Heterogeneous Carbonate Core Research Articles

Chemical enhanced oil recovery under Harsh conditions: Investigation of rock permeability and insights from NMR measurements

Injecting surfactant into a hydrocarbon reservoir stands out as a highly effective method for EOR due to its ability to reduce water/oil IFT and alter rock wettability in certain cases. However, the efficiency of this process is compromised in heterogeneous reservoirs, especially carbonates, characterized by significant permeability variations. This study presents findings from three core flooding experiments on heterogeneous carbonate core samples with different permeabilities. The experiments were conducted under representative reservoir conditions of 100 °C, pressures higher than 3000 psi, and seawater salinities and formation water of 57,745 ppm and 213,768 ppm, respectively. In each experiment, seawater was continuously injected followed by continuously injecting a 2500-ppm solution of in-house synthesized Gemini surfactant. Results revealed that the recovery factor was highest in low-permeability rocks and lowest in high-permeability rocks for both seawater and surfactant floods. Surfactant floods yielded additional recoveries of 31%, 23%, and 19% for low, medium, and high-permeability samples, respectively. Nuclear magnetic resonance (NMR) analysis on short analogous core plugs at different flooding stages confirmed these results. Effluent analysis on the produced aqueous phase indicated that dynamic retention was highest (0.467 mg/gm-rock) in the lowest permeability and lowest (0.146 mg/gm-rock) in the highest permeability rock. NMR analysis suggested that the surfactant's recovery performance and dynamic retention were influenced by the larger surface area of low-permeability rocks, facilitating increased contact with the surfactant. Utilizing NMR monitoring in this work enhances EOR insights through integrated studies and coreflooding experiments and establishes a novel framework for complex reservoir conditions.

Dissolution behaviour in carbonate reservoirs during WAG injection: A preliminary experimental study

In this study, a core flooding experiment using a water-alternating-gas (WAG) injection was conducted to evaluate its impact on the petrophysical properties of an initially oil-saturated heterogeneous carbonate core sample. Carbon dioxide (CO2) and synthetic formation brine were injected (0.5 pore volume CO2 alternating with 0.5 pore volume brine) alternately following establishment of waterflooding residual oil saturation under reservoir conditions. Gas porosity, gas permeability, NMR (nuclear magnetic resonance) T2 measurements, and X-ray CT scanning were conducted preand post-core flooding. The results show that CO2-WAG injection resulted in substantial additional oil recovery (~30 %) under the applied experimental conditions. The results also show an increase in the permeability of the tested sample from 1.5 to 16 mD, which could be attributed to mineral dissolution. X-ray CT imaging shows signs of excessive mineral dissolution and formation of wormhole structures. It is believed that dissolution within the tested core plug caused the WAG fluids to follow the newly wormhole (causing them to enlarge further), and consequently bypassing many parts of the sample. Therefore, despite a significant increase in oil recovery, a large amount of oil is still left behind.

The impact of wormhole generation in carbonate reservoirs on CO2-WAG oil recovery

In this paper, the impact of CO2-carbonate interactions on hydrocarbon recovery from three initially oil-saturated heterogeneous carbonate core samples (with low and mid permeabilities) were investigated. Alternate injection of carbon dioxide (CO2) and synthetic formation brine was conducted after water flooding. X-ray computed tomography scanning of the core samples before and after core flooding was performed at ambient conditions. Extent of carbonate dissolutions and rock matrix modifications were observed from the change in porosities, permeabilities, and wormhole formations. Generally, the CO2-WAG injection resulted in more than 30% extra oil recovery from the three cores after water flooding scenario. As expected, the total recovery factor of the core with lowest initial permeability and porosity was the smallest, however the core permeability increased from 1.45 mD (pre-flood) to 1987.9 mD (post-flood). Considerable amount of oil was left behind in the core with initially low permeability and porosity due to preferentially flow of WAG fluid through the wormholes, bypassing the trapped oil in the pore spaces at the uninvaded region of the rock. The study suggests that low oil recovery from core with low initial permeability and porosity is principally due to formation of wormhole because of rapid rate of rock dissolution and faster rate of CO2-carbonate reactions. Compared to the mid permeability cores, the low permeable core slows down the WAG fluid flow and give more time for CO2-carbonate rock interactions and reactions because of the tightness of the pore spaces. Thus, facilitated more exposure time and effective contact between the carbonate rock fabrics and the CO2-saturated brine.

