Berea Samples Research Articles

Lattice Boltzmann simulation of cross-linked polymer gel injection in porous media

This study addresses the critical challenge of excessive water production in mature oil and gas reservoirs. It focuses on the effectiveness of polymer gel injection into porous media as a solution, with an emphasis on understanding its impact at the pore scale. A step-wise Lattice Boltzmann Method (LBM) is employed to simulate polymer gel injection into a 2D Berea sample, representing a realistic porous media. The non-Newtonian, time-dependent characteristics of polymer gel fluid necessitate this detailed pore-scale analysis. Validation of the simulation results is conducted at each procedural step. The study reveals that the methodology is successful in predicting the effect of polymer gel on reducing permeability as the gel was mainly formed in relatively larger pores, as it is desirable for controlling water cut. Mathematical model presented in this study accurately predicts permeability reductions up to 100% (complete blockage). In addition, simulations conducted over a wide range of gelation parameters, TD_factor from 1 to 1.14 and Threshold between 0.55 and 0.95, revealed a quadratic relationship between permeability reduction and these parameters. The result of this research indicates LBM can be considered as promising tool for investigating time-dependant fluids on porous media.

Evaluation of the impact of low-salinity water on wettability alteration and oil recovery in Berea sandstones

Low-salinity water (LSW) flooding is an emerging technique to enhance oil recovery from carbonate and sandstone reservoirs. Despite growing interest in the field, significant disparities remain regarding the underlying mechanisms. While most researchers agree that wettability alterations may be the dominant mechanism, their quantitative impact on oil recovery remains elusive. This study quantitatively evaluated the effects of LSW flooding on rock wettability alteration and oil recovery enhancement using a non-polar crude through a series of U.S. Bureau of Mines (USBM) tests and contact angle measurements on synthetic clay-free Berea samples with similar textural properties and pore structures. Experimenting on clay-free samples and non-polar crude evaded the effects of (i) mineral dissolution, (ii) interfacial tension reduction due to in-situ saponification, and (iii) wettability alteration due to multi-ion exchange between clays and the crude-oil polar compounds. When water salinity varied from 85,000 to 4,000 ppm, the USBM index increased from approximately 0.26 to 0.38, thereby confirming a minor change in wettability alteration toward a more water-wet condition. These changes were consistent with a decrease in the contact angle from approximately 55.6° to 35.3°. As water salinity decreased to approximately 5 % of its original value, centrifuge data indicated a drop in the residual oil saturation from 0.247 to 0.202, corresponding to a minor increase (of approximately 4 %) in the oil recovery factor at the end of the forced imbibition cycle. This slight oil recovery enhancement is consistent with the minor wettability alterations observed in this study. However, the relatively large recovery factor values reported in the literature were not reproduced in this experiment. The reported findings of this study concerning the evaluation of wettability alteration and recovery factor improvement caused by LSW flooding are unique because they (i) are based on reproducible measurements obtained using state-of-the-art ultrahigh-speed rock centrifuge and core test system that simultaneously measures capillary pressure, evaluates rock wettability, and generates relative permeability data, and (ii) are focused on clean sandstones.

Pore structure and wetting alteration combine to produce the low salinity effect on oil production

Low salinity water flooding is a promising enhanced oil recovery technique that has been observed, in experiments over a range of scales, to increase oil production by up to 14% in some systems. However, there is still no way of reliably predicting which systems will respond favourably to the technique. This shortcoming is partly because of a relative lack of pore scale observations of low salinity water flooding. This has led to a poor understanding of how mechanisms on the scale of micrometres lead to changes in fluid distribution on the scale of centimetres to reservoir scales. In this work, we use X-ray micro-CT scanning to image unsteady state experiments of tertiary low salinity water flooding in Berea, Castlegate, and Bunter sandstone micro-cores. We observe fluid saturations and characterise the wetting state of samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the Berea sample, we observed an additional oil recovery of 3 percentage points during low salinity water flooding, with large volumes of oil displaced from small pores but also re-trapping of mobilised oil in large pores. In the Bunter sandstone, we observed 4 percentage point additional recovery with significant displacement of oil from small pores and no significant retrapping of oil in large pores. However, in the Castlegate sample, we observed just 1 percentage point of additional recovery and relatively small volumes of oil mobilisation. We observe a significant wettability alteration towards more water-wet conditions in the Berea and Bunter sandstones, but no significant alteration in the Castlegate sample. We hypothesise that pore structure, specifically the topology of large pores impacted recovery. We find that poor connectivity of the largest pores in each sample is strongly correlated to additional recovery. This work is the first systematic comparison of the pore scale response to low salinity flooding across multiple sandstone samples. Moreover, it gives the first pore scale insights into the role of pore geometry and topology on the mobilisation of oil during low salinity water flooding.

