Typical Reservoir Rock Research Articles

Petrophysical parameters inversion for heavy oil reservoir based on a laboratory-calibrated frequency-variant rock-physics model

Heavy oil has high density and viscosity, and exhibits viscoelasticity. Gassmann's theory is not suitable for materials saturated with viscoelastic fluids. Directly applying such model leads to unreliable results for seismic inversion of heavy oil reservoir. To describe the viscoelastic behavior of heavy oil, we modeled the elastic properties of heavy oil with varying viscosity and frequency using the Cole-Cole-Maxwell (CCM) model. Then, we used a CCoherent Potential Approximation (CPA) instead of the Gassmann equations to account for the fluid effect, by extending the single-phase fluid condition to two-phase fluid (heavy oil and water) condition, so that partial saturation of heavy oil can be considered. This rock physics model establishes the relationship between the elastic modulus of reservoir rock and viscosity, frequency and saturation. The viscosity of the heavy oil and the elastic moduli and porosity of typical reservoir rock samples were measured in laboratory, which were used for calibration of the rock physics model. The well-calibrated frequency-variant CPA model was applied to the prediction of the P- and S-wave velocities in the seismic frequency range (1–100 Hz) and the inversion of petrophysical parameters for a heavy oil reservoir. The pre-stack inversion results of elastic parameters are improved compared with those results using the CPA model in the sonic logging frequency (∼10 kHz), or conventional rock physics model such as the Xu-Payne model. In addition, the inversion of the porosity of the reservoir was conducted with the simulated annealing method, and the result fits reasonably well with the logging curve and depicts the location of the heavy oil reservoir on the time slice. The application of the laboratory-calibrated CPA model provides better results with the velocity dispersion correction, suggesting the important role of accurate frequency dependent rock physics models in the seismic prediction of heavy oil reservoirs.

Laboratory experiments on the effects of corrosion inhibitor on the mechanical properties of reservoir rock

Geothermal energy production often involves use of corrosion inhibitors. We performed rock mechanical experiments (room temperature; confining pressure of 10/20/30 MPa) on typical reservoir rocks (Bentheim sandstone and Treuchtlinger limestone) in contact with two different inhibitor solutions or with demineralized water. The sandstone experiments show no discernible difference in rock strength between inhibitors or water, attributed to low quartz reactivity. The limestone experiments show a significant difference in rock strength (and Mohr–Coulomb envelope), dependent on inhibitor type, attributed to high carbonate reactivity. This implies that, depending on the reactivity of the rocks and local stress conditions, inhibitor leakage may lead to unpredicted reservoir failure.

Effect of specimen size and shape on the mechanical properties measured on plugs subsampled from sidewall cores

For several disciplines, the increasing acquisition of rotary sidewall cores (RSWC) in the oil and gas industry gives the opportunity for more extensive experimental rock characterization but, on the other hand, the limited amount of recovered material, their shape and orientation are not optimal for geomechanical experiments in the triaxial cell. These drawbacks can be overcome by performing experiments on properly shaped and oriented small diameter plugs subsampled from the RSWCs. These plugs are smaller than conventional ones, so the effects of both specimen shape (i.e., length over diameter L/D ratio) and size (i.e., diameter) on strength, stiffness (i.e., Young’s modulus), and dilation (i.e., Poisson’s ratio) must be carefully considered. In this work, an experimental study on specimen shape and size effects on rock mechanical properties has been tailored to materials and testing conditions generally encountered in petroleum related geomechanics. Triaxial compression experiments at three confining pressures have been performed on outcrop analogues of typical reservoir rock lithologies, i.e., two sandstones and two limestones, and within a range of shapes and sizes relevant for specimens prepared from RSWCs with emphasis on 10 mm diameter specimens. The strength, stiffness and dilation results were analysed and compared with relevant data and relations available in the literature. Then, analytical equations, useful for the practice of geomechanical experimental studies on RSWCs, have been derived to correlate mechanical properties measured on specimens of any shape or size to the ones obtainable on reference specimens.

