Drainage Capillary Pressure Curves Research Articles

Towards Large-Scale DRP Simulations: Generation of Large Super-Resolution images and Extraction of Large Pore Network Models

Representativity and accuracy of digital rock physics (DRP) simulations depend strongly on the size of the image volume and the resolution obtained. Even with one of the fastest DRP simulation techniques like pore network modelling, simulation volumes have typically been limited to few cubic millimetres for highly resolved images. In this paper, a super-resolution technique named enhanced super-resolution generative adversarial network (ESRGAN) is used to obtain well-resolved images with large field of view and to generate micro-CT images with resolution enhancement factors of × 4 and × 8. Subsets of resulting ESRGAN images were tested against the same volume (of acquisitions resolved at high and low resolution) by comparing petrophysical properties of interest. Pore network extraction and multiphase simulation results showed that pore size distribution, porosity, permeability, drainage capillary pressure and relative permeability curves obtained using ESRGAN images were more accurate. Large images, however, pose subsequent limitations on DRP simulations as pore network extraction code needs a lot of memory to process them (usually more than 60 GB of RAM for 15003 voxels image). Thus, we present a novel stitching strategy that is developed to enable the extraction of pore networks on such large images. Several validation cases of this method are presented to test the accuracy of the results from stitched networks on single- and multiphase flow properties. Finally, our stitching tool was used to generate two large networks of 3.6 million and 9.2 million elements, respectively, from two large ESRGAN images of approximately 49003 voxels.

A note on dynamic rock typing and TEM-function for grouping, averaging and assigning relative permeability data to reservoir simulation models

For years, rock typing based on two-phase flow characteristics was mainly founded on grouping primary drainage capillary pressure curves, while rock classification based on relative permeability measurements and its practical applications were overlooked. Recently, a dynamic rock typing approach was proposed by defining a True Effective Mobility tool (TEM-function) to convert relative permeability data to fluid flow indicators. This technical note sheds further light on the concept of dynamic rock typing and TEM-function. Moreover, in previous studies the fact that how identified petrophysical dynamic rock types (PDRTs) and their corresponding average relative permeability tables should be assigned to simulation grid cells was not addressed. We accordingly investigate whether a general property can be found to assign average relative permeability data to grid cells. For this purpose, we apply TEM-function to identify PDRTs and present average relative permeability tables using gas-oil relative permeability experiments on a subset of carbonate samples. We also analyze the PDRTs in a counter-part water-oil system and investigate their relationship with gas-oil PDRTs. Results show that the recent dynamic rock typing approach incorporates forward and inverse processes that are physically meaningful and consistent with laboratory analysis and reservoir simulation processes. The strong dependency of TEM-function on the ratio of permeability to porosity enables us to introduce a general property to assign average relative permeability data to grid cells. Furthermore, while PDRTs in the gas-oil systems were almost identical, PDRTs in the water-oil system were dissimilar and different from the gas-oil counterpart. This confirms that each saturation function needs its specific rock typing scheme.

Dynamic measurements of drainage capillary pressure curves in carbonate rocks

The heterogeneity of rocks represents a challenge for interpreting and using outcomes from multiphase-flow experiments carried out on laboratory samples. While the capillary pressure–saturation function, pc(S), is known to vary spatially and cause local saturation development during immiscible displacements, its variation remains difficult to measure. This is particularly challenging for rocks with complex fabrics, such as carbonates. Here, we present a workflow for the dynamic measurement of core- and subcore-scale drainage pc(S) curves in heterogeneous porous media. Multi-rate, two-phase core-flooding tests are conducted on three carbonate rocks with direct observations of local saturation data. The interpretation of the experiments is done by fitting the parameters of the pc(S) curve, while describing both steady-state saturation and pressure profiles with a detailed one-dimensional model that accounts for the variation of subcore-scale properties in the direction of displacement. Workflow validation is achieved by means of synthetic data, thereby demonstrating the uniqueness of the solution of the resulting multi-objective optimisation problem. The model reproduces accurately experimental data on the three rocks and enables computing the effective core-scale pc(S) curve in the limit of zero velocity, as it would be expected during a porous-plate experiment. The output of the proposed technique is however much richer and includes the relativepc(S) curve that is universal and independent of the specific pattern of heterogeneity, in addition to a set of scaling factors. The latter describe the distribution of the pc(S) curves at the subcore-scale due to heterogeneity and form the statistical basis needed for upscaling studies.

