CO 2 geological storage (CCS)isconsidered as the most promising technique to reduce atmospheric CO 2 emissions. However, due to the density variation between the injected supercritical CO 2 and the formation water,CO 2 tends to move vertically toward the air. This vertical CO 2 leakage can be prevented by four trapping mechanisms (i.e. structural trapping,capillary trapping, solubility trapping, and mineral trapping). The capacities of structural and residual trapping are highly affected by rock wettability. Clay wettability is one of the crucial parametersin evaluation of CO 2 geo-sequestration. However, the literature data show that there are many uncertainties associated with experimental measurements. One of these uncertainties is the influenceof the effect of gas density on the clay mineral wettability. Thus, here, we compared the wettability of a clay mineral (i.e. illite) of three different gas densities scenarios (i.e. low (Helium), moderate (Nitrogen), and high (CO 2 ) gas densities). To do so, we measured the advancing and receding contact angle (i.e. wettability) of illite for CO 2 /water, nitrogen/water, and Helium/water systems at a constant (333 K) and four different pressures (5, 10, 15, and 20 MPa). The brine composition used was 4 wt% NaCl, 4 wt% CaCl2, 1 wt% MgCl2 and 1 wt% KCl, for all gas density scenarios. The results indicate that gas density has a significant effect on the clay mineral wettability and that both advancing and receding contact angles increase with an increase in gas density. The results show that a higher density gas scenario has a higher contact angle of illite, measured at the same temperature and pressure. For instance, the advancing contact angle of illite at 333 K and 20 MPa was 65° for the CO 2 /water system, 53° for the nitrogen/water system, and 50° for Helium/water Helium/water system. Thus, we conclude that the gas density affects the Clay wettability measurement and that the higher gas density leads to a higher contact angle measurements (i.e. a more CO 2 -wet system) of the clay and thus reduces the estimated CO 2 geo-sequestration capacity and containment security.

We investigated the utility of a modified Washburn method, combining results of two sorption experiments, to study wettability alteration processes. The main objective in deploying this technique was to avoid the difficulty of direct contact angle measurements in surfactant solutions. In such cases, the ultra-low interfacial tension between the crude oil and surfactant tends to cause the oil drop to spread prematurely rendering the measurement unreliable if possible at all. A carbonate-rock, dead crude oil, synthetic brines including SmartWater, and five surfactants were used in this study. The surfactants included: an anionic alfa olefin sulfonate, a cationic quaternary ammonium salt, an amphoteric surfactant, a nanosurfactant, and a nonionic ethoxylated alchohol. Hexane was also used as a reference completely wetting fluid. For sorption experiments, the rock was powdered. The powder with size between 80 and 100 mesh was compacted in the sample holder. In each experiment, a given fluid was raised to the bottom of the powder pack and allowed to rise into the powder by capillarity. A sensitive balance was used to measure fluid imbibition into the powder until no more fluid imbibes. Beside sorption experiments, surface and interfacial tension measurements were made. For benchmarking, we relied on previous findings reported in the literature. Plotting the square of fluid mass against time gave a slope which enabled the calculation of contact angle in air. The results (slope) observed for the completely wetting fluid (hexane) provided the rock constant. Sorption results of crude oil coupled with the previously determined rock constant enabled estimation of the Wasburn oil/air contact angles using the modified Washburn equation. Sorption results with brine and surfactant solutions coupled with the rock constant and oil/air enabled estimation of the Washburn water/air contact angles using the modified Washburn equation. Based on water/air and oil/air contact angles, values of the conventional oil/water contact angle were estimated. For surfactant solutions, interfacial tension between oil and surfactant-free brine were used to approximate contact angles that were otherwise undefined. This approach, enabled a robust and rapid estimation of the effects of various processes on contact angles (hence wettability alteration). Based on the benchmark previous findings, the sorption approach yielded acceptable results especially for screening purposes. The results demonstrated the potential of the Smartwater recipe and the nonionic surfactant for wettability alteration. However, it is recommended to rely on the sorption method direct measurements including sorption rates to establish sorption-based wettability indices and eliminate the intermediary and probably unnecessary contact-angle estimation step. In conclusion, the use of sorption to obtain contact-angle estimates provide a novel rapid and robust procedure for evaluation and screening of wettability-alteration agents. This eliminates direct contact angle measurements that are often cumbersome. It specifically eliminate the difficulties of attaching an oil drop onto a rock surface immersed in surfactant solutions.

