Coreflood Data Research Articles

Exact Solutions and Upscaling for 1D Two‐Phase Flow in Heterogeneous Porous Media

AbstractUpscaling of 1D two‐phase flows in heterogeneous porous media is important in interpretation of laboratory coreflood data, streamline quasi 3D modeling, and numerical reservoir simulation. In 1D heterogeneous media with properties varying along the flow direction, phase permeabilities are coordinate‐dependent. This yields the Buckley‐Leverett equation with coordinate‐dependent fractional flow f = f(s, x), which reflects the heterogeneity. So, an x‐dependency is considered to reflect microscale heterogeneity and averaging over x—upscaling. This work aims to average or upscale the heterogeneous system to obtain the homogenized media with such fractional flow function F(S) that provides the same water‐cut history at the reservoir outlet, x = 1. Thus, F(S) is an equivalent property of the medium. So far, the exact upscaling for 1D micro heterogeneous systems has not been derived. With the x‐dependency of fractional flow, the Riemann invariant is flux f, which yields exact integration of 1D flow problems. The novel exact solutions are derived for flows with continuous saturation profile, transition of shock into continuous wave, transition of continuous wave into shock, and transport in heterogeneous piecewise‐uniform rocks. The exact procedure of upscaling from f = f(s, x) to F(S) is as follows: the inverse function to the upscaled F(S) is equal to the averaged saturation over x of the inverse microscale function s = f −1(f, x). It was found that the Welge's method as applied to heterogeneous cores provides the upscaled F(S). For characteristic finite‐difference scheme, the fluxes for microscale and upscaled‐numerical‐cell systems, coincide in all grid nodes.

Stochastic model for migration and breakage of detrital and authigenic fines

Mobilisation of attached particles during flow in rocks occurs in geo-energy processes. Particle mobilisation, their migration through rocks and pore plugging yield significant decline in permeability and well injectivity and productivity. While much is currently known about the underlying mechanisms governing the detachment of detrital particles against attracting electrostatic forces, a critical gap exists in the theoretical understanding of detachment by breakage of widely spread authigenic particles, which naturally grow on rock grains during geological times. Previous works derived micro-scale mechanical equilibrium equations for both detrital and authigenic particles, and the upscaling procedure from particle to pore and core scales for detrital fines. In this paper, for the first time we derive a stochastic model for migration and breakage of authigenic fines and authigenic–detrital mixtures. This allows for core-scale transport modelling based on the particle-scale torque balance. We introduce a novel framework for predictive stochastic detachment modelling by particle–rock bond breakage that integrates the beam theory of elastic particle deformation, strength failure criteria and viscous flow around the attached particle. The analytical expressions for stress maxima and stress diagrams for a single particle allow determining the critical failure stresses, breakage points of the beam and breakage flow velocity. The mathematical model describing lab coreflood includes the maximum retention function for both authigenic and detrital fines. The matching laboratory coreflood data under increasing velocity at micro- and core-scales achieved high matching of the experimental data by the model. High matching validates the upscaling and downscaling procedures derived.

Deep bed filtration and formation damage by particles with distributed properties

Current models for deep bed filtration describe particles with uniform properties. Yet, the sizes, densities, and mineral composition of particles vary significantly in the same injection well. The aim of this work is to provide an effective mathematical model for water injection of particles with distributed properties and formation damage prediction. We average the set of traditional population balance equations for single-property particles and obtain one upscaled equation. The upscaled equation for particle retention rate contains a non-linear function of suspended concentration, which we call the 'suspension function'. We derive analytical solutions for the upscaled equation for linear (coreflood) and radial (well injectivity) flows. Then we treat lab coreflood data to determine the model suspension function and provide a model for well injectivity prediction. The retention profile for the flow of uniform particles has an exponential form. Frequently reported in the literature, hyper-exponential forms have been hypothetically explained by multiple particle properties. The inverse solution allows revealing the individual filtration coefficients for binary mixtures from total breakthrough concentrations during coreflood. Treatment of the data from lab experiments reveals individual filtration coefficients that belong to common intervals. For the first time, deep bed filtration of particles with distributed properties is upscaled and presented using a single equation that reflects the particle property distribution. This equation provides an effective mathematical model for tuning lab coreflood data, determines the model function, and uses it for injectivity decline prediction.