An effective approach to generate drainage representative capillary pressure and relative permeability curves in the framework of reservoir electrofacies

Representative capillary pressure and relative permeability curves for reservoir rock types are important inputs for a dynamic reservoir simulator. The current study proposes a third-step approach to generate representative capillary pressure and relative permeability curves of reservoir rock types from nuclear magnetic resonance (NMR) log. First, reservoir electrofacies were identified by integration of conventional well logs and NMR log parameters. Employing cluster analysis reservoir rocks were classified into six electrofacies (EF) with reservoir quality being increased from EF1 to EF6. In the second step, the NMR T2-distribution arrays were converted to synthetic drainage capillary pressure curves and the results were validated by available laboratory measured mercury injection capillary pressure curves (MICP). Finally, the relative permeability curves were generated from the NMR-derived MICP data by using the Wyllie and Gardner equations for each individual electrofacies. Comparing the results with laboratory data indicates the effective role of electrofacies control in generating high accuracy capillary pressure and relative permeability curves. The results of this study show that the application of NMR log can further be extended through the generation of drainage capillary pressure and relative permeability data in the framework of electrofacies clustering.

An Investigation into Different Correlation Methods between NMR T2 Distributions and Primary Drainage Capillary Pressure Curves Using an Extensive Sandstone Database

Many workers have recognised the link between Nuclear Magnetic Resonance (NMR) derived T2 distributions and pore size distributions in reservoir rocks. This property has been used to develop models to obtain primary drainage capillary pressure curves from T2 distributions. These models often assume that the rocks pore space resembles a simple bundle of capillary tubes. They do not consider the existence of multiple pore body connections and pore body restrictions/throats. The most successful models utilise variable scaling factors to convert T2 times to pore diameters and hence capillary pressure. The variable scaling factor approach recognises the existence of variable surface relaxivity throughout the pore space due to variations in mineralogy and pore topography. This investigation uses SCAL data from the ART NMR Sandstone Rock Catalogue to obtain core calibrated variable scaling factors for 174 reservoir sandstone samples. The depositional environments for these samples include; aeolian, fluvial, coastal and shallow and deep marine. The samples used have a wide variety of mineralogy, diagenetic overprints and cover six orders of magnitude in absolute permeability. Three different methods for obtaining the scaling factors are presented and the relative merits of each discussed. A global model to predict capillary pressure from NMR T2 distributions in reservoir sandstones has been developed using correlations between the variable scaling factors and permeability.

F63IDENTIFICATION OF PERIPHERAL miRNA BIOMARKERS IMPLICATED IN THE DEFAULT MODE NETWORK

Representative capillary pressure and relative permeability curves for reservoir rock types are important inputs for a dynamic reservoir simulator. The current study proposes a third-step approach to generate representative capillary pressure and relative permeability curves of reservoir rock types from nuclear magnetic resonance (NMR) log. First, reservoir electrofacies were identified by integration of conventional well logs and NMR log parameters. Employing cluster analysis reservoir rocks were classified into six electrofacies (EF) with reservoir quality being increased from EF1 to EF6. In the second step, the NMR T2-distribution arrays were converted to synthetic drainage capillary pressure curves and the results were validated by available laboratory measured mercury injection capillary pressure curves (MICP). Finally, the relative permeability curves were generated from the NMR-derived MICP data by using the Wyllie and Gardner equations for each individual electrofacies. Comparing the results with laboratory data indicates the effective role of electrofacies control in generating high accuracy capillary pressure and relative permeability curves. The results of this study show that the application of NMR log can further be extended through the generation of drainage capillary pressure and relative permeability data in the framework of electrofacies clustering.