Low salinity (LS) water flooding in the sandstone reservoir is of pronounced interest of the prospective for improved oil recovery. In this study, laboratory experiments in low-permeable sandstone core plugs saturated with various crude oil containing different acid numbers were presented. Several low-permeable sandstone cores (1-3 mD) were taken from Bartlesville Sandstone Reservoir from Eastern Kansas were successively flooded with seawater and different LS water. The reservoir cores were cleaned and saturated with formation water (FW) and then aged in three kinds of crude oil (different acid numbers) for six weeks at 90°C. To evaluate LS water in the low-permeable reservoir core plugs, core flooding tests were performed. Contact angle and spontaneous imbibition tests were also carried out. The results obtained from LS water flooding showed that an improvement in oil recovery up to 12% of the original oil in place when the acid number (AN) and core permeability were low. The water wetness, and in turn, the oil recovery reduced with increased crude oil's AN and as the permeability increased. The contact angle and spontaneous imbibition tests confirmed the appropriate wettability change is attainable with LS water flooding. The results were deliberated in relation to wettability change processes by LS Water.

Foam assisted lift is a vital significant technology for gas well deliquification. The foamer is injected into the wellbore, then the liquid in the hole is changed into foam by gas agitation, which can be carried to the surface by gas flow easily. The returned fluid should be defoamed before separator. Solid defoamers are often used to eliminate these foam. But there are many problems of solid defoamers, such as poor performance, short shelf lift and high cost, which affected its effectiveness seriously. To solve these issues, A new nano solid defoaming agent is presented in this paper. It consists of simethicone, hydrophobic nanoparticles, emulsifier and solidifying agent. The hydrophobic nanoparticles have improved the performance of new solid defoamer greatly. The characteristics of the new defoamer, including solubility, defoaming performance and anti-foaming performance are analyzed. Furthermore, the new defoamer was applied in a large amount of gas wells to validate its effectiveness and economy. And the field application results proved that the new solid defoamer is superior to the conventional solid defoamers in performance and economy.

Secondary oil recovery by waterflooding is usually achieved in neutrally and water wet reservoirs. Special core analysis (SCAL) data are difficult to obtain and expensive, we therefore generate experimentally-derived petrophysical correlations based on SCAL experiments conducted on neutrally wet sandstone in order to further understand maximizing oil recovery. The key objectives of the present study are to obtain and analyze the possible relationships between the reservoir petrophysical properties that are essential for reservoir simulations. The experimentally obtained petrophysical parameters and generated relationships are compared versus the prevailing initial water saturation, absolute permeability and wettability. Experimental results are then compared with network modeling results from the literature. Network modeling is a promising tool that has many usages including the convenient estimation of capillary pressure, relative permeability and residual oil saturation that would otherwise be obtained through lengthy and expensive SCAL experiments. However, network modeling predictively has been questioned in terms of making a full priori prediction of multiphase flow properties in mixed and neutrally wet systems as true representation of pore geometry and wettability are most challenging. Scaled, two-phase oil-water system, endpoint relative permeability was found to be linearly and strongly correlated to wettability. Residual oil saturation, however, was found to be curvilinear upward correlated to Amott-Harvey wettability. Comparing the experimental results of the present study with previous network model results, limited agreement was observed. Disagreement was mainly due to pore space wettability misrepresentation in network models. The representation of neutral wettability is the path towards more realistic physical description of pore-scale multiphase flow since most reservoirs tend to show some degree of neutral wettability.

