it difficult to evaluate the wettability, hence to find the recovery mechanisms behind modified waterflood in carbonate reservoirs. More recently, the streaming potential measurement is introduced as a method of electrokinetic phenomena more relevant to the subsurface systems. Regarding few experimental studies and in order to improve our understanding on streaming potential measurement, the electrokinetic studies on quartz and calcite surface were conducted as a function of pH in the range of 1.5–11.5 using an in-house novel setup of streaming potential measurement. High sensitivity of streaming potential coupling coefficient to pH variation in domain of pH lower than 4 for quartz and higher than 8 for calcite samples, underscores the fact that pH has to be well monitored during water based EOR tests to have more clear and predictable results. In the experiments reported here, measurements of streaming potential were compared with the adhesion test results to use streaming potential measurement as a promising tool to characterize wetting state and quantify wettability of a porous media. The results showed a clear correlation between streaming potential coupling coefficient/zeta potential change, wetting state and calcium concentration expressed as pCa2+, irrespective of how the pH is changed. Moreover, the equilibrium solutions analyses suggest that streaming potential measurement results are more reliable and applicable compared to electrophoresis method to extend to the subsurface setting during a dynamic injection process.

Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs

Wettability of the oil/brine/rock system is an essential petro-physical parameter which governs subsurface multiphase flow behaviour and the distribution of fluids, thus directly affecting oil recovery. Recent studies [1–3] show that manipulation of injected brine composition can enhance oil recovery by shifting wettability from oil-wet to water-wet. However, what factor(s) control system wettability has not been completely elucidated due to incomplete understanding of the geochemical system. To isolate and identify the key factors at play we used SO42—free solutions to examine the effect of salinity (formation brine/FB, 10 times diluted formation brine/10 dFB, and 100 times diluted formation brine/100 dFB) on the contact angle of oil droplets at the surface of calcite. We then compared contact angle results with predictions of surface complexation by low salinity water using PHREEQC software.We demonstrate that the conventional dilution approach likely triggers an oil-wet system at low pH, which may explain why the low salinity water EOR-effect is not always observed by injecting low salinity water in carbonated reservoirs. pH plays a fundamental role in the surface chemistry of oil/brine interfaces, and wettability. Our contact angle results show that formation brine triggered a strong water-wet system (35°) at pH 2.55, yet 100 times diluted formation brine led to a strongly oil-wet system (contact angle = 175°) at pH 5.68. Surface complexation modelling correctly predicted the wettability trend with salinity; the bond product sum ([>CaOH2+][–COO−] + [>CO3−][–NH+] + [>CO3−][–COOCa+]) increased with decreasing salinity. At pH < 6 dilution likely makes the calcite surface oil-wet, particularly for crude oils with high base number. Yet, dilution probably causes water wetness at pH > 7 for crude oils with high acid number.

Drivers of Low Salinity Effect in Carbonate Reservoirs

Wettability alteration appears to be the main mechanism of low salinity water flooding in carbonate reservoirs. However, what factor(s) controls the wettability alteration is not clearly defined. We hypothesized that zeta potential at interfaces of oil/brine and brine/rock controls the wettability alteration in carbonate reservoirs. To test our hypothesis, we removed SO42– ions from the aqueous ionic solutions because SO42– ions likely adsorb at the pore surface, triggering desorption of carboxylic materials. We examined the zeta potential of interfaces of crude oil/brines and brines/rock. We also measured the contact angle and conducted two core-flooding experiments. Moreover, we performed a geochemical study to examine the potential of calcite dissolution by low salinity water using PHREEQC software. Our work demonstrates that contact angle strongly correlates with polarity of the zeta potential of interfaces of oil/brine and brine/rock, showing that the same polarity of zeta potential for oil/brine and...

A Critical Review of Alternative Desalination Technologies for Smart Waterflooding