Predicting flow properties in diagenetically-altered media with multi-scale process-based modeling: A Wilcox Formation case study

Two approaches to capture the complex texture of Wilcox sandstone samples in a pore-scale model are employed: a process-based method and an image-based method. In the process-based method, petrographic analyses from transmitted light microscopy are used to infer the diagenetic history of the rock. Key steps in the diagenesis are quantitatively followed using a multi-scale pore-network modeling method to reconstruct the porous medium at different times in its history, including the final state. Further information about pore sizes is gathered from scanning electron microscopy and nitrogen adsorption hysteresis measurements. The ability to incorporate texture information of each diagenetic stage of a tight gas sandstone into a predictive multi-scale pore-network model is a novel aspect of this work. In the image-based method, a micro-CT image of the sample is acquired and a pore-network model is extracted based on skeletonizing the resolvable pore space and mapping clusters of micropores to the unresolved porous areas. The paragenesis of the formation was not captured using the image-based method since sufficient details of its history could not be extracted. The process-based and image-based methods produce comparable drainage capillary pressure curves. While the drainage relative permeability curves in both methods display permeability jail effect, they considerably differ from each other quantitatively. The process-based method produced a higher porosity and permeability compared to the image-based method which is potentially due to the lower degree of its disorder. High uncertainties in the petrophysical properties of tight gas sandstones is a costly challenge in their reservoir development. Our work provides insights into the effect of pore texture from different scales on rock fluid properties. Furthermore, the methods demonstrated in this work can be pursued to extrapolate tight gas sandstone petrophysical properties between wells and throughout paragenetic sequences. • An algorithm for the inclusion of oversize pores in process-based modeling is introduced and implemented. • A comparison of process-based and image-based multi-scale pore-network modeling methods in predicting several petrophysical properties is conducted. • Sedimentary rock fragments and dissolving feldspars can be crucial for fluid flow for the Wilcox Formation. • Permeability jail effect is observed during primary drainage using both methods.

An Ising-Based Simulator for Capillary Action in Porous Media

Multiphase flows in porous media are encountered in several contexts—e.g., hydrocarbon recovery operations, battery electrodes, microfluidic devices, etc. Capillary-dominated flows are interesting due to the complex interplay of interfacial properties and pore geometries. Conventional hydrodynamic flow solvers are computationally inefficient in the capillary-dominated regime, particularly in complex pore structures. The algorithm developed here specifically targets this regime to reduce simulation times. We minimise the fluid–fluid and fluid–solid interaction energies through an approach inspired by the ferromagnetic Ising model. We validate the algorithm on (1) model pore geometries with analytical solutions for capillary action, and (2) rocks with available mercury porosimetry data. We validate its predictions for model geometries and sandstones using (1) curvatures calculated from theories developed by Mayer–Stowe–Princen, Ma and Morrow, and Mason and Morrow; (2) predictions from GeoDict, a commercial software package, which also includes a state-of-the-art drainage simulator; (3) mercury porosimetry data. Drainage capillary pressure curves predicted for Bentheimer and Fontainebleau rocks reasonably match porosimetry data.

A new approach in petrophysical rock typing

Petrophysical rock typing in reservoir characterization is an important input for successful drilling, production, injection, reservoir studies and simulation. In this study petrophysical rock typing is divided into two major categories: 1) a petrophysical static rock type (PSRT): a collection of rocks having the same primary drainage capillary pressure curves or unique water saturation for a given height above the free water level, 2) a petrophysical dynamic rock type (PDRT): a set of rocks with a similar fluid flow behavior. It was shown that static and dynamic rock types do not necessarily overlap or share petrophysical properties, regardless of wettability.In addition, a new index is developed to define PDRTs via the Kozeny-Carman equation and Darcy's law. We also proposed a different index for delineation of PSRTs by combining the Young–Laplace capillary pressure expression and the Kozeny-Carman equation. These new indices were compared with the existing theoretical and empirical indices. Results showed that our indices are representatives of previously developed models which were also tested with mercury injection capillary pressure, water-oil primary drainage capillary pressure, and water-oil relative permeability data on core plugs from a highly heterogeneous carbonate reservoir in an Iranian oil field. This study enabled us to modify the conventional J-function to enhance its capability of normalizing capillary pressure data universally.