The wettability of conventional reservoirs have been extensively studied in the past. However, Shale is rich in organic matter, composed of many mineral components in complex relationships, and contains pores of various scales from micrometer to nanometer, so it is very difficult to evaluate the wettability of shale. In this study, low field nuclear magnetic resonance (NMR) was used to test the water wettability of shale and a new mixed wettability model was built to quantitatively calculate the organic matter contact angle and evaluate the water wettability of organic matter. The experimental results show that the surface of the shale exhibits complex non-uniform mixed wettability, both oil-wet and water-wet; with the increase of soaking time, the water wettability of shale enhances significantly and the equilibrium time of water imbibition is 5-10 days; the average contact angle of water with organic matter is 75.2°, indicating water can enter organic matter pores, but at weaker capacity than entering inorganic pores. The research results are helpful for making clear the micro mechanism of the action between fracturing fluid and shale reservoir and designing fracturing scheme.

Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery. Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage. The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.

Smart Water and Low Salinity EOR is established as a techno-economically promising method through laboratory coreflood studies and single well tracer studies in field pilot cases. The method is based on lowering salinity of injected water and spiking of multivalent ions such as Mg 2+ , SO 4 2− , PO 4 3− ions. Wettability alteration and expansion of electrical double layer are attributed to the trapped oil release mechanism. This however invites the possibilities of induced and aggravated scale deposition if the formation water is rich in divalent cations (as in the case of carbonate formation). The resulting formation damage and reduced well productivity may negate the advantages of smart waterflood. This article presents the outcome of an extensive study, conducted to optimize smart water composition targeting an offshore carbonate reservoir. After quantifying the scaling potential at reservoir condition, a Polyphosphate compound is introduced which arrested the scale precipitation. Through contact angle, interfacial tension, Zeta-potential and drainage studies it is established that new formulation not only has reduced scaling potential but also enhanced ability for oil recovery.

The wettability of CO 2 -brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behaviour of this system to pressure, temperature and brine salinity. We report results of an investigation into the impact of reservoir conditions on capillarity and multiphase flow through effects of wetting. The semi-dynamic capillary pressure core flooding technique was used with in situ saturation monitoring. The observations were made using a reservoir condition core-flooding laboratory that included high precision pumps, temperature control, the ability to recirculate fluids for weeks at a time and an x-ray CT scanner. The wetted parts of the flow-loop are made of anti-corrosive material that can handle co-circulation of CO 2 and brine at reservoir conditions. Eight reservoir condition capillary pressure characteristic curves were measured using CO 2 and brine in single fired Berea sandstone at pressures (5 to 20 MPa), temperatures (25 to 50°C) and ionic strengths (0 to 5 M kg -1 NaCl) representative of subsurface reservoirs. A ninth measurement using an N 2 -water system provided a benchmark for capillarity with a strongly water wet system. In all cases, the capillarity of the system, scaled by the interfacial tension, were equivalent to the N 2 -water system within measurement uncertainty. Thus reservoir conditions did not have a significant impact on the capillary strength of the CO 2 -brine system through a variation in wetting. In this work we report the results of the first study looking systematically at the impacts of reservoir conditions on the effective wettability in the CO 2 -brine-sandstone system. A new method is presented to quantify shifts in effective wetting properties with changing reservoir conditions. We find no impact within the range of reservoir and flow conditions relevant to CO 2 storage, consistent with traditional multiphase flow theory but despite observations by others suggesting that wetting properties and multiphase flow in this system are sensitive to pressure, temperature and brine salinity. This provides definitive confirmation that the CO 2 - brine system performs as a strongly water-wet system in sandstone rocks and the use of analogue fluids for this characterisation may be useful when the full reservoir conditions cannot be replicated in the laboratory. The spatial saturations were also investigated using x-ray computed tomography and were found to be invariant with different reservoir conditions in homogeneous samples. The findings confirm the role of residual trapping in capacity estimates and provide a comprehensive dataset for flow modelling in water wet reservoirs.