Reservoir geology of the Berea Sandstone (uppermost Devonian), eastern Kentucky

Berea reservoirs in eastern Kentucky are developed in tight siltstone and sandstone. Precision horizontal drilling provides access to thin ( 0.1 md, porosity is generally >10%. Cement in Berea samples includes quartz overgrowths, ferroan dolomite, siderite, pyrite, and kaolinite. In addition, these rocks were subject to varying degrees of intergranular compaction, quartz overgrowths, and secondary porosity formation (grain dissolution). In thin section, three pore types were encountered: (1) primary intergranular pores, (2) secondary moldic pores, and (3) microporosity. Intergranular porosity is most common. Mercury capillary injection tests show that moderate-permeability (0.02–0.2 md) Berea has pore size distributions of 1 to less than 0.1 μm, but mostly from 0.5 to 0.6 μm, which are commonly found in gas reservoirs. Higher-permeability samples (1.2–2.0 md) have pore-throat diameter distributions of 2 to >0.1 μm. The highest pore volumes (near 3.25%) have pore diameters of 1–2 μm, which is more characteristic of oil-producing reservoirs.

Nonlinear acoustics evaluation of CO2 exposed sandstone

In an effort to better understand the hygro-thermo-mechanical behavior of geologic CO2 reservoir material, we investigate the non-linear behavior of elastic wave propagation in Berea sandstone samples, which are used as a standard for reservoir rock formations. Nonlinear characterization methods, including resonant ultrasound spectroscopy (RUS), dynamic acousto-elasticity (DAET), and single-impact nonlinear resonance techniques, are applied to pristine, damaged (distributed microfractures), and CO2 injected Berea samples; conventional linear vibrational and wave propagation measurements are also applied to the samples. The results of these sensitive test methods are compared to reveal the characteristics of geologic reservoir materials that are most affected by varying microstructural and environmental conditions. An analysis of the work also leads to potential bases for test methods that could be deployed in the field in the future to monitor the condition of reservoir formations and lead to better under...

A Hierarchical Sampling for Capturing Permeability Trend in Rock Physics

Among all properties of reservoir rocks, permeability is an important parameter which is typically measured from core samples in the laboratory. Due to limitations of core drilling all over a reservoir, simulation of rock porous media is demanded to explore more scenarios not seen in the available data. One of the most accurate methods is cross correlation based simulation (CCSIM) which recently has broadly applied in geoscience and porous media. The purpose of this study is producing realizations with the same permeability trend to a real sample. Berea sandstone sample is selected for this aim. Permeability results, extracted from smaller sub-samples of the original sample, showed that classic Kozeny–Carman permeability trend is not suitable for this sample. One reason can be due to lack of including geometrical and fractal properties of pore-space distribution in this equation. Thus, a general trend based on fractal dimensions of pore-space and tortuosity of the Berea sample is applied in this paper. Results show that direct 3D stochastic modeling of porous media preserves porous structure and fractal behavior of rock. On the other hand, using only 2D images for constructing the 3D pore structures does not reproduce the measured experimental permeability. For this aim, a hierarchical sampling is implemented in two and three steps using both 2D and 3D stochastic modeling. Results showed that two-step sampling is not suitable enough, while the utilized three-step sampling occurs to be show excellent performance by which different models of porous media with the same permeability trend as the Berea sandstone sample can be generated.