Cyclic Steam Stimulation Results in High Water Retention for Kuwaiti Heavy-Oil Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184154, “High Water Retention in Cyclic-Steam-Stimulation Wells of Kuwait Heavy-Oil Field,” by Anil Kumar Jain, Amal Al-Sane, and Fatma Ahmad, Kuwait Oil Company, prepared for the 2016 SPE International Heavy Oil Conference and Exhibition, Mangaf, Kuwait, 6–8 December. The paper has not been peer reviewed. Cyclic steam stimulation (CSS) is one of the principal enhanced-oil-recovery methods for heavy oil. CSS was performed in some of the wells of a heavy-oil field in Kuwait. Multiple cycles were applied in these wells. However, the total water produced in each cycle was much less than expected. This paper presents experiments that were conducted to find possible reasons for the high water retention. Hysteresis in CSS Hysteresis in drainage and imbibition nonwetting-phase capillary pressure and relative permeability curves is an established phenomenon. Hysteresis of capillary pressure and relative permeability to water has a great effect on heavy-oil recovery and producing water/oil ratios (WORs) during cyclic steam stimulation. Produced WOR calculated without considering hysteresis will be unrealistically high relative to that observed in the fields. Water Retention During water injection, relative permeability to water increases, and, during the production phase, it decreases; however, it does not follow the same path. Relative permeability to water during the production phase is always less than that during the injection phase at the same water saturation. Irreducible water saturation during the production phase is more than the initial water saturation before injection. The difference between these two water saturations is water retention. The same phenomenon occurs when CSS is applied. As a result of hysteresis and temperature, irreducible water saturation does not reach the initial water saturation. When steam is injected into a formation, the formation becomes increasingly water-wet. In subsequent cycles, steam injection reduces the oil saturation and increases the water saturation around the wellbore. Relative permeability to oil at high water saturation is also reduced. In later cycles, increasingly more water is produced than oil, and, therefore, the WOR increases. The produced water consists of both the condensed steam and the formation water. After steam is injected, fresh water is produced first, and slowly the salinity of the produced water increases. Initially, some of the condensed steam returns, but, later, formation water is produced with the condensed steam. If the well produces for long enough, eventually only formation water will be produced.

Footprints of spontaneous fluid redistribution on capillary pressure in porous rock

AbstractPore‐scale imaging of two‐phase flow in porous media shows that pore filling occurs as cooperative events with accompanying spontaneous fluid redistribution in other parts of the pore space. We present a level set method that controls saturation quasi‐statically to model experiments controlled by low, constant flow rates and demonstrate that our method can describe the observed displacement mechanisms. The level set approach determines states of capillary equilibrium, which generally are different for displacement protocols constrained by saturation and pressure. Saturation‐controlled simulations of drainage in sandstone show spontaneous fluid redistributions with abrupt pressure jumps and cooperative behavior, including snap‐off and interface retraction events, consistent with experimental observations. Drainage capillary pressure curves are lower when saturation, rather than pressure, controls displacement. Remarkably, these effects are less significant for imbibition processes where the development of hydraulically connected wetting phase moderates the cooperative behavior and associated pressure jumps.

Evaluating the impacts of fine-scale capillary heterogeneity and wettability on the behavior of buoyancy-driven CO2 migration and trapping mechanisms