Abstract Water separation from crude oil inside oil transport pipelines causes the water to wet the inner steel surface of the pipe and leads to corrosion and leaks. Factors that affect the water settlement inside pipelines, interchangeably called as water-wetting phenomenon, are major areas of research. Previous studies focused on the physical properties of crude such as density, viscosity, interfacial tension and water-in-oil contact angle as factors affecting water wetting. In those studies, alteration of physical properties toward preventing water wetting inside crude pipelines was attributed to the presence of surface-active compounds in the crude oils, which promotes smaller water droplets, oil adsorption to the steel surface thus oil wetting; this was concluded through artificial mixing of selected surface active compounds with model oils. In the current paper, we will determine whether the natural presence of surface-active compounds in crude oils can only explain the alteration of the steel wettability of actual oils or not. To achieve that, a water-wetting study is conducted on a model oil blend mixture with 1% myristic acid, a carboxylic acid surface-active compounds, which mimics the PNA distribution and physical properties of an actual type of crude oil produced from a certain field. Using a doughnut cell wetting measurement apparatus, it was found that the model oil blend mixture with the myristic acid has reduced water wetting transition velocity by 60% compared to that of an actual crude of the similar physical properties. This indicates that the crude composition might have a higher impact on the water-wetting phenomena regardless of the natural presence of the surface-active compounds in the crude oil. Introduction Crude oil transport pipelines experience a significant increase in pipeline damage due to internal corrosion as oil fields mature. It is not coincidental that frequency of internal corrosion damage increases as the water-cut in the throughput continues to increase. In such situations, oil transport pipelines become oversized due to the low production rates which reduces the liquid velocities and allows free water to separate from the oil, thereby aggravating the corrosion environment in the pipeline. Previous experiments were conducted and predication models were developed to calculate the velocities below which water dropout occurs. In these models, water wetting transition velocity is dependent on physical properties of the fluid that includes fluid density, viscosity, oil-water interfacial tension, pipe diameter (Hinze 1955, Brauner 2001 and Tang 2011) and water-in-oil contact angle (Tang 2011). According to these models, oil wetting is promoted by higher density, higher viscosity, lower interfacial tension and larger water-in-oil contact angle. Compared to actual crude oils, model oils have higher tendency toward water wetting, which was attributed to the natural presence of surface-active compounds in crude oils (Ayello 2013). The adsorption of surface-active compounds at the metal surface can create an organic protective film and its presence in the oil-water interface reduces the oil-water interfacial tension, which prevents water droplets from wetting the steel surface (Ayello 2013).

Abstract Injection of CO2 into the subsurface is of interest for CO2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine-rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks. Introduction Uncertainty around CO2 storage and EOR may be significantly reduced from a greater understanding of the fundamental physics of fluid flow and reactive transport that control rock-brine-CO2 interaction in the subsurface. The combination of unique multiphase flow properties and significant reactivity in the CO2-brine-carbonate rock system has major impacts on the injection, flow and immobilization of CO2 in the subsurface. These unique properties must be accurately characterized to reduce major uncertainties for CO2 storage and EOR in carbonate rocks. Observations of reservoir condition multiphase flow and reactive transport properties for the CO2-brine-carbonate rock system are provided including wetting properties, capillary pressure, relative permeability and residual trapping. A methodology is presented for utilizing a combination of novel and traditional core-flooding and imaging techniques for a comprehensive characterization of carbonate reservoir rock.