Multi-technique approach to the petrophysical characterization of Berea sandstone core plugs (Cleveland Quarries, USA)

Berea sandstone has been used by the petroleum industry as a representative model siliciclastic rock for a number of years. However, only incomplete data has been reported in the literature regarding its petrographic, geochemical, and petrophysical properties. In particular knowledge of the mineral distribution along the pore walls is particularly scarce, despite the fact that mineral exposed in the pore space will be crucial in determining the rock-fluid interactions that occur during core-flooding experiments. In this paper, four Berea sandstone samples (with 4 different permeability ranges from <50mD, 50–100mD. 100–200mD, and 500–1000mD) were subjected to a multi-technique characterization with an emphasis on determining the mineral composition, and distribution at the pore surface as well as pore structure and connectivity analysis. The mineral distribution was measured in two-dimensions by chemical mapping using energy dispersive X-ray spectroscopy–scanning electron microscopy (SEM–EDX). The bulk composition of the Berea sandstones was also measured by X-ray diffraction and micro-X-ray computed tomography. From this, it was found that authigenic minerals, especially clay minerals, make up a small portion of the bulk rock volume (3.3–8%) but are over-represented at the pore surfaces and in pore spaces compared to the other major mineral constituents of the rock (quartz and feldspar). The effective mineralogy, from the standpoint of rock-fluid interactions, is the mineralogy that predominates at pore surfaces. For the Berea sandstone samples studied, the effective mineralogy is represented, mainly, by kaolinite, illite, and chlorite. For 3 of the four permeability ranges studied, kaolinite is the predominant pore lining mineral observed. In the remaining sample (50–100mD), illite is the predominant mineral. In addition to SEM, we used atomic force microscopy to show that the nano-sized particles with the shape and size of clay crystals are observed on the surface of recrystallised quartz grains in a Berea sample. Regardless of their origin and identity, the presence of these particles shows that the quartz grain surfaces in Berea sandstone are more heterogeneous than previously assumed. Carbonate cement was somewhat localized throughout two of the Berea sandstone specimens, however, quartz cement is common in all of the Berea cores studied and include both microcrystalline quartz and amorphous silica phases. The pore structure within the four different Berea samples was studied using a combination of X-ray computed tomography, mercury injection porosimetry and high resolution scanning electron microscopy. Results show that two Berea sandstone permeability ranges have a bimodal pore-throat-size distribution whereas the other two were dominated by a unimodal pore-throat size distribution. SEM imaging of the pore network showed that permeability is mainly controlled by pore connectivity in the clay mineral matrix. Next to the pore connectivity, three-dimensional pore space showing both pore-to-pore and pore-to-pore-throat-to-pore relationships are also important.

Seismoelectric measurements in a porous quartz‐sand sample with anisotropic permeability

ABSTRACTSeismoelectric coupling coefficients are difficult to predict theoretically because they depend on a large numbers of rock properties, including porosity, permeability, tortuosity, etc. The dependence of the coupling coefficient on rock properties such as permeability requires experimental data. In this study, we carry out a set of laboratory measurements to determine the dependence of seismoelectric coupling coefficient on permeability. We use both an artificial porous “sandstone” sample, with cracks, built using quartz‐sand and Berea sandstone samples. The artificial sample is a cube with 39% porosity. Its permeability levels are anisotropic: 14.7 D, 13.8 D, and 8.3 D in the x‐, y‐, and z‐directions, respectively. Seismoelectric measurements are performed in a water tank in the frequency range of 20 kHz–90 kHz. A piezoelectric P‐wave source is used to generate an acoustic wave that propagates through the sample from the three different (x, y, and z) directions. The amplitudes of the seismoelectric signal induced by the acoustic waves vary with the direction. The highest signal is in the direction of the highest permeability, and the lowest signal is in the direction of the lowest permeability. Since the porosity of the sample is constant, the results directly show the dependence of seismoelectric coefficients on permeability. Seismoelectric measurements with natural rocks are performed using Berea sandstone 500 and 100 samples. Because the Berea samples are nearly isotropic in permeability, the amplitudes of the seismoelectric signals induced in the different directions are the same within the measurement error. Because the permeability of Berea 500 is higher than that of Berea 100, the amplitude of the seismoelectric signals induced in Berea 500 is higher than those in Berea 100. To determine the relative contributions of porosity and permeability on seismoelectric conversion, we carried out an analysis, using Pride (1994) formulation and Kozeny–Carman relationship; the normalized amplitudes of seismoelectric coupling coefficients in three directions are calculated and compared with the experimental results. The results show that the seismoelectric conversion is related to permeability in the frequency range of measurements. This is an encouraging result since it opens the possibility of determining the permeability of a formation from seismoelectric measurements.