A non-aqueous foam concept for improving hydrocarbon miscible flooding in low permeability oil formations

Enhanced oil recovery (EOR) from carbonate formations has been challenging due to reservoir heterogeneity, unfavorable wettability, and low permeability. Thus, the application of traditional water-based EOR methods such as micellar-polymer flood in these reservoirs has been limited. With the increasing availability of natural gas, we introduce a new foam EOR concept utilizing the raw mixture of natural gas liquids (MNGLs). This process involves the injection of a non-condensable gas (i.e., nitrogen or methane) and MNGLs with dissolved non-aqueous foam stabilizing additive to maximize oil recovery based on crude oil-MNGLs miscibility and sweep efficiency due to foam improved mobility control.The objective of this study is to evaluate the performance of this unconventional foam process to improve miscible displacement in low permeability rocks. Coreflood experiments were conducted using heterogeneous carbonate cores with sub-10-mD permeability. It was found that non-aqueous foam-assisted miscible displacement can achieve promising ultimate recovery factors while significantly reducing the amount of injected MNGLs. The overall recovery could be increased up to 18% with a foaming additive dissolved in the MNGLs slug. The measured pressure drops along the core indicate that in-situ generation of foam significantly delayed the injectant breakthrough and recovered the unswept oil much further away from the injection point.

Prediction of oil-water relative permeability in sandstone and carbonate reservoir rocks using the CSA-LSSVM algorithm

Relative permeability of multiphase flow through porous media plays a vital role in the petroleum industry, especially in enhanced oil recovery (EOR) processes. In this study, models were developed based on a combination of Least-Square Support Vector Machine and Couple Simulated Annealing (CSA-LSSVM) algorithm to predict oil-water relative permeability in sandstone and carbonate porous media. Comparing the model to thousands of experimental data resulted in overall squared correlation coefficients (R2) of 0.9866 and 0.9965, and minimum squared errors (MSEs) of 0.0014 and 0.000143 for Kro and Krw, respectively. In addition, Model predictions were found to agree excellently with experimental data. The results of CSA-LSSVM model were compared with some of the well-known mathematical equations including the Purcell, Burdine, Brooks and Corey, Corey, and some empirical correlations for predicting the oil-water relative permeability in a heterogeneous carbonate core sample. The models developed in this study outperform the mathematical equations and empirical correlations yielding an overall squared correlation coefficients of 0.9987 and 0.9994, and minimum squared errors of 0.0003 and 0.0049 for Kro and Krw, respectively. Finally, leverage value was introduced to analyze the whole dataset from which 19 points were diagnosed as possible outlier experimental data.

Monte Carlo Approach for Estimating Density and Atomic Number From Dual‐Energy Computed Tomography Images of Carbonate Rocks

AbstractWe develop a new Monte Carlo‐based inversion method for estimating electron density and effective atomic number from 3‐D dual‐energy computed tomography (CT) core scans. The method accounts for uncertainties in X‐ray attenuation coefficients resulting from the polychromatic nature of X‐ray beam sources of medical and industrial scanners, in addition to delivering uncertainty estimates of inversion products. Estimation of electron density and effective atomic number from CT core scans enables direct deterministic or statistical correlations with salient rock properties for improved petrophysical evaluation; this condition is specifically important in media such as vuggy carbonates where CT resolution better captures core heterogeneity that dominates fluid flow properties. Verification tests of the inversion method performed on a set of highly heterogeneous carbonate cores yield very good agreement with in situ borehole measurements of density and photoelectric factor.