One of the primary concerns in CO2 sequestration is long-term immobilization of CO2. There are several storage mechanisms to immobilize CO2 in a porous medium: structural, dissolution, residual, and mineral trapping. Storage analysis with fine-scale heterogeneity requires the investigation of a newly suggested mechanism: capillary barrier trapping. This study covers a quantitative assessment of the CO2 trapping capacity with residual, dissolution, and capillary barrier trapping mechanisms in heterogeneous formations. The effects of heterogeneity on CO2 trapping capacity are studied under different wettability scenarios. The Leverett J-function is applied so that every grid block has a different drainage capillary pressure curve, which is physically consistent with its heterogeneous properties and wettability. Based on contact angle, residual saturation and relative permeability curves are modeled. Different heterogeneity and wettability causes considerable variations in leakage of CO2, ranging from 6 to 38 %. The lateral correlation length of permeability affects the spatial distribution of CO2. As the permeability variation increases, the total amount of trapped CO2 increases significantly indicating a reduced potential risk of leakage. Although the residual and dissolution trappings decreases as the wetting condition changes from strongly water-wet to intermediate gas-wet, the amount of CO2 trapped by the capillary barriers increases considerably, and the mobile phase saturation of the CO2 is reduced. The results of this study have emphasized the importance of capillary barrier trapping, which takes a large portion of the immobilized CO2 phase, for stable underground storage.

Revisiting the applications of drainage capillary pressure curves in water-wet hydrocarbon systems

AbstractThe main focus of the paper is to introduce a new approach at studying and modelling the relationship of initial water saturation profile and capillarity in water-wet hydrocarbon reservoirs, and describe the available measurement methods and possible applications. As a side track it aims to highlight a set of derivable parameters of mercury capillary curves using the Thomeer-method. Since the widely used mercury capillary pressure curves themselves can lead to over-, or underestimations regarding in-place and technical volumes and misinterpreted reservoir behaviour, the need for a proper capillary curve is reasonable. Combining the results of mercury and centrifuge capillary curves could yield a capillary curve preserving the strengths of both methods, while overcoming their weaknesses. Mercury injection capillary curves were normalized by using the irreducible water saturations derived from centrifuge capillary pressure measurements of the same core plug, and this new, combined capillary curve was applied for engineering calculations in order to make comparisons with other approaches. The most significant benefit of this approach is, that all of the measured data needed for a valid drainage capillary pressure curve represents the very same sample piece.

Evaluation of representative elementary volume for a vuggy carbonate rock – Part II: Two-phase flow

Abstract Large spatial variation of petrophysical properties and heterogeneous fluid displacement behavior are often associated with vuggy carbonate rocks. Because vugular rocks are characterized by large heterogeneity at the core-sample scale, the property measurements vary significantly between samples and the assessment of oil recovery is often unreliable. This paper focuses on variability of two-phase flow properties in a vuggy carbonate material. Drainage and waterflood experiments were performed on 12 different sample sizes, ranging from cm to m scale. The results for oil recovery show that the largest sample is above REV and reflects the average for the smaller volumes. An arithmetic average is found to be an appropriate upscaling scheme for oil recovery, thus the studied vuggy material can be regarded as heterogeneously homogeneous. Based on 2D gamma-ray saturation maps semivariogram functions were calculated. Both initial and residual saturations were spatially correlated. For two larger samples, the drainage and waterflood displacements were performed and monitored by x-ray providing high-resolution images. The results were used to measure the dispersion of the displacement front. The front behavior patterns and dispersion lengths were found to be similar for drainage and waterflood processes within the same sample. The effect of heterogeneities on the drainage capillary pressure curve and on spontaneous imbibition has been investigated. Nuclear Magnetic Resonance (NMR) 1D-saturation monitoring performed on a sample after a centrifuge test was used to investigate the air–water drainage capillary pressure curve. The obtained curve indicated variations along the sample. Imaging of the displacement front for spontaneous imbibition was performed to investigate impact of heterogeneities on the process.

The Impact of Tides on the Capillary Transition Zone

The capillary transition zone, also known as the capillary fringe, is a zone where water saturations decrease with height above the water table/oil–water contact as a result of capillary action. In some oil reservoirs, this zone may contain a significant proportion of the oil in place. In groundwater assessments, the capillary fringe can profoundly affect contaminant transport. In this study, we investigated the influence of a tidally induced, semi-diurnal, change in water table depth on the water saturation distribution in the capillary fringe/transition zone. The investigation used a mixture of laboratory experiments, in which the change in saturation with depth was monitored over a period of 90 days, and numerical simulation. We show that tidal changes in water table depth can significantly alter the vertical water saturation profile from what would be predicted using capillary–gravity equilibrium and the drainage or imbibition capillary pressure curves.