Rock fines breakage by flow-induced stresses against drag: geo-energy applications

The paper presents a strength-failure mechanism for colloidal detachment by breakage and permeability decline in reservoir rocks. The current theory for permeability decline due to colloidal detachment, including microscale mobilisation mechanisms, mathematical and laboratory modelling, and upscaling to natural reservoirs, is developed only for detrital particles with detachment that occurs against electrostatic attraction. We establish a theory for detachment of widely spread authigenic particles due to breakage of the particle-rock bonds, by integrating beam theory of particle deformation, failure criteria, and creeping flow. Explicit expressions for stress maxima in the beam yield a graphical technique to determine the failure regime. The core-scale model for fines detachment by breakage has a form of maximum retention concentration of the fines, expressing rock capacity to produce breakable fines. This closes the governing system for authigenic fines transport in rocks. Matching of the lab coreflood data by the analytical model for 1D flow exhibits two-population particle behaviour, attributed to simultaneous detachment and migration of authigenic and detrital fines. High agreement between the laboratory and modelling data for 16 corefloods validates the theory. The work is concluded by geo-energy applications to (i) clay breakage in geological faults, (ii) typical reservoir conditions for kaolinite breakage, (iii) well productivity damage due to authigenic fines migration, and (iv) feasibility of fines breakage in various geo-energy extraction technologies.

The Effect of Multiple Cycles of Surfactant-Alternating-Gas Process on Foam Transient Flow and Propagation in a Homogeneous Sandstone

Summary Years of laboratory studies and field tests show that there is still uncertainty about the ability of foam to propagate deep into a reservoir. Many factors have been identified as potential causes of nonpropagation, the most concerning being the lack of sufficient pressure gradient required to propagate foam at locations far from the point of injection. Most researchers that investigated foam propagation did so by coinjecting surfactant and gas. Coinjection offers limited information about transient foam processes due to limitations in the experimental methods needed to measure foam dynamics during transient flow. Foam injection by surfactant-alternating-gas (SAG) has proven to be more effective and common in field application. Repeated drainage and imbibition cycle offer a more favorable condition for the quick generation of foam. Foam can also be propagated at a lower pressure gradient in SAG mode. The objective of this study is to experimentally investigate how transient foam dynamics (trapping, mobilization, and bubble texture) change with multiple cycles of SAG and also with distance from the point of injection. A pair of X-ray source and receiver, differential pressure transducers, and electrical resistance sensors were placed along a 27-cm long, homogeneous, and high-permeability (KL = 70 md) Berea sandstone core. Foam was then generated in situ by SAG injection and allowed to propagate through the core sample under a capillary displacement by brine (brine injection rate = 0.5 cm3/min, Nca = 3×10-7). By use of a novel analytical method on coreflood data obtained from axial pressure and saturation sensors, we obtained trapped foam saturation, in-situ foam flow rates, apparent viscosities, and inferred qualitative foam texture at different core sections. We then observed the following: (i) Maximum trapped foam is uniform across the core sections, with saturation ranging from 47% to 52%. At the vicinity of foam injection, foam apparent viscosity is dominantly caused by gas trapping. At locations farther away, foam apparent viscosity is dominated by both gas trapping and refinement of foam texture. (ii) Cyclic injection of foam further enhances the refinement of foam texture. (iii) Textural refinement increases foam apparent viscosity as it propagates away from the point of injection. (iv) As the foam strength increases, the average gas flow rate in the core sample decreases from 0.5 cm3/min to 0.06 cm3/min. (v) There is no stagnation of foam as remobilization of trapped gas occurs during each cycle at an average flow rate of 0.002 cm3/min.