Determination techniques of Archie’s parameters:a,mandnin heterogeneous reservoirs

The determination of water saturation in a heterogeneous reservoir is becoming more challenging, as Archie’s equation is only suitable for clean homogeneous formation and Archie’s parameters are highly dependent on the properties of the rock. This study focuses on the measurement of Archie’s parameters in carbonate and sandstone core samples around Malaysian heterogeneous carbonate and sandstone reservoirs. Three techniques for the determination of Archie’s parameters a, m and n will be implemented: the conventional technique, core Archie parameter estimation (CAPE) and the three-dimensional regression technique (3D). By using the results obtained by the three different techniques, water saturation graphs were produced to observe the symbolic difference of Archie’s parameter and its relevant impact on water saturation values. The difference in water saturation values can be primarily attributed to showing the uncertainty level of Archie’s parameters, mainly in carbonate and sandstone rock samples. It is obvious that the accuracy of Archie’s parameters has a profound impact on the calculated water saturation values in carbonate sandstone reservoirs due to regions of high stress reducing electrical conduction resulting from the raised electrical heterogeneity of the heterogeneous carbonate core samples. Due to the unrealistic assumptions involved in the conventional method, it is better to use either the CAPE or 3D method to accurately determine Archie’s parameters in heterogeneous as well as homogeneous reservoirs.

Non-Fickian Description of Tracer Transport Through Heterogeneous Porous Media

The porosity and the in situ concentration of tracer testing through different heterogeneous carbonate cores were performed using X-ray computed tomography. The results were interpreted using three approaches: the convection–diffusion equation, the arrival time moments and the stratified model. The results showed that (i) the Fickian approach led to a dispersion coefficient varying along each sample (ii) the statistical approach led to a power law of the variance of the arrival time as a function of the distance and (iii) the stratified model allowed quantification of the heterogeneity factor, which also appeared to be a power function of the distance. These data suggest that the temporal moments approach and the stratified model, but not the classical Fickian approach, are suitable for describing tracer transport through heterogeneous media at the core scale.

Unconditional sequential Gaussian simulation for 3-D flow in a heterogeneous core

Three-dimensional (3-D) porosity distribution realizations from unconditional sequential Gaussian simulations were input into a 3-D miscible displacement simulator to model miscible flow through a heterogeneous carbonate core containing a residual phase. The displacement simulations using unconditional sequential Gaussian simulation generated data as input were compared to the displacement simulations using the actual experimental data as input in order to evaluate the effectiveness of unconditional sequential Gaussian simulation for these applications. Previous X-ray computer tomography experiments provided the porosity and residual saturation distribution parameters. The experimental porosity data were fit to spherical, exponential, Gaussian and power semivariogram models. The power model provided the best fit followed by the exponential model. Both the power and the exponential models were used in the fluid displacement simulations. Both models predicted similar effluent profiles with relatively little spread between realizations. Breakthrough occurred late in all runs using the simulated input data, but otherwise the effluent profiles were in excellent agreement with the results using the experimental data. The spread between realizations, however, was not large enough to include all the points calculated using the experimental data. Differences between results using experimental data and sequential Gaussian simulation generated data were accentuated in numerical displacement simulations where a single miscible pulse was injected.

Distribution of Residual Oil in Heterogeneous Carbonate Cores Using X-Ray CT

Summary The use of X-ray computerized tomography (CT) for the measurement of residual saturations and porosity distributions in heterogeneous carbonate cores is illustrated. Semivariograms of porosity are calculated and used to determine correlatiort lengths on the laboratory scale. The relationship between residual saturation and porosity is presented for two different cores.