Capillary Heterogeneity in Sandstone Rocks During CO2/Water Core-flooding Experiments

We have successfully applied a novel experimental technique to measure drainage capillary pressure curves in reservoir rocks with representative reservoir fluids at high temperatures and pressures. The method consists of carrying out 100% CO2 flooding experiments at increasingly higher flow rates on a core that is initially saturated with water and requires that the wetting-phase pressure is continuous across the outlet face of the sample. Experiments have been carried out on a Berea Sandstone core at 25 and 50°C and at 9MPa pore pressure, while keeping the confining pressure at 12MPa. Measurements are in good agreement with data from mercury intrusion porosimetry. The technique possesses a great potential of applicability due to the following reasons: (a) it can be applied in conjunction with steady-state relative permeability measurements, as it shares a very similar experimental configuration; (b) it is faster than traditional (porous-plate) techniques used for measuring capillary pressure on rock cores with reservoir fluids; (c) by comparison with results from mercury porosimetry, it allows for the estimation of the interfacial and wetting properties of the CO2/water system, the latter being unknown for most rocks; (d) by combination with X-ray CT scanning, the method allows for the observation of capillary pressure–saturation relationships on mm-scale subsets of the rock core. The latter are of high relevance as they directly and non- destructively measure capillary pressure curve heterogeneity in sandstone rocks.

A Dimensionless Capillary Pressure Function for Imbibition Derived From Pore-Scale Modeling in Mixed-Wet-Rock Images

Summary It has been demonstrated experimentally that Leverett's J-function yields almost unique dimensionless drainage capillary pressure curves in relatively homogeneous rocks at strongly water-wet conditions, whereas for imbibition at mixed-wet conditions, it does not work satisfactorily because the permeability dependency on capillary pressure has been reported to be weak. The purpose of this study is to formulate a new dimensionless capillary pressure function for mixed-wet conditions on the basis of pore-scale modeling, which could overcome these restrictions. We simulate drainage, wettability alteration, and imbibition in 2D rock images by use of a semianalytical pore-scale model that represents the identified pore spaces as cross sections of straight capillary tubes. The fluid configurations occurring during drainage and imbibition in the highly irregular pore spaces are modeled at any capillary pressure and wetting condition by combining the free-energy minimization with an arc meniscus (AM)-determining procedure that identifies the intersections of two circles moving in opposite directions along the pore boundary. Circle rotation at pinned contact lines accounts for mixed-wet conditions. Capillary pressure curves for imbibition are simulated for different mixed-wet conditions in Bentheim sandstone samples, and the results are scaled by a newly proposed improved J-function that accounts for differences in formation wettability induced by different initial water saturations after primary drainage. At the end of primary drainage, oil-wet-pore wall segments are connected by many water-wet corners and constrictions that remain occupied by water. The novel dimensionless capillary pressure expression accounts for these conditions by introducing an effective contact angle that depends on the initial water saturation and is related to the wetting property measured at the core scale by means of a wettability index. The accuracy of the proposed J-function is tested on 36 imbibition capillary pressure curves for different mixed-wet conditions that are simulated with the semianalytical model in scanning-electron-microscope (SEM) images of Bentheim sandstone. The simulated imbibition capillary pressure curves and the reproduced curves, based on the proposed J-function, are in good agreement for the mixed-wet conditions considered in this study. The detailed behavior is explained by analyzing the fluid displacements occurring in the pore spaces. It is demonstrated that the proposed J-function could be applied to mixed-wet conditions to generate a family of curves describing different wetting states induced by assigning different wetting properties on the solid surfaces or by varying the initial water saturation after primary drainage. The variability of formation wettability and permeability could be described more accurately in reservoir-simulation models by means of the proposed J-function, and hence the opportunity arises for improved evaluation of core-sample laboratory experiments and reservoir performance.

