Fractured Reservoir Rocks Research Articles

A New Type of Surfactant for Enhanced Oil Recovery

abstract Most naturally fractured reservoir rocks are mixed to oil wet and do not imbibe the injected water, which translates into low-efficiency waterflood recovery. To enhance the spontaneous imbibition process, a low concentration of surfactants is dissolved into the injected water to induce wettability alteration of the reservoir rock by changing the wettability of the rock toward a more water-wet state. Zizyphus spina-christi leaves, which are grown in the Middle East, produce a special surfactant called saponin. This surfactant can be used for chemical flooding in Iranian oil fields due to its low cost and availability. Saponin was extracted from leaves using a spray-drying method and the interfacial tension (IFT) between saponin–water–oil was determined. For interfacial tension measurements the pendant drop method was used. A typical pendant drop apparatus is presented in this article. The algorithms used to infer interfacial tension from the geometrical profile of the pendant drop are described in detail; in particular, a new method for evaluation of the value of the radius at the apex of the drop, necessary for calculation of interfacial tension, is presented. Saponin caused a reduction in interfacial tension from 48 to 9 dyn/cm, which can be decreased to ultralow IFT by the addition of salt and alcohol. According to the results, saponin can be used as a surface-active agent for enhanced oil recovery.

Experimental verification of the fracture density and shear‐wave splitting relationship using synthetic silica cemented sandstones with a controlled fracture geometry

ABSTRACTWe present laboratory ultrasonic measurements of shear‐wave splitting from two synthetic silica cemented sandstones. The manufacturing process, which enabled silica cementation of quartz sand grains, was found to produce realistic sandstones of average porosity 29.7 ± 0.5% and average permeability 29.4 ± 11.3 mD. One sample was made with a regular distribution of aligned, penny‐shaped voids to simulate meso‐scale fractures in reservoir rocks, while the other was left blank. Ultrasonic shear waves were measured with a propagation direction of 90° to the coincident bedding plane and fracture normal. In the water saturated blank sample, shear‐wave splitting, the percentage velocity difference between the fast and slow shear waves, of <0.5% was measured due to the bedding planes (or layering) introduced during sample preparation. In the fractured sample, shear‐wave splitting (corrected for layering anisotropy) of 2.72 ± 0.58% for water, 2.80 ± 0.58% for air and 3.21 ± 0.58% for glycerin saturation at a net pressure of 40 MPa was measured. Analysis of X‐ray CT scan images was used to determine a fracture density of 0.0298 ± 0.077 in the fractured sample. This supports theoretical predictions that shear‐wave splitting (SWS) can be used as a good estimate for fracture density in porous rocks (i.e., SWS = 100εf, where εf is fracture density) regardless of pore fluid type, for wave propagation at 90° to the fracture normal.

Integrating seismic attributes to estimate transport properties of dual porosity reservoir rocks

The productivity of porous and fractured reservoir rocks depends heavily on the total permeability of the reservoir. Here we distinguish between matrix permeability, fracture permeability, and a ‘boundary permeability’ controlling pore fluid exchange between fractures and matrix pores. Seismic data are capable of tracking variations of the second and third types of permeability: fracture permeability is indicated by mapping fracture swarms; and boundary permeability is indicated by the dynamic properties of P-waves. To implement these capabilities, two groups of seismic attributes are proposed here. The group of attributes for mapping fracture swarms is traditional, whereas the group of attributes responding to variations of the boundary permeability has only been introduced recently. Permeability substitution modelling is done before using attributes of the second group. Application to an oil field with a tight, fractured carbonate reservoir in the Timan-Pechora province, Russia, enabled us to group the fracture-controlling faults into three categories having distinct multi-attribute patterns and diverse transport properties defined by specific combinations of fracture and boundary permeabilities.