Relative Permeabilities From Centrifuge Data

Abstract The drainage of a wetting phase (say oil) by a non-wetting phase (say gas) may be simulated in the centrifuge by two liquids. Such experiments were conducted on a number of cores and they are discussed in a paper by Firoozabadi, et al.(1). In this paper we consider two of the cores with available capillary pressure data. Two forms of the relative permeability models are selected and the parameters of these models are obtained by history matching with a numerical simulator developed for this study that properly accounts for the capillary pressure and the boundary conditions in centrifuge experiments. It is shown that:recoveries can be matched with two — and maybe even more — very different sets of relative permeability curves;recoveries are sensitive to the parameters of each relative permeability model; andlate time predictions can be improved by using a linear relationship for the wetting phase relative permeability below some arbitrary value of the wetting phase saturation. It is concluded that both wetting and non-welling phase permeabilities can be estimated from a least-squares history match of the recovery data. However, for the oil-water system examined in this paper, the history match technique leads to a non-unique set of relative permeabilities. Introduction Relative permeability curves for a given rock sample may be measured from the steady-state or unsteady-state core displacement experiments. The steady-state(2) method requires simple calculations to derive relative permeabilities from experimental data. Either explicit or implicit approaches can be used to calculate relative permeabilities from the unsteady-state core flooding experiments. The Johnson, Bossler and Naumann(3) (JBN) or its modification(4) are explicit techniques. In the implicit method, relative permeability curves are adjusted so that the response simulated by a numerical model of the displacement process matches the measured quantities(5,6). The explicit JBN approach relates phase permeabilities and saturations at the effluent-end or some other point in the core. Relative permeabilities derived from the JBN method normally cover only a part of the saturation range over which both phases are mobile. The application of this method may yield anomalous relative permeability curve shapes for typical heterogeneous carbonate core samples and for strongly water-wet homogeneous cores(5,6). The JBN technique, however, seems to be valid for the conditions assumed in its development. A basic assumption of this method is that the capillary pressure and hence the capillary pressure end effects can be ignored. This is realized in practice by conducting experiments at sufficiently high flow rates. However, for many field scale calculations the flow rates are such that the inclusion of the capillary pressure is necessary. Also in heterogeneous cores, effective average relative permeabilities may be rate sensitive(7) and therefore the standard JBN method cannot be used. Archer and Wong(5) suggested that the use of a reservoir simulator to model laboratory tests can smooth the anomalous relative permeability curves obtained from the JBN method. They agreed that the smoothed curves reflect properties that are more consistent with the bulk behavior of the core sample than the results obtained from the standard JBN method.

An Improved Unsteady-State Procedure for Determining the Relative-Permeability Characteristics of Heterogeneous Porous Media (includes associated papers 8028 and 8777 )

Abstract With typical heterogeneous carbonate coresamples, large uncertainties of unknown magnitudecan occur in the relative permeabilities derived using different methods. This situation can beimproved by analyzing the recovery and pressureresponse to two-phase laboratory displacement tests by a nonlinear least-squares procedure. Thesuggested technique fits the finite-differencesolution of the Buckley-Leverett two-phase flowequations(which include capillary pressure) to theobserved recovery and pressure data. The procedureis used to determine relative-permeability curves characterized by two parameters and their standarderrors for heterogeneous cores from two Albertacarbonate reservoirs. Introduction Several recent investigations have recognizedpossible problems when obtaining reliable two-phasedisplacement data from heterogeneous carbonate core samples. Huppler stated that waterfloodresults on cores with significant heterogeneitiescan be sensitive to flooding rate, core length, andwettability, and that these effects should beconsidered before applying the laboratory results atfield flooding rates. Brandner and Slotboomsuggested that realistic displacement results maynot be obtainable when vertically flooding aheterogeneous core with a nonwetting phase becauseof the fluid's inability to maintain a properdistribution when the sample length is less than the height of capillary rise. Ehrlich noted thatstandard relative-permeability measurement methodsusing core plugs cannot be applied when the media are heterogeneous. Archer and Wong reported that application of theconventional Johnson- Bossler - Neumann (JBN)methods for determining relative permeabilities froma waterflood test could give erroneous results forheterogeneous carbonate as well as for relativelyhomogeneous porous media having a mixed wettability (see Refs. 1, 6, and 7). The observedstepwise or humped shape of water relativepermeability curves mainly were attributed to theeffect of water breakthrough ahead of the main floodfront entering into the JBN calculation. Archer andWong suggested that such abnormally shapedrelative-permeability curves do not represent theproperties of the bulk of the core sample, and proposed the use of a reservoir simulator forinterpreting laboratory waterflood data. The work referred to above provides the majorbackground for this study involving the developmentof an improved unsteady-state test method tocharacterize the relative-permeability properties ofheterogeneous carbonate core samples. The methodcan be applied to all porous media, regardless ofthe size and distribution of the heterogeneities.However, the presence of large-scaleheterogeneities, especially in the form of vugs, fractures, and stratification, could cause the derivedrelative-permeability relations to be affected by viscosityratio and displacement rate. Remember also that extrapolation of any core test data to a field scaleis associated with many uncertainties, particularlyfor heterogeneous formations. The inclusion ofcapillary pressure effects permits the interpretationof displacement tests at reservoir rates. The proposed calculation procedure extends theapproach suggested by Archer and Wong in thatthe degree of fit between observed laboratory dataand simulator results is quantified. We suggest thatrelative-permeability curves for a variety of rocktypes can be expressed in terms of two adjustable parameters and their standard error estimates.To illustrate the method, the results of displacementtests performed on cores from Swan Hills Beaverhill Lake limestone oil reservoir and Rainbow F KegRiver dolomite oil reservoir are interpreted. SPEJ P. 15^