Upscaling of the constitutive relationships for CO2 migration in multimodal heterogeneous formations

Numerical modeling is a critical tool for site performance and risk assessment of geological stored CO2 at the reservoir scale. However, due to computational resource constraints, reservoir scale models have limitations in accounting for the details of the multi-scale heterogeneities. Appropriately averaged medium parameters are needed for the full scale modeling. In this study, we apply the macroscopic theory and present large-scale capillary pressure–relative permeability–saturation relationships that may be used as grid-block properties in the full-scale modeling. A macroscopic invasion percolation (MIP) model is developed, based on the assumption of capillary force dominance. Comparison of the MIP model with the numerical simulator TOUGH2/ECO2N for simulations of large-scale drainage capillary pressure curves shows a reasonably good match between results from the two models. Large-scale constitutive relationships are obtained through simulation procedures of CO2 displacing brine in multimodal heterogeneous media for ten cases with different geostatistical parameters. The large-scale constitutive relationships are mainly controlled by the proportion and the permeability variability of the background (framework) material, while the existence of the non-framework materials and their permeability variabilities may contribute, in a complex way, to the uncertainty in the large-scale constitutive relationships. In addition, the Leverett equation may well describe the relationship between the large-scale capillary pressure and absolute permeability when the sandstone (background material) proportion is high (>0.7). For cases with smaller sandstone proportions it may not be appropriate to link capillary pressure and absolute permeability through the Leverett equation.

De l’application à la réflexion : mise en place d’une équipe santé au travail dans un service interentreprise du Puy-de-Dôme

A novel method is presented to measure drainage capillary pressure curves both at the core and sub-core scale using CO2 and water at reservoir conditions. The experimental configuration is very similar to the one used in traditional steady-state relative permeability experiments. Capillary pressure measurements are made at the inlet face of the sample by successively increasing the flow rate of the non-wetting phase while measuring the saturation with a medical X-ray Computed Tomography (CT) scanner. The method requires that the wetting phase pressure is uniform across the core and can be measured in the outlet end-cap. A capillary pressure curve is obtained in less than two days, as compared to weeks for existing methods that use porous plates. Drainage capillary pressure curves of CO2 and water are measured for two sandstones rock cores with different lithology and pore size distribution. Experiments are carried out at 25 and 50 °C and at 9 MPa pore pressure, while keeping the confining pressure on the core at 12 MPa. There is excellent agreement between the new method and data from mercury intrusion porosimetry; beside providing confidence in the new technique, such comparison allows for an estimate of the wetting and interfacial properties of the CO2/water system. X-ray CT scanning allows for precise imaging of fluid saturations at a resolution of about (2.5 × 2.5 × 1) mm3, thus enabling quantification of sub-core scale capillary pressure curves. These measurements provide independent confirmation that sub-core scale capillary heterogeneity plays an important role in controlling saturation distributions during multiphase flow.

Capillary pressure and heterogeneity for the CO2/water system in sandstone rocks at reservoir conditions

A novel method is presented to measure drainage capillary pressure curves both at the core and sub-core scale using CO2 and water at reservoir conditions. The experimental configuration is very similar to the one used in traditional steady-state relative permeability experiments. Capillary pressure measurements are made at the inlet face of the sample by successively increasing the flow rate of the non-wetting phase while measuring the saturation with a medical X-ray Computed Tomography (CT) scanner. The method requires that the wetting phase pressure is uniform across the core and can be measured in the outlet end-cap. A capillary pressure curve is obtained in less than two days, as compared to weeks for existing methods that use porous plates. Drainage capillary pressure curves of CO2 and water are measured for two sandstones rock cores with different lithology and pore size distribution. Experiments are carried out at 25 and 50°C and at 9MPa pore pressure, while keeping the confining pressure on the core at 12MPa. There is excellent agreement between the new method and data from mercury intrusion porosimetry; beside providing confidence in the new technique, such comparison allows for an estimate of the wetting and interfacial properties of the CO2/water system. X-ray CT scanning allows for precise imaging of fluid saturations at a resolution of about (2.5×2.5×1)mm3, thus enabling quantification of sub-core scale capillary pressure curves. These measurements provide independent confirmation that sub-core scale capillary heterogeneity plays an important role in controlling saturation distributions during multiphase flow.