An experimental study of ultra-high pressure water jet-induced fracture mechanisms and pore size evolution in reservoir rocks

Ultra-high pressure water jets (UHP-WJ) rock breaking is a promising technology for developing unconventional natural gas reserves . In this study, rock-breaking experiments were conducted using typical reservoir rock samples such as sandstone , shale, and coal. The failure patterns in rocks after impact by UHP-WJ were analyzed. Moreover, the 3D damage field model of the rock was reconstructed based on CT scanning, and the internal crack distribution was visualized and examined. Furthermore, the fracture mechanisms of three types of reservoir rocks under the UHP-WJ impingement were studied. The results indicate that intergranular fractures produced due to shear stress are the dominant type of fracture in sandstones, tensile failure due to stress wave was the main type of fracture observed in shale, and coal exhibited the double breaking characteristics of stress wave effect and water wedge effect. The fragments size distribution of samples shows the largest fragments in shale, followed by coal, and the smallest fragments are observed in sandstone. Finally, the evolution of rock pore structure before and after the impact of UHP-WJ was monitored by nuclear magnetic resonance (NMR) methods. The results reveal that the micropores transform into mesopores and macropores in the sandstone, where the total porosity increased by 14.3%–24.8%. As the jet pressure exceeds 100 MPa, the porosity of shale increases significantly, such that the total porosity of the shale sample increased by 7.6%–37.1%. The mesopores transform into macropores and fractures with the influence of the water wedge effect in coal samples, resulting in the reduction of mesopores and the increase of macropores, where the total porosity of the coal sample increased by 14.6%–40%. The complexity and heterogeneity of pores were reduced under UHP-WJ with the increasing jet pressure. The findings provide a theoretical reference for optimizing the recovery from unconventional natural gas reservoirs .

A Technology of Hydrocarbon Fluid Production Intensification by Productive Stratum Drainage Zone Reaming

The paper proposes a new technology for fluid production intensification, in particular hydrocarbons, which is implemented via significant increasing of the local wellbore diameter in the interval, where the productive stratum is present. The proposed technology improves the well productivity by increasing the filtration surface area and opening new channels for filtering fluids into the well. The innovative, technical idea is to drill large diameter circular recesses in planes perpendicular to the well axis. After that, the rock mass located between the circular recesses are destroyed by applying static or dynamic axial loads. The required value of the axial force is provided by the weight of the standard drilling tool. As a result of the study, the analytical relations to specify the admissible radius of circular recesses and admissible thickness of rock mass between two adjacent circular recesses from the condition of safe operation are obtained. The numerical analysis carried out for typical reservoir rocks substantiated the possibility of well diameter local reaming twenty times. A special tool for circular recess drilling is developed and the principle of its operation is described. The advantage of the proposed approaches is the low energy consumption for well diameter reaming. Our technology will have special economic expediency for the intensification of production from hydrodynamically imperfect wells and under the condition of fluid filtration according to the expressed nonlinear law.

Model-based pore-pressure prediction in shales: An example from the Gulf of Mexico, North America

Accurate pore-pressure interpretation and prediction play important roles in understanding the sedimentary history of a basin and in reducing drilling hazards during hydrocarbon exploitation. Unlike typical reservoir rocks, in which pore pressures can be directly measured, pore pressures in shale must be inferred via their state of compaction. We have used the shale acoustic properties to accomplish this. Shale P- and S-wave velocities were first calculated using an anisotropic differential effective medium model. This model was built using elastic properties of wet clay mineralogy, and the total porosity of the shale was obtained from basic open-hole well-log measurements. These simulated shale velocities were systematically higher than sonic velocities observed on a test data set from a Gulf of Mexico well, penetrating a 1200 m vertical section of overpressured shale. The difference between the modeled velocities and the sonic measurements was then evaluated to estimate the abnormal pore pressure based on an exponential relationship between the pore pressure and the ratio of measured to modeled velocity. Using a reasonable exponent, the predicted pore pressure was shown to be in good agreement with direct pore-pressure measurements either made in adjacent sand layers that are thought to be in pressure equilibrium with the shales or inferred from drilling mud weights.