Use of a Reservoir Simulator To Interpret Laboratory Waterflood Data

Abstract Relative permeability curves calculated from laboratory waterflood history by the method of Johnson, Bossler and Naumann (JBN) are often poorly defined or anomalous at low and intermediate poorly defined or anomalous at low and intermediate water saturations. Poor definition can be encountered with strongly water-wet homogeneous cores when the displacement is piston-like. Anomalous curve shapes are associated with laboratory-observed water breakthrough ahead of the main flood front and are common in cores that have contrasting permeability streaks. The JBN technique, although permeability streaks. The JBN technique, although valid for the conditions assumed in its development, is unsatisfactory for the conditions specified above. A reservoir simulator has been used to model laboratory tests and thereby provide an alternative interpretation procedure. The simulation uses core properties and trial-and-error relative permeabilities. properties and trial-and-error relative permeabilities. The shapes of the relative permeability curves are adjusted until calculated oil recovery and relative injectivity curves match those obtained from the laboratory displacement tests. The technique has been used successfully to obtain meaningful relative permeability curves for piston-like displacement, mixed wettability systems, piston-like displacement, mixed wettability systems, and heterogeneous carbonates. The technique has also been used in evaluating empirical equations for calculating relative permeability. Introduction Numerical reservoir simulators are finding increasing application in production history matching and performance predictions. Because of the degree of sophistication reached with these models, it is mandatory that the fluid flow properties be of the highest possible quality. Of all the rock and fluid properties required in predicting performance, it is properties required in predicting performance, it is often the relative permeability characteristics that are the most critically important. These data are usually obtained from laboratory waterflood tests using reservoir core samples. The laboratory waterflood test is an attempt to represent the linear displacement behavior of the oil/water/reservoir-rock system. The wettability properties of the rock system should be preserved properties of the rock system should be preserved in the laboratory core sample if reliable results are to be obtained. Furthermore, the viscosity ratio and surface tension of the oil/water system in the laboratory test should ideally be made the same as those in the reservoir. In interpreting laboratory waterflood tests the unsteady-state equations are usually solved by methods of Buckley-Leverett, Welge and Johnson, Bossler and Neumann (JBN). These interpretations are sometimes inadequate for defining relative permeability curves for heterogeneous reservoir permeability curves for heterogeneous reservoir rock systems or for water displacing a very light oil in a homogeneous sandstone. For example, a number of writers have observed anomalous changes in the relative permeability to water during the flooding of heterogeneous carbonate core samples. The relative permeability to water does not increase smoothly with increasing water saturation, but increases stepwise or even humps. Such behavior appears to reflect small-scale local heterogeneity in the core sample and is likely to be insignificant on a field scale. The heterogeneity is often indicated in the laboratory by an observed water breakthrough at the core-sample production face ahead of the main flood front. The time of water breakthrough is an important measurement used in the calculation of relative permeability by the JBN method. If the breakthrough permeability by the JBN method. If the breakthrough time observed is not that of the main flood front but is a little early, then the relative permeabilities calculated will not represent the properties of the bulk of the core sample. It is under these conditions that anomalous relative permeability curves usually occur. We suggest in this paper that, in many cases, the small changes in pressure and in oil and water production rate that accompany anomalous relative production rate that accompany anomalous relative permeability curves can be smoothed to reflect permeability curves can be smoothed to reflect properties more consistent with the bulk behavior properties more consistent with the bulk behavior of the core sample. In essence, we are saying that together the smoothed oil and water production history and the pressure history of the laboratory core sample represent a unique property of that sample.