Effect of fracture roughness on seismic source and fluid transport responses

To explain how fracture roughness affects seismic source and transport response of deformed fractured rock, we developed a microscale fluid flow‐geomechanics‐seismicity model. The modeling method considers comprehensive grains and cement interactions. Fluid flow behavior is obtained through realistic network models of the pore space in the compacted assembly. In addition, forces and displacements in the grains involved in the bond breakage are measured to determine seismic moment tensor. The results of our work show that in addition to stress conditions in the target formation, geological properties of preexisting fractures affect volumetric deformation of the seismic source as well. The results of the model proves that roughness of fractures, applied in a Berea sample, causes deviation of source mechanism of acoustic emission events toward opening tensile part and enhances the permeability of the sample significantly during its failure even under confining pressure.

A New Approach in Permeability and Hydraulic-Flow-Unit Determination

Summary Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field-development plans. All field-data acquisitions from seismic, well logging, production, and geomechanical monitoring to enhanced-oil-recovery (EOR) operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model of the field and associated operations is essential for a successful implementation of such projects. Furthermore, using a more reliable model can, in turn, provide the basis in the decision-making process for control and remediation of formation damage. One of the key identifiers of the subsurface model is accurately predicting the hydraulic-flow units (HFUs). There are several models currently used in the prediction of these units on the basis of the type of data available. The predictions that used these models differ significantly because of the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions, thus increasing the need for better models. A new approach has been developed in this study for predicting the petrophysical properties and improving the reservoir characterization. The Poiseuille flow equation and Darcy equation were coupled, taking into consideration the irreducible water saturation in the pore network. The porous medium was introduced as a domain containing a bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis was performed on 17 Berea sandstone samples, and the petrophysical properties were measured and X-ray diffraction (XRD) analysis was conducted. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers, each layer representing one Berea sample. Afterward, by the iteration and calibration of the laboratory data, the number of HFUs was determined by use of the common HFU model and the proposed model accordingly. A comparative study shows that the new model provides a better distribution of HFUs and prediction of the petrophysical properties. The new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for the Berea sandstone experimental data and the model predictions by use of the new permeability model shows a wider range of applicability for various reservoir conditions. In addition, the model has been applied to a series of core-analysis data on low-permeability Medina sandstone, Appalachian basin, northwest Pennsylvania. The flow-unit distribution by use of the proposed model shows a better flow-zone distinction, and the permeability/ porosity relationship has a higher confidence coefficient.

Influence of Heterogeneity on Relative Permeability for CO2/Brine: CT Observations and Numerical Modeling

The determination of relative permeability of CO2/brine fluids under reservoir condition is critical for the design of CO2 injection strategy and prediction of CO2 behavior underground through reservoir simulation. For some reservoirs only heterogeneous samples are available for measurement. Heterogeneity, such as layering or cross bedding lamination can commonly be seen in sandstone cores. The effects and mechanism of core-scale heterogeneities on macroscopic scale relative permeability must be well-addressed. Here we report two sets of laboratory core flooding experiments using Berea sandstone for steady-state measurement of relative permeability of CO2/Brine at reservoir condition [1]. Berea sandstone is relatively homogeneous but has strong bedding or lamination structures. Two Berea samples were used (cored along the directions parallel to and perpendicular to the bedding, and named Berea-1 and Berea-2 respectively). We recorded the pressure and discharge volume to get the relative permeability curves for both samples; and utilized the X-ray computed tomography to estimate the distributions of porosity and CO2 (or Brine) saturation for Berea-2. The measured phase relative permeability of Berea-2 sample is greatly deviated from Berea-1. To further investigate the effects of core-scale heterogeneity on the measurement of relative permeability, we carried out a series numerical simulation on core scale using Tough2ECO2N code with building models based on X-ray CT scan images. By comparing the numerical results, we found the heterogeneity of capillary pressure field under one injection direction plays a dominant role in CO2/brine saturation patterns, flow regime and apparent relative permeability model.