Geochemical Analysis of Hardness on the Adsorption of Surfactants in Carbonates Under Severe Thermodynamic Conditions: Surface Complexation Modeling Approach

Abstract Several core-flooding-based experimental studies demonstrated the effect of calcium and magnesium ions and it is found that these hard ions have detrimental effects on oil recovery during chemical-enhanced oil recovery operations. However, studies regarding the coupled effect of hard ions and surfactant adsorption are very limited. Thus, this study aims to present a novel approach that can capture mineral-brine, brine-oil, and brine-surfactant interactions in the presence of hard ions (Ca2+ and Mg2+). Also, we introduced four oil-surfactant-based surface complexation geochemical reactions (SCGR) in the presence of hard ions for the first time to analyze the oil-surfactant interactions. The developed thermodynamic-based geochemical model is compared and validated with recent core-flooding data. Our results illustrate that the use of oil-surfactant SCGR is important and should be captured for detailed surfactant adsorption. Thus, we observed that in the presence of hard ions, surfactant adsorption increases with the increase in temperature, which is due to the surge in kinetic energy. We also observed that a reduction in hardness reduces the adsorption of surfactants. Additionally, increasing surfactant concentration led to a minor increase in the adsorption of surfactant with a significant increase in its concentration in the discharge/effluent. Therefore, the hard ions (Ca2+ and Mg2+) concentration has a substantial negative effect, as they reduce the solubility of surfactant and increase its adsorption. Furthermore, the lowest level of surfactant adsorption was accomplished by injecting ten times diluted water (<0.070 mg/g).

Effects of salinity alternation on relative permeability and capillary pressure as determined from steady-state-transient test

This paper aims the development of a new laboratory method for the simultaneous determination of phase relative permeability (Kr) and capillary pressure (Pc) for low salinity (LS) waterflooding. The proposed method is based on the so-called steady-state-transient (SSTT) method that uses steady-state and transient coreflood data, which allows calculating Kr and Pc from the same coreflood. A novel mathematical modelling is developed to determine Kr and Pc for two-phase multicomponent transports, where these parameters also depend on component concentrations, i.e. kr(s,c) and pc(s,c).Two sister cores from the same outcrop are used for the SSTT and wettability measurement experiments. The SSTT is performed using a sequence of HS injection → core re-initialization → LS injection to enable comparison of Kr and Pc curves for the same initial conditions. The modelling resultsusing a well-posed inverse algorithm - indicate a significant decrease in relative permeability for water, an insignificant increase in relative permeability for oil, a slight reduction in residual oil saturation, and a negligible downward shift in the Pc curve after LS water injection. This is explained by the formation damage caused by the mobilization of fine particles and the consequent pore-scale flow diversion due to pore plugging.

Permeability Evolution of Porous Sandstone in the Initial Period of Oil Production: Comparison of Well Test and Coreflooding Data

Permeability prediction in hydrocarbon production is an important task. The decrease in permeability due to depletion leads to an increase in the time of oil or gas production. Permeability models usually are obtained by various methods, including coreflooding and the field testing of wells. The results of previous studies have shown that permeability has a power-law or exponential dependence on effective pressure; however, the difficulty in predicting permeability is associated with hysteresis, the causes of which remain not fully understood. To model permeability, as well as explain the causes of hysteresis, some authors have used mechanical reservoir models. Studies have shown that these models cannot be applied with small fluctuations in effective pressures in the initial period of hydrocarbon production. In this work, based on the analysis of well test data, we came to the conclusion that in the initial period of production under constant thermobaric conditions, the permeability of a slightly clayey terrigenous reservoir depends on the amount of fluid produced. A model has been obtained that describes the change in permeability in the initial period of oil production. Core samples were flooded to confirm the model. Coreflooding showed high convergence of the model obtained from well test data. With computed tomography (CT) and scanning electron microscope (SEM), the properties and structure of the core were studied, and it was found that the main reason for the decrease in the permeability of slightly clayey rocks in the initial period of production is the migration of natural colloids.