A unified permeability and effective stress relationship for porous and fractured reservoir rocks

As one of the most important parameters for estimating oil/gas production rate, permeability is sensitive to effective stress which may change significantly with reservoir depletion. Although vast amount of data on permeability–stress correlations have been reported, many of them were proposed based on different situations. This makes it difficult to compare the modeling results of the experimental data and limits the adaption of the findings from one set of testing permeability data to other situations. A unified permeability and effective stress relationship would make it possible to evaluate the permeability behavior under different situations. Recently, the validity of an exponential form permeability correlation to any types of fractured rocks has been confirmed by some of the authors in this paper. In this study, the exponential form model is further extended to describe the permeability change for porous media through theoretical derivation. The unified permeability relationship is then applied to represent the permeability data for a large amount of samples from three typical reservoir rocks, including porous sandstone, idealized fractured coal and randomly fractured shale. The results show that the unified relationship is capable of describing permeability data for both porous and fractured rocks. The distributions of the model parameters are also obtained. This unified relationship provides a benchmark to evaluate the permeability behaviors in different rocks and the modeling results form a practical database for permeability in typical reservoir rocks. The outcome of this work would contribute to many circumstances including interpreting permeability data and making comparison, estimating permeability, coupling into existing reservoir simulators for fluid flow modeling and so on.

Effect of sub‐core scale heterogeneities on acoustic and electrical properties of a reservoir rock: a CO2 flooding experiment of brine saturated sandstone in a computed tomography scanner

ABSTRACTThe effect of sub‐core scale heterogeneity on fluid distribution pattern, and the electrical and acoustic properties of a typical reservoir rock was studied by performing drainage and imbibition flooding tests with CO2 and brine in a laboratory. Moderately layered Rothbach sandstone was used as a test specimen. Two core samples were drilled; one perpendicular and the other parallel to the layering to allow injection of fluids along and normal to the bedding plane. During the test 3D images of fluid distribution and saturation levels were mapped by an industrial X‐ray CT‐scanner together with simultaneous measurement of electrical resistivity, ultrasonic velocities as well as amplitudes.The results showed how the layering and the flooding direction influenced the fluid distribution pattern and the saturation level of the fluids. For a given fluid saturation level, the measured changes in the acoustic and electrical parameters were affected by both the fluid distribution pattern and the layering orientation relative to the measurement direction. The P‐wave amplitude and the electrical resistivity were more sensitive to small changes in the fluid distribution patterns than the P‐wave velocity. The change in amplitude was the most affected by the orientation of the layering and the resulting fluid distribution patterns. In some instances the change due to the fluid distribution pattern was higher than the variation caused by the change in CO2 saturation. As a result the Gassmann relation based on ‘uniform' or ‘patchy' saturation pattern was not suitable to predict the P‐wave velocity variation. Overall, the results demonstrate the importance of core‐imaging to improve our understanding of fluid distribution patterns and the associated effects on measured rock‐physics properties.

Influence of CO2 on rock physics properties in typical reservoir rock: A CO2 flooding experiment of brine saturated sandstone in a CT-scanner