Summary The importance of tuning injection-water chemistry for upstream is moving beyond formation-damage control/water incompatibility to increasing oil recovery from waterflooding and different improved-oil-recovery (IOR)/enhanced-oil-recovery (EOR) processes. Smart waterflooding through tuning of injection-water salinity and ionic composition has gained good attention in the industry during recent years for IOR in carbonate reservoirs. The water-chemistry requirements for IOR/EOR have been relatively addressed in the recent literature, but the key challenge for field implementation is to find an easy, practical, and optimum technology to tune water chemistry. The currently available technologies for tuning water chemistry are limited, and most of the existing ones are adopted from the desalination industry, which relies on membrane-based separation. Even though these technologies yield an achievable solution, they are not the optimum choice for altering injection-water chemistry in terms of incorporating selective ions and providing effective water management for large-scale applications. In this study, several of the current, emerging, and future desalination technologies are reviewed with the objective to develop potential water-treatment solutions by use of both seawater and produced water that can most efficiently alter injection-water chemistry for smart waterflooding in carbonate reservoirs. Standard chemical-precipitation technologies, such as lime/soda ash, alkali, and lime/aluminum-based reagent, are only applicable for removing certain ions from seawater. The lime/aluminum-based reagent process looks interesting because it can remove both sulfates and hardness ions to provide some tuning flexibility for key ions included in the smart water. There are some new technologies under development that use chemical solvents to extract salt ions from seawater, but their capabilities to selectively remove specific ions need further investigation. Forward osmosis (FO) and membrane distillation (MD) are the two emerging technologies, and they can provide good alternatives to reverse-osmosis (RO) seawater desalination for the near-term. These technologies can offer a more cost-effective solution in which there is availability of low-grade waste heat or steam. The two new desalination technologies, based on dynamic vapor recompression and carrier-gas extraction (CGE), are well-suited to treat high-salinity produced water for zero liquid discharge (ZLD), but they may not be able to provide an economical solution for seawater desalination. Carbon nanotube-based desalination, graphene sheet-based desalination, and capacitive deionization are the three potential future seawater-desalination technologies identified for the long term. Among these, carbon nanotube-based desalination is more attractive, although the technology is still largely under research and development. The results of this review study show that there is no commercial technology yet available to selectively remove specific ions from seawater in one step and optimally meet the desired water-chemistry requirements of smart waterflooding. As a result, different conceptual process configurations involving selected combinations of chemical precipitation, conventional/emerging desalination, and produced-water-treatment technologies are proposed. These configurations represent both approximate and improved soutions to incorporate specific key ions into the smart water selectively, besides presenting the key opportunities to treat produced-water/membrane reject water and provide ZLD capabilities in smart-waterflooding applications. The developed configurations can provide an attractive solution to capitalize on existing huge produced-water resources available in carbonate reservoirs to generate smart water and minimize wastewater disposal during fieldwide implementation of smart waterflood.

Experimental analysis of calcium carbonate scale formation and inhibition in waterflooding of carbonate reservoirs

Deposition of inorganic salts such as calcium carbonate (CaCO3) can cause formation damage and production equipment failure during the development of a reservoir. In case of waterflooding, complex geochemical processes between the injection water, formation water and rock occur and the concentration of ions increases. Major contribution of scale control concentrates on understating the conditions scale formation and its inhibition.In this paper, we analyze experimentally the effect of oil composition and flow conditions on CaCO3 scale formation. We measured the induction period of CaCO3 crystallization in a stirred vessel with different Reynold numbers and the interfacial tension at the boundary between the aqueous scale inhibitor and oil at different percentages of organic components. In addition, we determined the performance of CaCO3 scale inhibition under different static and dynamic conditions in some Iranian carbonate core samples.The experimental results showed that if the interfacial tension was reduced by increasing the concentration of organic components to 1.5%, the CaCO3 precipitation decreases more than 30%. In addition, increasing the flow velocity (Reynolds number) had a great influence on the increase in the induction period of CaCO3 crystallization. However, the induction period was insignificantly changed at higher values.Using a recently developed scale inhibitor, we kept the CaCO3 formation at a constant concentration of 30mg/L. The efficiency of the inhibitor was insignificantly reduced if the temperature is increased up to 120°C. Core flooding experiments show that formation damage due to CaCO3 precipitation depends on the injection rate of the solution. In addition, the formation damage was mitigated to the 93% of initial permeability of the core samples. The results of this work improve our understanding from CaCO3 formation and can be used to predict and prevent it during waterflooding process in carbonate reservoirs.

Potential of Low-Salinity Waterflood To Improve Oil Recovery in Carbonates: Demonstrating the Effect by Qualitative Coreflood

Summary Low-salinity waterflood (LSF) is a promising improved-oil-recovery (IOR) technology. Although, it was demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in carbonate reservoirs is still not well-established because only a limited number of successful coreflood experiments are available in the literature. Therefore, the aim of this study was to examine the oil-recovery improvement by LSF in carbonate reservoirs by performing coreflood experiments. This paper proposes an experimental approach to qualitatively evaluate the potential of LSF to improve oil recovery and alter the rock wettability during coreflood experiments. The corefloods were conducted on core plugs from two Middle Eastern carbonate reservoirs with a wide variation of rock properties and reservoir conditions. Seawater (SW) and several dilutions of formation brine and SW were flooded in the tertiary mode to evaluate their impacts on oil recovery compared with formation-brine injection. In addition, a geochemical study was performed with PHREEQC software (Parkhurst and Appelo 1999) to assess the potential of calcite dissolution by LSF. The experimental results confirmed that lowering the water salinity can alter the rock wettability toward more water-wet, causing improvement of oil recovery in tertiary waterflood in plugs from the two reservoirs. Furthermore, SW is more-favorable for improved oil recovery than formation brine because injection of SW after formation brine resulted in extra oil production. This demonstrates that the brine composition plays an important role during waterflooding in carbonate reservoirs, and not only the brine salinity. It was also observed that oil recovery can be improved by injection of brines that cannot dissolve calcite on the basis of the geochemical modeling study. This implies that calcite dissolution is not the dominant mechanism of IOR by LSF. To conclude, this paper demonstrates that LSF has a good potential as an IOR technology in carbonate reservoirs. In addition, the proposed experimental approach ensures the verification of LSF effect, either it is positive or negative. However, further research is required to explore the optimum salinity and composition and the most-influential parameters affecting LSF response.

