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.

Modified or low-salinity waterflooding of carbonate oil reservoirs is of considerable economic interest because of potentially inexpensive incremental oil production. The injected modified brine changes the surface chemistry of the carbonate rock and crude oil interfaces and detaches some of adhered crude oil. Composition design of brine modified to enhance oil recovery is determined by labor-intensive trial-and-error laboratory corefloods. Unfortunately, limestone, which predominantly consists of aqueous-reactive calcium carbonate, alters injected brine composition by mineral dissolution/precipitation. Accordingly, the rock reactivity hinders rational design of brines tailored to improve oil recovery. Previously, we presented a theoretical analysis of 1D, single-phase brine injection into calcium carbonate-rock that accounts for mineral dissolution, ion exchange, and dispersion (Yutkin et al. in SPE J 23(01):084–101, 2018. https://doi.org/10.2118/182829-PA). Here, we present the results of single-phase waterflood-brine experiments that verify the theoretical framework. We show that concentration histories eluted from Indiana limestone cores possess features characteristic of fast calcium carbonate dissolution, 2:1 ion exchange, and high dispersion. The injected brine reaches chemical equilibrium inside the porous rock even at injection rates higher than 3.5 × 10- 3 m s- 1 (1000 ft/day). Ion exchange results in salinity waves observed experimentally, while high dispersion is responsible for long concentration history tails. Using the verified theoretical framework, we briefly explore how these processes modify aqueous-phase composition during the injection of designer brines into a calcium-carbonate reservoir. Because of high salinity of the initial and injected brines, ion exchange affects injected concentrations only in high surface area carbonates/limestones, such as chalks. Calcium-carbonate dissolution only affects aqueous solution pH. The rock surface composition is affected by all processes.

The fundamental study of adsorption in this manuscript pertains to a well-known process of low salinity water flooding (LSW), which is a potentially economic way of incrementing productivity of oil reservoirs. Our preliminary results indicate adsorption of a positively charged surfactant CTAB (cetrimonium bromide) regardless of brine type and charge at the surface. We show that the surfactant behavior mimics that found at charged crude oil-brine interfaces. This result partially explains strong crude oil interaction with calcium carbonate and adds to the difficulties associated with oil extraction by LSW.

© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. The fundamental study of adsorption in this manuscript pertains to a well-known process of low salinity water flooding (LSW), which is a potentially economic way of incrementing productivity of oil reservoirs. Our preliminary results indicate adsorption of a positively charged surfactant CTAB (cetrimonium bromide) regardless of brine type and charge at the surface. We show that the surfactant behavior mimics that found at charged crude oil-brine interfaces. This result partially explains strong crude oil interaction with calcium carbonate and adds to the difficulties associated with oil extraction by LSW.

Low-salinity waterflooding (LSW) is ineffective when reservoir rock is strongly water wet or when crude oil is not asphaltenic. Success of LSW relies heavily on the ability of injected brine to alter surface chemistry of reservoir rock-brine-crude oil interfaces. LSW in carbonate reservoirs is especially challenging because of high brine salinity and, more importantly, because of high reactivity of the rock minerals. Here, we tackle the complex physicochemical processes in chemically active carbonates flooded with diluted brine that is saturated with atmospheric CO2 and possibly supplemented with additional ionic species, such as sulfates or phosphates. Later work will focus on the important role of crude oil and multicomponent ion-exchange (MIE) in LSW. When waterflooding carbonate reservoirs, rock equilibrates with the injected brine over short distances. Injected-brine ion speciation is shifted substantially in the presence of reactive-carbonate rock. Our new calculations demonstrate that rock-equilibrated aqueous pH is slightly alkaline quite independent of injected-brine pH. We establish, for the first time, that carbon-dioxide content of a carbonate reservoir, originating from CO2-rich crude oil and gas, plays a dominant role in setting aqueous pH and speciation. A simple ion-complexing model predicts calcite surface charge as a function of composition of reservoir brine. The surface charge of calcite may be positive or negative depending on speciation of reservoir brine in contact with the calcite. There is no single point of zero charge; all dissolved aqueous species are charge determining. Rock-equilibrated aqueous composition controls calcite surface ionexchange behavior. At high ionic strength, the electrical double layer collapses and is no longer diffuse. All surface charges are located directly in the inner and outer Helmholtz planes. Our evaluation of calcite bulk and surface equilibria is preliminary but draws several important inferences about proposed LSW oil-recovery mechanisms. Diffuse double layer expansion (DLE) is not possible unless brine ionic strength is below 0.1 molar. Because of rapid rock/brine equilibration, the dissolution mechanism for releasing adhered oil is eliminated. Also, fines mobilization and concomitant oil release cannot occur because there are few loose fines and clays in a majority of carbonates. LSW cannot be a low interfacial-Tension alkaline flood because carbonate dissolution exhausts all injected base near the wellbore and lowers pH to that set by the rock and by formation CO2. In spite of diffuse double-layer collapse in carbonate reservoirs, surface ion-exchange oil release remains feasible, but unproven.