Abstract Laboratory core flooding experiment was run to investigate the joint use of electrical resistivity, ultrasonic velocities and 3D images of fluid distribution to improve current understanding of CO2 and brine behaviour during drainage and imbibition in reservoir rocks. The test specimen was cylindrical Rothbach sandstone measuring 100 mm in length and 38 mm in diameter, with a porosity of 23% and an average permeability of 400 mD. The brine saturated specimen was drained by injecting CO2 and later imbibed with brine while monitoring changes in resistivity and ultrasonic velocity measurements. Actual fluid saturation level and distribution have been mapped simultaneously using X-ray CT scan. CO2 saturation calculations based on CT values showed a steep saturation gradient at start of drainage and the gradient flattened with more CO2 injected into the sample. The ultrasonic compressional velocity (V p) measurements depicted a continuous decrease with increase in CO2 saturation while the resistivity of the sample increased proportionally with increase in CO2 saturation. A CO2 saturation of 53% was achieved at the end of drainage after injection of 20 pore volume (PV) CO2. This resulted in a decrease of V pby 7.2% while the amplitude decreased by as much as 48%. At the end of drainage, the resistivity of the sample increased to 13.9 Ω-m from full brine saturated value of 3.2 Ω-m. During imbibition, the sample was re-saturated close to 100% after 10 PV brine injection. Change in V p due to CO2 saturation level variation was relatively consistent during drainage and imbibition (no hysteresis) where as the resistivity of the sample was more affected by the flooding history resulting in hysteretic variation in resistivity. Resistivity index (RI) values did not show a consistent pattern and a single Archie’s saturation exponent (n) could not be assigned.

The acoustic signature of fluid flow in complex porous media

Effective medium approximations for the frequency-dependent and complex-valued effective stiffness tensors of cracked/porous rocks with multiple solid constituents are developed on the basis of the T-matrix approach (based on integral equation methods for quasi-static composites), the elastic–viscoelastic correspondence principle, and a unified treatment of the local and global flow mechanisms, which is consistent with the principle of fluid mass conservation. The main advantage of using the T-matrix approach, rather than the first-order approach of Eshelby or the second-order approach of Hudson, is that it produces physically plausible results even when the volume concentrations of inclusions or cavities are no longer small. The new formulae, which operates with an arbitrary homogeneous (anisotropic) reference medium and contains terms of all order in the volume concentrations of solid particles and communicating cavities, take explicitly account of inclusion shape and spatial distribution independently. We show analytically that an expansion of the T-matrix formulae to first order in the volume concentration of cavities (in agreement with the dilute estimate of Eshelby) has the correct dependence on the properties of the saturating fluid, in the sense that it is consistent with the Brown–Korringa relation, when the frequency is sufficiently low. We present numerical results for the (anisotropic) effective viscoelastic properties of a cracked permeable medium with finite storage porosity, indicating that the complete T-matrix formulae (including the higher-order terms) are generally consistent with the Brown–Korringa relation, at least if we assume the spatial distribution of cavities to be the same for all cavity pairs. We have found an efficient way to treat statistical correlations in the shapes and orientations of the communicating cavities, and also obtained a reasonable match between theoretical predictions (based on a dual porosity model for quartz–clay mixtures, involving relatively flat clay-related pores and more rounded quartz-related pores) and laboratory results for the ultrasonic velocity and attenuation spectra of a suite of typical reservoir rocks.

Relationship of biomarker distribution to depositional environment: Phosphoria Formation, Montana, U.S.A.