Review of Recovery Mechanisms of Ionically Modified Waterflood in Carbonate Reservoirs

Advanced waterflooding is a process in which the ionic strength as well as the ionic composition of the injected water is tuned to improve the oil recovery. It has been observed in field trials and in lab coreflooding experiments; advanced waterflooding has the potential to recover additional oil. This process has been evaluated as a wettability-modifying agent in carbonates and captured the global research focus in water-based enhanced oil recovery (EOR) methods. This paper provides a comprehensive review of the published research to speed the process of further investigations in this field. The review provides the most current information to the reader about advanced waterflooding and a guide to the relevant papers for those who are new in this field.

Impact of Multi-ion Interactions on Oil Mobilization by Smart Waterflooding in Carbonate Reservoirs

The injected brine composition has been observed to have intense effect on efficiency of waterflooding in carbonate reservoirs. This process is known as smart waterflooding and has proved to be an effective process in improving oil recovery. Different approaches have been tested in carbonate reservoirs due to the complexity of the process. Based on these approaches, different mechanisms have been proposed with some level of uncertainties. This has led to several arguments on the chemical mechanisms responsible for such feat achieved. One of the approaches is discussed in this paper, however with much interpretation considering all factors influencing the oil-brine-rock interactions. Therefore, this paper presents the influence of multi-ion interactions during smart water flood on carbonates. Sequential flooding of formation brine and smart brines and the effluent ion analysis were conducted to confirm the multi-ion interactions leading to improved recovery. In addition, zeta potential measurement was conducted to examine the alteration process and correlated with the core flood results. The results from zeta potential measurement showed that multi-ion interaction alters the rock surface charge, which led to more water-wetness. Significant improvement in oil displacement efficiency was observed beyond the secondary waterflood and effluent ionic analysis demonstrated that these multi-ionic interactions led to the observed alteration.

A Mechanistic Model for Wettability Alteration by Chemically Tuned Waterflooding in Carbonate Reservoirs

Summary Injection of chemically tuned brines into carbonate reservoirs has been reported to enhance oil recovery by 5–30% original oil in place (OOIP) in coreflooding experiments and field tests. One proposed mechanism for this improved oil recovery (IOR) is wettability alteration of rock from oil-wet or mixed-wet to more-water-wet conditions. Modeling of wettability-alteration experiments, however, is challenging because of the complex interactions among ions in the brine and crude oil on the solid surface. In this research, we developed a multiphase and multicomponent reactive transport model that explicitly takes into account wettability alteration from these geochemical interactions in carbonate reservoirs. Published experimental data suggest that desorption of acidic-oil components from rock surfaces make carbonate rocks more water-wet. One widely accepted mechanism is that sulfate (SO42−) replaces the adsorbed carboxylic group from the rock surface, whereas cations (Ca2+, Mg2+) decrease the oil-surface potential. In the proposed mechanistic model, we used a reaction network that captures the competitive surface reactions among carboxylic groups, cations, and sulfate. These reactions control the wetting fractions and contact angles, which subsequently determine the capillary pressure, relative permeabilities, and residual oil saturations. The developed model was first tuned with experimental data from the Stevns Klint chalk and then used to predict oil recovery for additional untuned experiments under a variety of conditions where IOR increased by as much as 30% OOIP, depending on salinity and oil acidity. The numerical results showed that an increase in sulfate concentration can lead to an IOR of more than 40% OOIP, whereas cations such as Ca2+ have a relatively minor effect on recovery (approximately 5% OOIP). Physical parameters, including the total surface area of the rock and the diffusion coefficients, control the rate of recovery, but not the final oil recovery. The simulation results further demonstrate that the optimum brine formulations for chalk are those with relatively abundant SO42− (0.096 mol/kg water), moderate concentrations of cations, and low salinity (total ionic strength of less than 0.2 mol/kg water). These findings are consistent with the experimental data reported in the literature. The new model provides a powerful tool to predict the IOR potential of chemically tuned waterflooding in carbonate reservoirs under different scenarios. To the best of our knowledge, this is the first model that explicitly and mechanistically couples multiphase flow and multicomponent surface complexation with wettability alteration and oil recovery for carbonate rocks specifically.