Low salinity water flooding (LSW) has gained significant attention, because of its advantages comparedwith other enhanced oil recovery (EOR) methods. LSW's positive contribution to recovery factor has beendemonstrated in the literature at lab and field scales. However, LSW flooding does not always incrementoil recovery. It is a specific combination of properties of an asphaltenic crude oil, chemically equilibratedbrine, and rock surface that may explain the success or failure of LSW. In this work, we introduce anovel experimental approach to study asphaltene-like chemical interactions with surfaces rock minerals toevaluate the effectiveness of applying LSW. When studying the impact of asphaltene properties on incremental recovery, one aims to detach someof the immobile oil, which is semi-irreversibly stuck on rock surface. This is a difficult task, because ofvarying crude oil composition, as well as asphaltene interfacial and chemical properties. To overcomethese issues, we split the problem into several parts. We study how mono- and poly-functional chemicalcompounds mimic asphaltene interactions with mineral surfaces, like silica and calcium carbonate, whichare proxies for sandstones and limestones, respectively. For example, amines, quaternary ammonia orcarboxylates represent asphaltene functional groups that are mainly responsible for crude oil base andacid numbers, respectively. Adsorption of polymers and oligomers containing such groups mimics theirreversible asphaltene deposition onto rock surface through formation of chemically active polymerlikestructures at the oil-brine interface. The silica surface is negatively charged in brines with pH above 2. Silica attracts positively chargedammonia salts, such as cetrimonium chloride (CTAC). However, negatively charged mono-functionalcarboxylates, i.e. anionic surfactants, like sodium hexanoate (NaHex), hardly adsorb onto silica, even in thepresence of a bridging ion, like calcium. In contrast to silica, calcium carbonate surface has both positive and negative charges on its surface. Wefound that CTAC adsorbs onto calcium carbonate in any brine tested. NaHex shows minimal adsorption onto calcium carbonate only in the presence of calcium ions suggesting a contribution of an ion-bridgingmechanism. Adsorption of all studied mono-functional surfactants is fully reversible and, consequently notrepresentative of asphaltenes. Multifunctional compounds, i.e., polymers, demonstrate irreversible,asphaltene-like, adsorption. We studied adsorption of carbohydrates decorated with individual amines andquaternary ammonia functional groups. The carbohydrates with amine functional groups adsorb irreversibly on calcium carbonate and silica inall tested brines with pH up to 10. Therefore, a lower base number (BN) in crude oils indicates a higherpotential for LSW. Our findings demonstrate the proof of concept that contribution of different functional groupsto asphaltene adsorption/deposition can be studied using functionalized water-soluble polymers. Thisframework is useful for assessment of adsorption strength vs. number of active groups as well as screeningof efficient detachment process of asphaltenic crude oils from rock surface.