Abstract Reservoir wettability has direct impact on the relative movement of reservoir fluids and oil displacement efficiency by EOR techniques. The industry standard wettability laboratory techniques of Amott, USBM and modified Amott/USBM are very time demanding due to its complex experimental setup and procedure. This paper describes the theory and experimental setup and procedure of a new wettability laboratory technique. Rise In Core, RIC, technique is based on a modified version of the Washburn Equation. The modified equation could be solved for the wettability contact angle by only substituting the slope of a fitted straight line of the square line of the square of core sample mass change with time, resulting from either water imbibition into oil saturated core sample, and/or vice versa. A constant of the equation, that is characteristic of the rock type, needs to be determined prior, however, by conducting an imbibition experiment of a reference liquid into air saturated twin core sample. The reference liquid completely wets the core sample with zero contact-angle. The new technique was applied to measure the wettability of Berea sandstone core samples. The wettability of natural outcrop cores was found to be weakly water wet. Experiments conducted on neighboring samples, produced similar wettability result, indicating good repeatability. The applicability of the RIC in other wettability regions was also tested, resulting in repeated strong wetness for standards that were artificially treated to be either strongly water wet, and oil wet. The technique was also compared to the existing industry technique and proved to provide equivalent and more consistent wettability measurements for more than ten twins of carbonate core samples. RIC technique is theoretically sound, and requires simple experimental setup and procedure. Moreover, it determines wettability in terms of contact angles rather than wettability index. It is more consistent and applicable to all wettability regions.

Abstract One of the challenges in slickwater fracturing of tight sand gas reservoirs is post-treatment fluid recovery. More than 60% of the injected fluid remains in the critical near wellbore area and has a significant negative impact on the relative permeability to gas and well productivity. The trapped water could be due to capillary forces around the vicinity of the fractured formation. For strongly water-wet tight gas reservoirs, capillary forces promote the retention of injected fluids in pore spaces. Commonly available surfactants are added to slickwater to reduce surface tension between the treating fluids and gas. The problem with surfactants is that upon exposure to the formation, they adsorb on the surface of the rock. The addition of microemulsion to the fracturing fluid can result in lowering the pressure needed to displace injected fluids and/or condensate from low permeability core samples. This alteration of the fracturing fluid effectively lowers the capillary forces in low permeability reservoirs. This will result in removal of water and condensate blocks, the mitigation of phase trapping, and therefore an increase in permeability to gas. This paper examines the effectiveness of microemulsions in the improvement of fracturing fluid recovery. Coreflood runs using 20 in. Bandera sandstone cores with residual condensate and water showed that the percentage of permeability regained due to treatment with microemulsion solutions was up to 150% depending on type of microemulsion. An environment-friendly microemulsion formulated with a blend of a novel anionic surfactant, nonionic surfactant, short chain alcohol and water showed very good results in lowering interfacial tension between water and oil, when compared with competitive technologies. The performance of this microemulsion was excellent in high salinity fluid as well as low salinity fluid. It was excellent for solubilizing liquid condensates which can be found in wet gas wells. Contact angle of 63.45 degrees makes this microemulsion an optimal solution for cleanup of the near wellbore area. The resulting capillary pressure for a frac fluid treated with 0.25 wt% of this chemical in 2 wt% KCl is nearly 300 times lower than untreated fluid and 30 times lower than a fluid treated with competitive technologies. Introduction Condensate-banking has become an important source of damage and reducing the well productivity. The effective permeability to gas reduces dramatically as a result of accumulated condensate near the wellbore and subsequently decreases the productivity of the well. In gas reservoirs, the use of water-based fluid creates fluid retention problems and becomes more pronounced, as the combination introduces an additional phase to the reservoir, including an additional reduction in the effective permeability to the gas phase (Franco et al. 2013). Large quantities of fluid that has been trapped in the near wellbore area in the reservoir and in the case of fracturing, the fluid that have been trapped in the area surrounding the fracture and within the fracture itself, have detrimental effects on the relative permeability, the effective flow area, and effective fracture length, and impairs well productivity (Penny et al. 2005).