Newly engineered alumina quantum dot-based nanofluid in enhanced oil recovery at reservoir conditions

In this work, a newly engineered alumina quantum dot-based nanofluid (α-AQDs; D ~ 4 nm; amorphous solid) and one commercial alumina nanoparticle-based nanofluid (γ-ANPs; D ~ 20 nm; crystalline type) with the capability of strong colloidal dispersion at reservoir conditions, such as, high salinity, divalent ions (Ca2+) and high temperature was compared. The main goal of this research was to study the crude oil displacement mechanisms of alumina suspensions as a function of variety in size and particle morphology in aged carbonate rocks. The strong interaction potential between the particles was achieved by the citric acid and a special composition of a carboxylate-sulfonate-based polyelectrolyte polymer as an effective dispersant compound on the surface, leading to a negative particle charges and an additional steric and electrostatic repulsion. Wettability alteration upon exposure to fluids using the contact angle and the Amott cell were performed on saturated carbonate plug samples and rock slices. While, dynamic core displacements were conducted to test the water/nanofluid/oil flow and nanoparticle retention behavior thorough typical pore throats underground the reservoir conditions. The stability results revealed that PE-polymer was able to create a long-term colloidal fluid during 30 days. It was found that mass concentration of nanofluid increased with decreasing in particle size. The optimal amount of particles in aqueous solution was obtained 0.05 wt% for ANPs, increased up to 0.1 wt% for AQDs. Analysis of experiments showed that wettability alteration was the main mechanism during nanofluid injection. Laboratory core-flooding data proved that the enhanced oil recovery due to a less concentration state by ANPs was consistent with AQDs at higher concentrations. In addition, permeability-impairment-behavior study was discussed in terms of possible mineral scale deposition and alumina release on the rock surface. Results showed that a large extent of permeability damage caused by mineral scale (55–59%). Alumina quantum dot-based nanofluids were found a minimum impairment (2–4%) and a significant reduction of ~ 10% in permeability was observed for ANPs-based nanofluid.

Geochemical investigation of electrical conductivity and electrical double layer based wettability alteration during engineered water injection in carbonates

The injection of engineered water to increase the oil recovery from carbonates is increasingly becoming popular due to its reduced environmental impact and low cost of operation. However, the related variation in electric properties of rock and fluid with this technique is still ambiguous and needs thorough investigation. This study explores the variation in electrical conductivity, ion mobility, electrical double layer thickness, and the related oil recovery with the change in water composition from a geochemical perspective. In this study, we implemented an improved wettability alteration model based on the variation in electrical conductivity with a Matlab-IPhreeqc coupled simulator, to model the electrical conductivity, ion mobility, and electrical double layer (EDL) thickness. The variation in concentration of the ionic species obtained from the geochemical model is used to determine the electrical conductivity. This electrical conductivity-based wettability modification is dynamically simulated in the transport model. The model is validated with experimental coreflood data conducted on carbonates by simulating the electrical conductivity measurements reported in the literature. From the findings, it is evident that the formation temperature, sulfate concentration, and dilution of injected seawater has a noticeable effect on electrical conductivity during engineered water injection. It is important to mention that the EDL thickness is the main parameter affected by the change in electrical conductivity. In consequence, it is suggested to inject high-temperature water in carbonate reservoirs because it will increase ion mobility. This increase in ion mobility will enhance the EDL thickness and water film will become stabilized. Moreover, seawater dilution decreases electrical conductivity while spiking of sulfate concentration increases the activity of sulfate ions. However, the concentration of sulfate ions must be controlled as a wettability alteration agent, as it can cause the formation and precipitation of calcium sulfate. Furthermore, the variation in electrical conductivity and EDL thickness caused by the injection of seawater and diluted seawater increased the recovery of oil by approximately 16–21% in the selected case study.