Waterflooding in Carbonate Reservoirs: Does the Salinity Matter?

Summary Waterflooding has been used for decades as a secondary oil-recovery mode to support oil-reservoir pressure and to drive oil into producing wells. Recently, the tuning of the salinity of the injected water in sandstone reservoirs was used to enhance oil recovery at different injection modes. Several possible low-salinity-waterflooding mechanisms in sandstone formations were studied. Also, modified seawater was tested in chalk reservoirs as a tertiary recovery mode and consequently reduced the residual oil saturation (ROS). In carbonate formations, the effect of the ionic strength of the injected brine on oil recovery has remained questionable. In this paper, coreflood studies were conducted on Indiana limestone rock samples at 195°F. The main objective of this study was to investigate the impact of the salinity of the injected brine on the oil recovery during secondary and tertiary recovery modes. Various brines were tested including deionized water, shallow-aquifer water, seawater, and as diluted seawater. Also, ions (Na+, Ca2+, Mg2+, and SO42−) were particularly excluded from seawater to determine their individual impact on fluid/rock interactions and hence on oil recovery. Oil recovery, pressure drop across the core, and core-effluent samples were analyzed for each coreflood experiment. The oil recovery using seawater, as in the secondary recovery mode, was, on the average, 50% of original oil in place (OOIP). A sudden change in the salinity of the injected brine from seawater in the secondary recovery mode to deionized water in the tertiary mode or vice versa had a significant effect on the oil-production performance. A solution of 20% diluted seawater did not reduce the ROS in the tertiary recovery mode after the injection of seawater as a secondary recovery mode for the Indiana limestone reservoir. On the other hand, 50% diluted seawater showed a slight change in the oil production after the injection of seawater and deionized water slugs. The Ca2+, Mg2+, and SO42− ions play a key role in oil mobilization in limestone rocks. Changing the ion composition of the injected brine between the different slugs of secondary and tertiary recovery modes showed a measurable increase in the oil production.

Water Flooding of Carbonate Reservoirs: Effects of a Model Base and Natural Crude Oil Bases on Chalk Wettability

Polar components, especially the carboxylic material in crude oil, are known to have great impact on the wetting conditions of carbonates. The water-wetness decreases as the acid number, AN, of the crude oil increases. The success of enhanced oil recovery by water flooding in fractured carbonates is strongly dependent on the wetting conditions of the formation. The impact on wettability of basic compounds present in crude oil has received much less attention than that of carboxylic material, even though the base number, BN, is usually much higher than the AN. Furthermore, acids and bases present in crude oil will react with each other to form acid−base complexes. In this paper, we have studied the impact of basic components on the wetting properties of chalk by using an oil with a constant AN = 0.5 mg KOH/g oil and varying the AN/BN ratio in the range of 0.24−4.6. The initial water saturation was varied from 0 to 47%. The relative impact of basic material on the wetting properties was studied by means of ...

A Method for Predicting Vertical Sweep Efficiency of Waterflooding in Carbonate Reservoirs and the Relative Permeability Curves for the Mathematical Reservoir Simulation

The vertical sweep efficiency of waterflooding in carbonate reservoirs and the associated relative permeability-saturation relationship were studied with a mathematical reservoir model. The model consisted of 30×25 or 15×10 cells, and the rock properties of each cell were characterized so that the model represented the cross section of carbonate reservoirs. A production well and an injection well were located on each side of the model, and seven cases of waterflooding performance were calculated with various distribution of reservoir rock properties. The performance was then compared with those predicted by three vertical sweep efficiency calculation methods, and it was concluded that the vertical sweep efficiency was best predicted by taking an average of the efficiencies by the two methods: a method based on the Buckley-Leverett displacement principle6) assuming a reservoir consisting of one layer, and the Stiles method5) with the above displacement principle using the smoothed permeability profiles determined by the Fourier series trend analysis. Meanwhile the Stiles method using the unmodified permeability profile of cells penetrated by the injection well gave very low vertical sweep efficiencies in many cases.Investigation of the absolute permeability revealed that the geometric average of permeabilities of cells penetrated by the wells was almost as large as the absolute permeability of the reservoir determined by the reservoir performance but the arithmetic average was greater, when the horizontal variation of the cell permeability was large, while the arithmetic average was as large as the reservoir permeability but the geometric average was smaller, when the horizontal variation was small.It was also concluded that the relative permeability, which gives nearly 110% of the predicted vertical sweep efficiency if no truncation error is envisaged, should be employed in a large cell model with only one intermediate cell between the injection well cell and the production well cell, in order to compensate for an effect of truncation errors on the efficiency.