Abstract The study presents an innovative cement spacer fluid based on microemulsion technology and an operationally simple cement design using a water-based multifunctional polymer. A case history is described where their combination was successfully applied on a deepwater exploration well in the South China Sea. Laboratory testing, modeling, and engineering design that preceded the field operation are outlined. The spacer's performance to clean the mud from contact surfaces was verified with the goniometer method. Mud/spacer and spacer/cement tests for optimum compatibility were conducted and a fluid friction pressure chart for the mud-spacer-cement train at different displacement rates was generated. The results show that the designed spacer is highly effective in displacing the mud and converting an oil-wet surface to a water-wet surface, and therefore to provide a clean and water-wet surface to which cement can strongly bond. A water-based multifunctional polymer in the designed cement slurry was tested to validate its ability to adjust slurry properties for deepwater challenges. The cement slurry was easy to mix at surface, stable under downhole conditions, and had a sufficient short transition time at low temperature, preventing water and gas intrusion. Furthermore the evaluated multifunctional polymer was found to work as a stabilizer and extender as well as provide very good fluid loss, free fluid, and gas control. As a consequence, the multifunctional polymer reduces the total number and amount of required chemicals, thereby simplifying logistics and operations for deepwater wells. The presented spacer and cementing technologies contribute to successful zonal isolation of deepwater wells and so minimize risks as well as expensive rig and nonproductive times due to remedial work.

Abstract A pilot study to evaluate the quality and validity of special core analysis (SCA) data from Digital Rock Physics (DRP) has provided results that are comparable to laboratory measurements. The DRP technique applied in this study employs the Lattice Boltzmann Method (LBM) for computing relative permeability (Kr(Sw)) and capillary pressure (Pc(Sw)) curves from high resolution digital pore structures obtained from micro-CT image data. The DRP processes, results, and comparisons with laboratory measurements on carbonate rock samples from different Saudi Arabian carbonate reservoirs are presented. DRP conventional core analysis (DRP-CCA) computations include porosity, permeability, formation factor, and dynamic elastic properties. DRP special core analysis (DRP-SCA) computations include Kr(Sw) and Pc(Sw). The translation of DRP-CCA and DRP-SCA determinations from imaged 4 mm subsamples to the 38 mm core plug-scale was achieved by upscaling the data for the various flow units and porosity structures in each plug. The number of flow units within each plug varied between one and four. The process of assembling plug-scale DRP-CCA and DRP-SCA properties is discussed. DRP-SCA results and laboratory measurements from similar rock types in the same wells are comparable and show inherent process and inter-lab uncertainties. The dynamic range of the computed relative permeability curves is superior to the laboratory measurements. The comparisons further showed the benefit of the DRP images and computations in capturing the detailed pore structure and fabric of the rock, especially in the capillary pressure responses. The DRP-SCA computations accentuate spontaneous imbibition and the transition to forced imbibition, a region that traditional laboratory methods may not adequately capture. Computations for different wetting conditions provide relative permeability data that cover all possible rock-fluid wettability states. Similar attempts in traditional laboratory experiments would be long, tedious and expensive. This work shows that DRP can provide satisfactory and complementary data for reservoir studies. The images are readily available and can be used for sensitivity studies. The workflow allows users to conduct their own validation tests, just as we have done, to determine the applicability of the method. Introduction In this work we consider the computation of porosity, conductivity, (relative) permeability and capillary pressure. These rock properties are of interest to petroleum engineers for characterizing a reservoir and measure the ability of the rock to transport fluids as well as the fluid pressure and saturation behavior exhibited through various hydraulic processes. These properties can be computed based on the pore space representation from CT or FIB-SEM based acquisition, physical models and their numerical implementation. Since rocks normally exhibit a strong multi-scale behavior, it is necessary to scan and compute properties on different scales. Scales can be differentiated by the resolution of the scans, but it is more useful to differentiate them conceptually. For example, there is a scale where the pore space is not directly visible at a certain resolution, but it is possible to identify different material regions that can be described by averaged properties. Physical processes can be described by equations like Darcy flow. We will call that scale the Darcy scale. On the other hand, there is the pore scale where the pore space is visible and the physical processes are described directly by pore scale physics. There can also be a mixture of both scales at a certain scan resolution. This includes large vugs embedded in one or several Darcy regions.