Role of relative permeability hysteresis in modified salinity water flooding

Many laboratory and field scale trials have shown that modified salinity water flooding increases the mobility of oil and improves oil recovery. However, field scale simulation of the process guided by core flooding data leads to inaccurate prediction of oil recovery if the effect of the saturation history of the reservoir on relative permeability is ignored. Here, we address this problem by proposing three models illustrating the interplay among wettability alteration, hysteresis effect, and fluid flow transport in porous media. The models provide the variation of imbibition and secondary drainage saturation curves versus salinity caused by wettability alteration. Our simulations show that including hysteresis together with the wettability alteration process can better quantify the re-trapping of the oil that is mobilized due to wettability alteration of the reservoir. We further show that in the capillary transition zone, where water saturation varies from top to bottom of the reservoir, oil recovery continues for a long time, although the water cut starts early, in comparison with a reservoir with an initial uniform water saturation. Despite many experiments conducted for advanced waterflooding, our observations show that measuring the secondary drainage and imbibition saturation curves is essential and serves as a valuable input for the field scale simulation of modified salinity waterflooding of water flooded reservoirs with highly non-uniform saturation history.

Investigation of the enhanced oil recovery potential of sodium cocoyl alaninate: an eco-friendly surfactant

Amino acid-based surfactants (AASs) and other novel surfactants have recently gained attention to provide a favorable environmental image (“green”) in surfactant application. Yet their potential in enhancing oil recovery is not well investigated. Only a few works have been reported on their potential enhanced oil recovery (EOR) application with less satisfactory results. Here in, sodium cocoyl alaninate (SCA), an acylated amino acid with excellent properties that facilitate its application in other fields, is investigated for its EOR potential. Its effectiveness in lowering the interfacial tension and the emulsifying crude oil–brine mixture were studied. The ability to alter rock surface wettability and its adsorption behavior on the sand surface were studied as well. Then, its oil recovery potential was confirmed through a core displacement experiment. All studies were performed in comparison with conventionally deployed sodium dodecyl sulfate (SDS). The critical micelle concentrations for SCA (CMC = 0.23 wt%) and SDS (CMC = 0.21 wt%) were close, which serves as a good basis for comparing their EOR potential. SCA proved to be more effective in IFT reduction attaining a minimum IFT of 0.069 mN/m (i.e., ~ 98.8% IFT reduction) compared to 0.222 mN/m of SDS (i.e., ~ 96.2% IFT reduction) at the same concentration. Salinity showed a synergistic effect on the interfacial properties of both SCA and SDS but had a more significant impact on SDS interfacial properties than SCA due to low salt tolerance of SDS. The low IFT attained by SCA yielded enhanced emulsion formation and stable emulsion both at 25 °C and 80 °C for a period of one week. SCA also altered quartz surface wettability better via reduction of contact angle by 94.55% compared to SDS with contact angle reduction of 87.51%. The adsorption data were analyzed with the aid of various adsorption isotherm models. The adsorption behavior of SCA and SDS could be best described by the Langmuir model. This means a monomolecular surfactant layer exists at the aqueous–rock interface. SDS also exhibited more severe adsorption on the sand surface with the maximum adsorption density of 15.94 mg/g compared to SCA with the maximum adsorption density of 13.64 mg/g. The core flood data also confirmed that SCA has a better oil recovery potential than SDS with an additional oil recovery of 29.53% compared to 23.83% of SDS. This additional oil recovery was very satisfactory compared to the performance of other AAS that have been studied. This study therefore proves that SCA and other AAS could be outstanding alternatives to conventional EOR surfactants owing to their excellent EOR potential in addition to their environmental benign nature.