Digital rock physics benchmarks—Part I: Imaging and segmentation

The key paradigm of digital rock physics (DRP) “image and compute” implies imaging and digitizing the pore space and mineral matrix of natural rock and then numerically simulating various physical processes in this digital object to obtain such macroscopic rock properties as permeability, electrical conductivity, and elastic moduli. The steps of this process include image acquisition, image processing (noise reduction, smoothing, and segmentation); setting up the numerical experiment (object size and resolution as well as the boundary conditions); and numerically solving the field equations. Finally, we need to interpret the solution thus obtained in terms of the desired macroscopic properties. For each of these DRP steps, there is more than one method and implementation. Our goal is to explore and record the variability of the computed effective properties as a function of using different tools and workflows. Such benchmarking is the topic of the two present companion papers. Here, in the first part, we introduce four 3D microstructures, a segmented Fontainebleau sandstone sample (porosity 0.147), a gray-scale Berea sample; a gray-scale Grosmont carbonate sample; and a numerically constructed pack of solid spheres (porosity 0.343). Segmentation of the gray-scale images by three independent teams reveals the uncertainty of this process: the segmented porosity range is between 0.184 and 0.209 for Berea and between 0.195 and 0.271 for the carbonate. The implications of the uncertainty associated with image segmentation are explored in a second paper.

Relative permeability and trapping of CO2 and water in sandstone rocks at reservoir conditions

We report the results of an experimental investigation into the multiphase flow properties of CO2 and water in four distinct sandstone rocks: a Berea sandstone and three reservoir rocks from formations into which CO2 injection is either currently taking place or is planned. Drainage relative permeability and residual gas saturations were measured at 50°C and 9 MPa pore pressure using the steady state method in a horizontal core flooding apparatus with fluid distributions observed using x‐ray computed tomography. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample. Relative permeability in the four samples is consistent with general characteristics of drainage in strongly water‐wet rocks. Measurements in the Berea sample are also consistent with past measurements in Berea sandstones using both CO2/brine and oil/water fluid systems. Maximum observed saturations and permeabilities are limited by the capillary pressure that can be achieved in the experiment and do not represent endpoint values. It is likely that maximum saturations observed in other studies are limited in the same way and there is no indication that low endpoint relative permeabilities are a characteristic of the CO2/water system. Residual trapping in three of the rocks is consistent with trapping in strongly water‐wet systems, and the results from the Berea sample are again consistent with observations in past studies. This confirms that residual trapping can play a major role in the immobilization of CO2 injected into the subsurface. In the Mt. Simon sandstone, a nonmonotonic relationship between initial and residual CO2 saturations is indicative of a rock that is mixed or intermediate wet, and further investigations should be performed to establish the wetting properties of illite‐rich rocks. The combined results suggest that the petrophysical properties of the multiphase flow of CO2/water through siliciclastic rocks is for the most part typical of a strongly water‐wet system and that analog fluids and conditions may be used to characterize these properties. Further investigation is required to identify the wetting properties of illite‐rich rocks during imbibition processes.