Abstract As a rock-fluid interaction property, wettability is well recognized to influence the flow in multi-phase systems such as hydrocarbon reservoirs. In the laboratory, wettabilty measurements are made according to certain standard procedures and the results are expressed as indices for comparative purposes. The two most commonly used wettability indices are the USBM index, related to areas under capillary pressure curves, and the Amott-Harvey wettability index related to imbibition characteristics. If such measurements are not available, relative permeability curve characteristics may be used to quantify wettability. As is the case with most special core measurements, wettability tests are expensive and time consuming, with the consequence that the number of plugs subjected to wettability testing is usually limited, often resulting in a poor definition of reservoir wettability characteristics. One objective of the study presented is to introduce a mathematical expression, which may be used to gauge relative wettability, as an alternative to the above-mentioned indices. The model has been validated using data from Australian hydrocarbon basins. A genetic algorithm approach was utilised to tuning parameters in the wettability model presented. The model compares favourably with laboratory measurements and may be used to predict USBM indices if experimental values are not available. As such, the formulation presented may also be used in wettability classification. One of the relative permeability characteristics used to gauge wettability is the ratio of relative permeability end points. A second objective in the presented research is to predict this ratio, useful for the prediction of relative permeability characteristics. In considering possible analytical forms, the final derived formulae are extensions of the Carman-Kozeny equation. Introduction Reservoir wettability characterisation requires the knowledge of three types of data: rock related pore structure properties, fluid properties and rock-fluid interaction properties. The knowledge of the mineralogy is also helpful in characterising wettability. On the other hand, failure to properly characterise wettability may result in incorrect validation of special rock properties, such as relative permeability, leading to wrong recovery factors for a particular reservoir situation. Wettability may be viewed in different ways. Fundamentally, from thermodynamics, a system may be considered in terms of an equilibrium state where wetting of a surface by a liquid can be correlated to the variation in the Gibbs free energy (Berg, 1993). The balance between cohesive forces within the liquid (tend to pull up fluid drops) and adhesive forces between liquid and solid (allow fluid to spread) are a measure of wettability (Embid, 1997). Quoting from the literature: "Wettability is defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids." (Ahmed, 2001). Honarpour, et al. (1986) stated the following, "a term used to describe the relative attraction of one fluid for a solid in the presence of other immiscible fluids".

Abstract Modification of injection water salinity to improve oil recovery is not a new idea and the process has been investigated as far back as the 70's prior to the use of other chemical processes to improve oil recovery. In practice in planning water flooding project oil companies focused only on the compatibility of injection water and formation water issue to eliminate any possibility of formation damage. Many investigators recently had focused their research on the role of water salinity alteration to improve oil recovery. A number of possible mechanisms concerning alteration of water flooding salinity have been proposed in the literature. This project describes an experimental investigation of contact angle changes as function of time, and water flood performance using limestone and sand stone rocks for various injection brines. Carbonate rocks, sandstone rocks obtrained from a Libyan oil reservoir, high salinity water, sea water, low salinity water, and water contains different sulfate concentrations were employed in this study. The results of this research will shed more light on the mechanism of modified salinity flooding (MSFTM) and will help operating companies to better plan water flooding process. Introduction Water flooding has been used for many years to improve recovery from oil reservoirs. In the past, no attention has been given to the effect of the water composition and/or concentration on the possibility of increased oil recovery by alteration of salinity type and concentration. Historically the engineering design of water flooding focused only on avoiding formation damage by making sure no interaction between injected brine and indigenous brine. Morrow et al. (1996) concluded that alteration of brine composition of injected water can result in optimization of oil recovery. Tang and Morrow 1999; and McGuire et al. 2005, investigated further the effect of salinity on oil recovery and they have proved that decreasing brine salinity can improve oil recovery. Jerauld et al. 2008 indicated that more than 20 core floods using low salinity of sandstone reservoirs at reservoir conditions and at secondary and tertiary modes has been reported in the literature. Results of experimental work demonstrated an improvement of recovery efficiency due to low salinity by 5 to 38% and that manifested by reduction of residual oil saturation by 3 to 17% pore volume. Nasralla et al. 2011, indicated that injection of deionized water in the secondary mode resulted in a significant improvement in oil recovery compared to seawater. Different hypothesis have been introduced to explain the improvement in oil recovery by low salinity water injection. These include interfacial tension reduction, wettability alteration, change in pH (increase) resulting in in-situ saponification, emulsion formation, and clay migration.