Insights into wettability alteration during low-salinity water flooding by capacitance-resistance model

The capacitance-resistance model (CRM) has been widely implemented to model and optimise waterflooding and enhanced oil recovery (EOR) techniques. However, there is a gap in the application of CRM to analyse physical phenomena in porous media as well as the performance of EOR methods, such as low-salinity water (LSW) flooding. The main purposes of this study were to investigate how changes in time constant, as a CRM parameter, can represent physical phenomena in porous media such as wettability alteration. Moreover, to show CRM is a reliable tool to use for interpretation of LSW process as an EOR method. The results of different experimental/modelling studies in this research showed that in CRM model time constant increases when the wettability alters to a water wetness state, whereby the smallest time constant value is observed for the oil wet medium and the highest is observed for the water wet medium. The cases with a gradual alteration in wettability show an increasing trend with the dilution of the injection water. The core flooding data confirms the observed results of the simulation approach. The increment in time constant values indicates the resistance against displacing fluid, which is due to the wettability alteration of the porous medium, resulting in additional oil production. The observations made during this research illustrate that the time constant parameter can be a powerful tool for comparing different EOR techniques, since it is a good indication of the speed of impact of a particular injection fluid on production.

Foam Flow in Different Pore Systems—Part 2: The Roles of Pore Attributes on the Limiting Capillary Pressure, Trapping Coefficient, and Relative Permeability of Foamed Gas

Summary The limiting capillary pressure of foam (Pc*) and foam trapping in porous media are pore-scale foam properties that affect foam transport in porous media. They are strongly influenced by the characteristics of rock pores and throats. Because of experimental limitations, these foam properties are difficult to measure at core scale. As a result, our understanding of their relationship with different pore characteristics is limited. In this paper, novel coreflood and graphical analysis techniques were used to measure Pc* and the foam-trapping coefficient (FTC) at core scale. FTC is a new parameter synonymous to Land’s (1968) trapping coefficient, which describes foam-trapping behavior across an entire range of saturation as opposed to a single endpoint trapped saturation. The scalability of these two foam properties with permeability and other pore characteristics [average pore size (PS), average throat size (TS), average aspect ratio (AR), coordination number (CN), surface area/volume ratio, and reservoir-quality index (RQI)] were also investigated. Pore characteristics of 12 different rock samples were measured from 3D pore-network models generated from high-resolution X-ray computed-microtomography images. The heterogeneity of the rock samples were quantified by the Dykstra-Parsons index (Dysktra and Parsons 1950), while the RQI and J-function methods were used to classify them according to their storage and flow properties. Each of the measured pore characteristics and their combination [combined pore character (CPC)] were then correlated with Pc* and FTC to understand their respective roles. Furthermore, the data points obtained from the graphical analysis of the coreflood data provided the required input data for a mechanistic foam model for relative permeability of foamed gas (Kovscek and Radke 1994). The estimated relative permeability of foamed gas was then used to study foam mobility in the different pore geometries. The overall results showed the following: P c * has strong negative correlations with all pore characteristics except AR, which has a weak positive correlation. P c * has the strongest correlation with RQI, CPC, and permeability; a moderate correlation with CN and TS; and a very weak correlation with PS. Foam trapping has positive correlations with all pore characteristics except AR, which has a negative correlation. Low AR appears to be responsible for significant trapping of foam in high-permeability rocks. Low AR favors more foam trapping, while high AR favors trapping of oil and gas during water imbibition in water-wet rocks. Foam trapping appears to have the dominant control on foam mobility.

Foam Flow in Different Pore Systems—Part 1: The Roles of Pore Attributes and Their Variation on Trapping and Apparent Viscosity of Foam