From biomarker distributions it is possible to distinguish extracts from four different members/facies (Meade Peak, Rex, Retort, and Tosi) of the Permian Phosphoria Formation at Little Sheep Creek, Montana. These distributions relfect changes in floral and faunal distribution in response to a changing depositional environment and suggest that the Retort and Tosi Members (the second cycle of deposition) were deposited under more anoxic conditions and at higher salinity than Meade Peak and Rex Members (the first cycle). Correlations between biomarker indicators of anoxia and salinity suggest that anoxia was in part the result of a chemocline separating normal marine waters above from more saline bottom waters. Anoxia and salinity in the bottom waters increased with time making conditions in the basin progressively more hostile to benthic organisms. Development of extreme environmental conditions in continental shelf habitats (such as those suggested by biomarker parameters at Little Sheep Creek) may have compounded spatial problems created by continental suturing suggested to be a cause of Permian extinctions. Factor analysis indicates that four factors for 75.3% of the variance in biomarker ratios. These factors are suggested to be source organisms (types of eukaryotic plankton), salinity, Eh, and mineralogy. The Grandeur Member of the Phosphoria, which is a typical reservoir rock for Phosphoria derived oils, yields an extract containing a novel C 30 nitrogen-containing steroid. This unique steroid is not abundant in any other known extracts or oils, which along with the extremely low Porphyrin Maturity Parameter of all the extracts (PMP < 0.01), confirms the absence of migrated oils in the Phosphoria at Little Sheep Creek. The biomarker ratios C 29 αββ/( gaββ + αααa steranes; Ts/(Ts + Tm); triaromatic/(triaromatic + monoaromatic) steroids; short/(long + short chain) monoaromatic steroids; and short/(long + short chain) triaromatic steroids are commonly used to determine the thermal maturity of oils and source rock extracts. However, these ratios show considerable variation in core extracts of the same thermal maturity from different facies. In contrast, the thermal maturity parameters, C 29 ααα 20 S/(20 S + 20 R) steranes and Porphyrin Maturity Parameter (PMP) show little variation, indicating that these parameters are less affected by changes in depositional environment and may be most useful for thermal maturation determinations of Phosphoria related oils and source rocks. This study supports previous work suggesting environmental effects must be considered if correct determination of thermal maturity of an oil or extract is to be made. This is especially true of oils and extracts from source rocks with high sulfur concentrations and/or those deposited at elevated salinities.

Discussion of the Use of Capillary Tube Networks in Reservoir Performance Studies

Abstract The paper is presented as a discussion of the work of Simon and Kelsey on the use of capillary tube networks in reservoir performance studies. The author believes that calculation of oil recovery by the method outlined by Simon and Kelsey will give predictions that are too optimistic for reservoir-scale predictions that are too optimistic for reservoir-scale flooding processes, particularly when the mobility ratio is unfavorable. The reason for this is that the networks are too small to permit proper scaling of longitudinal and transverse dispersion effects. Hence, as early a breakthrough as will occur with fully developed viscous fingers is not observed. Introduction It appears to us that calculation of oil recovery by the method outlined by Simon and Kelsey will give predictions which are much too optimistic for reservoir-scale flooding processes, particularly when the mobility ratio is unfavorable. We believe that the principal reason for this is that the Simon-Kelsey networks are too small to permit proper scaling of longitudinal and transverse proper scaling of longitudinal and transverse dispersion effects. Hence, the authors do not observe as early a breakthrough as will occur with fully developed viscous fingers. Since the authors oil recovery predictions are too optimistic for any given degree of heterogeneity, but decrease with increasing heterogeneity, Simon and Kelsey have attributed too great a degree of heterogeneity to some of the laboratory models involved in previously reported work in attempting to match the observed recovery data. Data derived from the models themselves indicate a much lesser degree of heterogeneity. MODELLING OF PORE STRUCTURE AND THE H FACTOR The mathematical model of reservoir displacement processes described by Simon and Kelsey is related processes described by Simon and Kelsey is related to the capillary network model of pore structure devised by Fatt. However, Fatt intended his model to describe the capillary pressure and relative permeability properties of small samples of reservoir rock, rather than large-scale oil reservoirs. Fatt emphasized the relationship between the form of the network as expressed by his connectivity number, 8, and the degree of similarity of the capillary pressure and relative permeability curves for his model to those of typical reservoir rocks. Fatt found that similarity required a value of 8 in the interval from 7 to 25. This is the average number of other tubes connected to the two ends of a given tube. It means that from 4 to 13 flow channels meet at each junction, on the average. For this reason, Fatt favored the use of a triple hexagonal network (B = 10) in which six tubes meet at each junction. This judgment of natural rock pore structure is supported by more recent scanning electron microscope studies. Simon and Kelsey used the double hexagonal network (B = 7) in part of the work reported in Ref. 1; but the remainder and the second article are based on a diamond grid (B = 6). Fact also found that a reciprocal relationship between tube radius and tube length was required to simulate actual rock permeability-porosity relationships. Simon and Kelsey permeability-porosity relationships. Simon and Kelsey have instead used tubes of constant length. A wide distribution of cube radii was found by Fatt to be necessary to simulate the capillary pressure curves of consolidated porous media. Pore radius distributions are typically log-normal, and the distributions used by Fatt were of this shape. They are not flat-topped distributions such as that used by Simon and Kelsey to define a heterogeneity factor, H, as the ratio of the maximum to the minimum channel radius. However, it is easy to derive for such a flat-topped distribution that the fractional average deviation for a total number of flow channels, N, is given by the following equations: ............(1a) ............(1b) SPEJ P. 352