Abstract Carbonate reservoirs are highly heterogeneous and often show oil-wet or mixed-wet characteristics. Both geological heterogeneity and wettability have strong impact on capillary pressure (Pc) and relative permeability (Kr) behaviour, which is controlled by the pore size distribution, interfacial tension and interactions between rock and fluids as well as the saturation history. Capillary pressure data are essential input in both static and dynamic modelling of heterogeneous carbonate reservoirs. Drainage Pc is generally used for initialising reservoir static models while imbibition Pc is used to model secondary and tertiary recovery processes. The objective of this paper is to present an improved reservoir characterisation and modelling procedure for predicting waterflood performance of a Cretaceous carbonate reservoir in the Middle East. We focus on the characterisation of multi-phase fluid flow properties, in particular the capillary pressure characteristics in both drainage and imbibition, and their assignments in reservoir simulation models. We show that for modelling initial saturation distribution in the reservoir, assigning saturation functions based on permeability or porosity classes alone is not adequate. Moreover the petrophysical correlations often used for clastic reservoirs (e.g., Leverett J-function) may not be applicable to carbonate reservoirs without careful pore-type examination and core analysis/calibration. A novel procedure is described to derive imbibition capillary pressure curves from the primary drainage Pc curves taking into account of wettability and fluid trapping. The results lead to an improved understanding of capillary pressure characteristics in carbonate reservoirs, in particular, the contact angle distributions and hysteresis behaviour in both drainage and imbibition. This paper also presents a mathematical model for implementing both drainage and imbibition capillary pressure functions in dynamic reservoir simulation. This model takes into account the complex pore size distribution and wettability characteristics in carbonates as observed in experimental special core analysis (SCAL) measurements. Furthermore, how to assign imbibition Pc for the different porosity and permeability classes will be examined and its impact on modelling waterflooding performance and remaining oil saturation distributions assessed. Introduction The complexity of carbonate reservoirs and the importance of a consistent approach in defining rock types have been a subject of several recent papers (Marzouk et al. 2000; Ramakrishnam et. al. 2000; Leal et. al. 2001; Porrai and Campos 2001; Giot et. al 2000; Silva et. al. 2002; Hamon 2002; Masalmeh and Jing 2004). Current practices in general are either based on petrophysical properties (i.e., porosity, permeability and drainage Pc curves) or geological description (facies and depositional environment) or a combination of both. The underlying assumption is that static rock characterisation and the resultant rock-typing scheme remain valid when assigning saturation functions (Pc & Kr) in dynamic reservoir modelling. In this paper, we will incorporate conventional core analysis (porosity, permeability), thin section and SEM analysis, mercury-air capillary pressure (Pc)/ NMR with special core analysis data, in particular, the imbibition Pc and residual oil saturation. Several experimental techniques are available to measure capillary pressure (Pc) curves, both in drainage and imbibition cycles. Mercury injection is frequently used for measuring drainage Pc curves as the technique is relatively cheap, fast and requires relatively straightforward data interpretation. The measured data, however, need to be converted to in situ reservoir conditions by taking into account the differences in interfacial tension and contact angle between the rock/fluid systems used in the laboratory and that found in reservoir. The porous-plate equilibrium method is a reliable and accurate technique for measuring Pc in drainage and imbibition under representative reservoir conditions of fluids, pressure and temperature. The main drawback of this technique is the lengthy time required to reach capillary equilibrium, which renders the technique impractical for certain field applications especially for tight and heterogeneous carbonates. The multi-speed centrifuge method can be used for both drainage and imbibition Pc measurements using representative reservoir fluids. Compared with the porous-plate equilibrium technique, the centrifuge method is relatively fast, which is a clear advantage for studying tight carbonates. However, the design of the centrifuge experiment and the interpretation of the data are not straightforward and numerical simulation of centrifuge experiments is generally required to derive capillary pressure data (Maas and Schulte 1997).