Understanding the micro structure of Berea Sandstone by the simultaneous use of micro-computed tomography (micro-CT) and focused ion beam-scanning electron microscopy (FIB-SEM)

Berea sandstone is the building block for reservoirs containing precious hydrocarbon fuel. In this study, we comprehensively reveal the microstructure of Berea sandstone, which is often treated as a porous material with interconnected micro-pores of 2–5μm. This has been possible due to the combined application of micro-computed tomography (CT) and focused ion beam (FIB)-scanning electron microscopy (SEM) on a Berea sample. While the use of micro-CT images are common for geological materials, the clubbing and comparison of tomography on Berea with state-of-the-art microstructure imaging techniques like FIB-SEM reveals some unforeseen features of Berea microstructure. In particular, for the first time FIB-SEM has been used to understand the micro-structure of reservoir rock material like Berea sandstone. By using these characterization tools, we are able to show that the micro-pores (less than 30μm) are absent below the solid material matrix, and that it has small interconnected pores (30–40μm) and large crater-like voids (100–250μm) throughout the bulk material. Three-dimensional pore space reconstructions have been prepared from the CT images. Accordingly, characterization of Berea sandstone specimen is performed by calculation of pore-structure volumes and determination of porosity values.

Shear wave attenuation in dry and saturated sandstone at seismic to ultrasonic frequencies

Ultrasonic and forced-oscillation methods have been applied to measure shear attenuation in Berea sandstone and a fused glass bead sample in the frequency ranges of .03 to 100 Hz and 600 to 1000 kHz. The Qs of dry Berea sandstone at atmospheric pressure falls in the range 100 to 150 for frequencies between .03 Hz and 20 Hz. The ultrasonic results show a much lower Q S (<100) and a strong effect of complete fluid saturation. In the dry Berea samples, Q S is most strongly influenced by frequency at the highest confining pressure of 70 MPa. In all cases, ultrasonic shear Q decreases with increasing frequency. Fluid-flow mechanisms are indicated as the responsible loss mechanisms, both in the saturated samples and in the humid (room-dry) samples.

Evaluation of the High-Speed Centrifuge Technique for Determining Capillary Pressure at Low Wetting-Phase Saturations

ABSTRACTRecent experimental studies of the high-speed centrifuge technique have indicated that the method, if properly used, yields results which are in accordance with other methods. These studies have also shown that the concept of an irreducible wetting phase saturation is not valid. In the present paper work is reported in which these previously presented results are extended to both higher and lower capillary pressures. Air/liquid data have been obtained with n-decane as the wetting phase and are compared with new data (as well as with the previously reported data) for the air/brine system. The study involved 242 days of centrifugation and utilized 10 different Berea plug samples and 5 different high permeability plug samples taken from a producing reservoir.The linear relationship between log Pc and log &amp;lt;Sw&amp;gt; (or log Sw, as observed in previous work) was confirmed for Berea samples over the average saturation range from about 30 percent down to 10 percent. For lower average saturations, the saturation data are not sufficiently precise either to (1) demonstrate conclusively the persistence of this relationship, or (2) prove the breakdown of the Hassler boundary condition. For three of the five producing reservoir samples, it was found that two different linear segments characterized the log Pc versus log &amp;lt;Sw&amp;gt; relationship, with a rather sharp transition occurring in the 30 to 40 percent average saturation range.

Valid Capillary Pressure Data at Low Wetting-Phase Saturations

Summary Air/brine capillary pressure data obtained by three different techniques are reported as a function of saturation for several Berea core-plug samples. The capillary pressure values ranged from about 0.67 to 9.5 MPa [97 to 1, 380 psi]. The corresponding brine saturations ranged from 10 to 3% PV. The techniques used were high-speed centrifuge, porous plate, and water-vapor desorption (WVD). The results show that a plot of log Pc vs. log Sw is linear in the saturation range studied. These data are believed to be the first valid capillary pressure data reported for Berea samples in the high-pressure, low-saturation region. Also, no comparable data appear to have been published for any sedimentary rock in the permeability range above 1 md.