Effect of Saturation on Mobility of Low Liquid-Vapor Ratio Fluids

Abstract Laboratory research has been conducted to evaluate the characteristic effects of condensate saturation on the mobility of gas in typical reservoir rocks. A pump with two pistons provided phases in equilibrium at controlled flow rates and constant liquid-vapor volume ratios. Core samples were tested in a holder that permitted sealing steady-state phases in the pore spaces under flow test pressures for weighing with sufficient precision to give an accurate measure of the attained saturations. Parameters of the study were pressure, apparent velocity, flowing liquid-vapor volume ratio, fluid composition, core material and length-to-diameter ratio. Tests were conducted at 515 and 1,515 psia to determine the effect of pressure on the mobility-saturation relationship. Influence of the apparent velocities 0.30, 0.15 and 0.07 cm/ sec and of five liquid-vapor volume ratios from 0.0001 to 0.01 was determined at 515 psia. The principal fluid system was nitrogen and and separator liquid from a Gulf Coast condensate, but the effect of a condensate of different viscosity was also determined. The significance of a possible concentration of liquid near the outlet end of the test cores was investigated. Core materials included a consolidated sandstone and a low-permeability limes tone. Relative mobility and liquid-vapor volume ratio relationships are concluded to be dependent on pressure, saturation and, to a lesser extent, on velocity. For each porous medium and fluid there is a minimum saturation essential to two-phase flow, and high velocities of flow have only limited effect on saturations in this range. INTRODUCTION It is now recognized that knowledge of the availability of a reservoir gas - the period that gas may be recovered from a reservoir at a given rate - is as important as the estimate of gas in place. When reservoir conditions are such that pressure decline owing to production will result in retrograde condensation, liquid saturation can increase in the structure around the production well in a way that may restrict flow capacity, and hence future availability.1 Based on a numerical solution of transient radial flow of single-phase gas-condensate fluids,2 a program for computing the accumulation of condensate in a reservoir and the effect of this condensate on deliverability has been developed.3 During this development a need evolved for data that described the influence of pressure, velocity of flow and condensed liquid on mobility as recovery progressed. This paper presents the results of experimental investigation to obtain insight into the mobility relationship at reservoir pressures of gas-condensate fluids. A core holder for flow tests at reservoir pressure was developed to weigh the core and its fluid contents under pressure to determine saturation. A specially constructed pump was used to drive a two-phase fluid through the core until a steady state prevailed. The core was used as a differential device, and properties measured were intensive rather than extensive. APPARATUS Fig. 1 shows a schematic representation of the major pieces of equipment used in the mobility determination. The weighable core holder is connected to a two-piston, constant-displacement pump. Attainment of steady-state flow is indicated by stability of the flow differential read from the high-pressure manometer. WEIGHABLE CORE HOLDER An important part of the data needed was the mobility-saturation relationship. This required that mobilities and saturations be measured at pressures, flow velocities and liquid-vapor volume ratios characteristic of condensate reservoirs. WEIGHABLE CORE HOLDER An important part of the data needed was the mobility-saturation relationship. This required that mobilities and saturations be measured at pressures, flow velocities and liquid-vapor volume ratios characteristic of condensate reservoirs.