Summary Lateral propagation of foam in heterogeneous reservoirs, where pore geometries vary laterally, depends on the roles of pore geometries on the foam properties. In this paper, the pore attributes of 12 different rock samples were characterized in terms of porosity, permeability, pore shape, pore size, throat size, aspect ratio, coordination number, and log mean of surface relaxation times (T2LM). These were measured from gas porosimeter and permeameter, X-ray microcomputed tomography (CT)-based pore-network models, thin-section photomicrographs, and nuclear magnetic resonance (NMR) surface relaxometry. The samples have a wide range of porosity: 12 to 29%; permeability: 1 to 5,000 md; average pore size: 3.7 to 9 µm; average throat size: 2.4 to 8 µm; average aspect ratio: 1 to 1.7; average coordination number: 2.6 to 5.2; and T2LM: 9.4 to 740 ms. Nitrogen foam flow experiments (without oil) were then conducted on each rock sample using a specialized coreflood apparatus. A graphical analysis of the coreflood data was used to estimate the total saturation of trapped foam (10 to 66%), flowing foam (3 to 14%), and apparent viscosity of foam (3.2 to 73 cp). Trapped foam saturation and apparent viscosity values were then correlated with each of the measured pore attributes. The results revealed that all pore attributes, except aspect ratio, have positive correlations with foam trapping and apparent viscosity. The best correlation with trapped foam saturation was obtained when the most influential pore attributes (pore size, throat size, aspect ratio, and coordination number) were combined into a single mathematical function. Foam apparent viscosity also appears to be mostly influenced by trapped foam saturation, permeability, and coordination number of pore systems. Trapping is also likely enhanced by the presence of fenestral or channel pores. Furthermore, the shape and angularity of pores seem to facilitate snap-off and trapping of foam, because rock samples with angular pores trapped the highest foam saturation compared with other samples with rounded and subrounded pores. It was also shown that the correlation between trapped foam saturation (and foam apparent viscosity) and the absolute permeability of porous media may reverse at some high-permeability values (greater than several darcies), when one or both of the following conditions exist: (1) The aspect ratio of a lower-permeability porous medium is lower than that of a higher-permeability porous medium, and (2) the coordination number of a lower-permeability porous medium is higher than that of a higher-permeability porous medium. Finally, T2LM showed a good correlation with foam trapping, making NMR logging a prospective tool for pre-evaluating foam performance in targeted reservoir sections.

Capillary fluctuations and energy dynamics for flow in porous media

Capillary energy barriers have important consequences for immiscible fluid flow in porous media. We derive a time-and-space averaging theory to account for the non-equilibrium behavior and understand the role of athermal capillary fluctuations in the context of their relationship to larger scale phenomenological equations. The formulation resolves several key challenges associated with two-fluid flow in porous media: (1) geometric and thermodynamic quantities are constructed as smooth functions of time based on time-and-space averages; (2) averaged thermodynamics are developed for films; (3) multi-scale fluctuation terms are identified, which account for transient behaviors of interfaces and films that occur due to pore-scale events; (4) geometric constraints are derived and imposed on the averaged thermodynamics; (5) a new constitutive model is proposed for capillary pressure dynamics that includes contributions from films; and (6) a time-and-space criterion for representative elementary volume is established based on capillary fluctuations. Capillary fluctuations are assessed quantitatively based on pore-scale simulations and experimental core-flooding data.

Laboratory Formation Damage Test Data Upscaled With Computational Fluid Dynamics

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 199268, “Upscaling Laboratory Formation Damage Laboratory Test Data,” by Michael Byrne, SPE, Lesmana Djayapertapa, and Ken Watson, SPE, Lloyd’s Register, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19-21 February. The paper has not been peer reviewed. Through several case histories, the complete paper demonstrates applications of computational fluid dynamics (CFD) modeling to upscaling of laboratory-measured formation damage and reveals implications for well and completion design. The value of laboratory testing is quantified and interesting challenges to conventional wisdom are highlighted. Introduction Laboratory formation damage testing is often used to help select optimal drilling and completion fluids. Test procedures such as sand retention and return permeability represent an attempt to simulate near-wellbore conditions during well construction and production. To determine what degree of permeability impairment is allowable, further interpretation that cannot be provided using classical nodal analysis or reservoir simulation methods is required. The complete paper describes the evolution of, and potential for, more-comprehensive upscaling and outlines the importance of consideration of full well geometry when designing and interpreting coreflood tests for formation damage. CFD simulations provide a means to upscale suitable laboratory test data to predict effect on well performance. Methods CFD simulations use a relatively simple, steady-state, static damage model that takes endpoint data from laboratory core tests and translates the data into parameters that are used for input into well geometry. Although this method has its merits and is a considerable advance on previous, more-simplistic upscaling attempts, it does not necessarily present the full picture of damage evolution in the near-wellbore. A transient model of damage with data again derived from laboratory coreflood data could reveal more about well cleanup and progressive damage removal. Steady-State Modeling. No API recommended practice for return permeability testing exists. Laboratories have their own procedures that comply broadly with recommended procedures developed some time ago. Operators and consultants, too, have their own procedures, which they often ask laboratories to follow. Although no recommended practice exists, evaluation of drilling and completion fluids usually involves measurement of a base permeability and remeasurement of a return permeability—or several—after application of the test fluid or fluids. In many cases, the laboratory removes the external mud cake or trims a slice of the end of the plug to measure return permeability without mud cake (Fig. 1).