Detecting Fluid Movement and Isolation in Reservoir Core With Medical NMR Imaging Techniques

Summary A medical nuclear magnetic resonance (NMR) imaging instrument has been modified to image water and oil in reservoir rocks by the construction of a new receiving coil. Both oil and water inside the core produced readily detectable hydrogen proton NMR signals, while the rock matrix produced no signal. Because of similar NMR half-lives, the water was doped with a paramagnetic ion, Mn+2, to reduce its relaxation time. This procedure enhanced the separation between the oil and water phases in the resulting images. Sequential measurements, as water imbibed into one end and oil was expelled from the other end of a core plug, produced a series of images that showed the location of the fluids as a function of flow time. For water-wet Berea sandstone, a flood front was readily observed, but some of the oil apparently was left behind in small, isolated pockets that were larger than individual pores. After several additional PV's of water flowed through the plug, the NMR image indicated a homogeneous distribution of oil. The amount of residual oil determined from the ratio of NMR intensities closely approximated the residual oil saturation of fully flooded Berea samples measured by the Dean-Stark method. A Berea sandstone core treated to make it partially oil-wet did not show a definitive flood front but appeared to channel the water around the perimeter of the core plug. The relative ease with which these images were made indicates that NMR imaging can be a useful technique to follow the flow of oil and water through a core plug for a variety of production processes.

NMR imaging of fluid dynamics in reservoir core

A medical NMR imaging instrument has been modified to image water and oil in reservoir rocks by the construction of a new receiving coil. Both oil and water inside the core produced readily detectable proton NMR signals, while the rock matrix produced no signal. Because of similar T 2 NMR relaxation times, the water was doped with a paramagnetic ion, Mn+2, to reduce its T 2 relaxation time. This procedure enhanced the separation between the oil and water phases in the resulting images. Sequential measurements, as water imbibed into one end and oil was expelled from the other end of a core plug, produced a series of images which showed the dynamics of the fluids. For water-wet Berea Sandstone a flood front was readily observed, but some of the oil was apparently left behind in small, isolated pockets which were larger than individual pores. After several additional pore volumes of water flowed through the plug the NMR image indicated a homogeneous distribution of oil. The amount of residual oil, as determined from the ratio of NMR intensities, closely approximated the residual oil saturation of fully flooded Berea samples measured by Dean-Stark extraction. A Berea sandstone core treated to make it partially oil-wet, did not show a definitive flood front, but appeared to channel the water around the perimeter of the core plug. The relative ease with which these images were made indicates that NMR imaging can be a useful technique to follow the dynamics of oil and water through a core plug for a variety of production processes.

The alteration of rock properties due to interactions with drilling-fluid components

The effects of water-based drilling-fluid components on wettability and permeability have been evaluated. Most of the components tested are generally considered to be acceptable for a bland drilling mud, that is, a mud which will not alter rock properties. However, we have found that almost all of the components do alter wettability, and that some components reduce permeability significantly. Ten whole drilling fluids were also evaluated. Alteration was observed for several of these drilling fluids, although the extent of alteration was lower than observed for the individual components. The drilling fluids which led to the most alteration either lacked components needed to form a good filter cake, or contained particular especially damaging components. Both capillary pressure behavior and contact angle measurements were used to evaluate the effects of drilling fluid components on wettability. The effects of the whole drilling fluids were evaluated by free imbibition tests. The capillary pressure tests were performed on strongly water-wet Berea sandstone samples, and on Berea samples which had been treated to be oil-wet. Contact angles were measured on quartz and calcite crystals, and on asphaltene films. The bland components tested included bentonite, carboxymethylcellulose (CMC), dextrid, drispac (a polyanionic cellulose polymer), hydroxyethylcelulose (HEC), pregelatinized starch, and xanthan gum. Two components excluded from bland muds also were tested: Coat 415 (a filming amine) and lignosulfonate. All of the components considered to be bland, with the exception of bentonite filtrate, made oil-wet samples significantly less oil-wet. None of the bland components apparently affected the wettability of the water-wet samples. Coat 415 reversed the wettability of the water-wet samples, and lignosulfonate made the oil-wet samples less strongly oil-wet. CMC, starch, and dextrid were found to reduce permeability significantly. This work demonstrates that additives generally considered to be bland can, in fact, alter reservoir rock properties.