Can low salinity water injection be an efficient option for the Recôncavo Basin? An experimental and simulation case study

Low salinity water injection (LSWI) has been studied by several researchers as an enhanced oil recovery (EOR) method in laboratory experiments, numerical simulations, and field applications. However, its effects on oil recovery remain uncertain due to the complexity of the interactions among crude oil, brine, and the rock surface, for both sandstone and carbonate reservoirs, particularly when they contain a diversity of clay minerals. This paper investigates LSWI performance and mechanisms in sandstone rock, brine, and light crude oil with low polar compounds from a reservoir in Brazil. Core flooding experiments and reservoir simulations were carried out to understand the influence of key parameters on oil recovery. Zeta potential measurements were performed to investigate the influence of the formation water and NaCl and CaCl2 brine solutions on rock and oil surface charges. Increased oil recovery, Ca++ desorption from the rock surface, and a substantial pH increase in the effluent were noticed during LSWI. Based on the zeta potential measurement, a thicker water film was also formed on the rock and oil surface with brine dilution. A recovery factor of 64% was reached by testing LSWI from the beginning of the waterflooding (secondary mode) and this was the highest recovery of all the scenarios evaluated. Ten parameters were successfully history matched to core flood data, and optimization and sensitivity analysis showed that the concentration of Na+ and Ca++, and the water injection rate were the most important parameters in the LSWI process. Overall, this study sheds light on the LSWI mechanisms for the Brazilian oil field investigated and provides useful operational parameters for designing and achieving better LSWI performance.

Enhancing surfactant desorption through low salinity water post-flush during Enhanced Oil Recovery

Low Salinity Water (LSW) incorporates in surfactant Enhanced Oil Recovery (EOR) as a pre-flush is a common practice aiming to reduce the formation salinity, which affects surfactant adsorption. However, in a field implementation, the adsorption of surfactant is unavoidable, so creating a scheme that detaches the trapped surfactant is equally essential. In this study, LSW was a candidate to enhance the desorption of surfactant. LSW solely formulated from NaCl (1 wt.%), Sodium Dodecylbenzene Sulfonate (SDBS) was chosen as the primary surfactant at its critical micelle concentration (CMC, 0.1 wt.%). It found that injecting LSW as post-flush achieved up to 71.7% of SDBS desorption that lower interfacial tension against oil (31.06° API) to 1.3 mN/m hence bring the total Recovery Factor (RF) to 56.1%. It was 4.9% higher than when LSW injecting as pre-flush and 5.2% greater than conventional surfactant flooding (without LSW). Chemical analysis unveiled salinity reduction induces Na+ ion adsorption substitution onto pore surface resulting in an increment in surfactant desorption. The study was further conducted in a numerical simulation upon history matched with core-flood data reported previously. By introducing LSW in post-flush after SDBS injection, up to 5.6% RF increased in comparison to other schemes. The proposed scheme resolved the problems of adsorbed surfactant after EOR, and further improve the economic viability of surfactant EOR.

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

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