Effects of Fracture Parameters in an Anisotropy Model on P-Wave Azimuthal Amplitude Responses

The study showed that the presence of vertically aligned fractures in reservoir rock could possibly be inferred through analysis of P-wave reflectivity variations with azimuth. The azimuthal amplitude responses measured at an interface separating overburden anisotropy and fractured rock rely on several parameters that can be decomposed into the background rock and the fracture contributions. The effect of fracture porosity on P-wave azimuthal amplitude response is small for moderate incidence angles. For fluid filled fractures P-wave anisotropy is mildly affected. For dry fractures the difference in P-wave anisotropy between low and high fracture porosities is high. This suggests that an assumption of overburden isotropy may result in a large error in predicting the fluid type and saturation.

TOUGHREACT—A simulation program for non-isothermal multiphase reactive geochemical transport in variably saturated geologic media: Applications to geothermal injectivity and CO 2 geological sequestration

TOUGHREACT is a numerical simulation program for chemically reactive non-isothermal flows of multiphase fluids in porous and fractured media. The program was written in Fortran 77 and developed by introducing reactive geochemistry into the multiphase fluid and heat flow simulator TOUGH2. A variety of subsurface thermo-physical–chemical processes are considered under a wide range of conditions of pressure, temperature, water saturation, ionic strength, and pH and Eh. Interactions between mineral assemblages and fluids can occur under local equilibrium or kinetic rates. The gas phase can be chemically active. Precipitation and dissolution reactions can change formation porosity and permeability. The program can be applied to many geologic systems and environmental problems, including geothermal systems, diagenetic, and weathering processes, subsurface waste disposal, acid mine drainage remediation, contaminant transport, and groundwater quality. Here we present two examples to illustrate applicability of the program. The first example deals with injectivity effects of mineral scaling in a fractured geothermal reservoir. A major concern in the development of hot dry rock and hot fractured rock reservoirs is achieving and maintaining adequate injectivity, while avoiding the development of preferential short-circuiting flow paths. Rock–fluid interactions and associated mineral dissolution and precipitation effects could have a major impact on the long-term performance of these reservoirs. We used recent European studies as a starting point to explore chemically induced effects of fluid circulation in the geothermal systems. We examine ways in which the chemical composition of reinjected waters can be modified to improve reservoir performance by maintaining or even enhancing injectivity. The second TOUGHREACT application example is related to CO 2 geologic sequestration in a saline aquifer. We performed numerical simulations for a commonly encountered Gulf Coast sediment under CO 2 injection conditions in order to analyze the impact of CO 2 immobilization through carbonate precipitation. Using the data presented in this paper, the CO 2 mineral-trapping capability after 10,000 years can reach 60 kg/m 3 of sandstone by secondary carbonate mineral precipitation such as siderite, ankerite, and dawsonite. Most of the simulated mineral alteration pattern is consistent with the field observations of natural CO 2 reservoirs.

Enhanced oil production in a mature field assisted by spectral attenuation analysis

Seismic attenuation analysis is used to distinguish changes in the spectral and amplitude characteristics of the seismic signal with the purpose of identifying the presence of fluids and fractures within the rock system. The analysis of such changes can be used as a tool for characterizing rock properties and for understanding the behaviour of wave propagation in a complex environment comprised by pores and cracks containing fluids. The study is carried out using high-resolution reflection data obtained from a mature fractured carbonate reservoir near the northeast coast of Mexico. Production from this reservoir is declining considerably. For this reason, a horizontal drilling programme is being considered. The results obtained from in situ measurements indicate that spectral changes and attenuation anomalies are related to the presence of hydrocarbons in the fractured reservoir rocks; however, such anomalies are also related to wave scattering in highly fractured areas. The seismic attenuation patterns associated with the productive zones have helped to identify new potential areas and horizontal drilling targets.

Hydromechanical interactions in a fractured carbonate reservoir inferred from hydraulic and mechanical measurements

Hydromechanical coupled processes in a shallow fractured carbonate reservoir rock were investigated through field experiments coupled with analytical and numerical analyses. The experiments consist of hydraulic loading/unloading of a water reservoir in which fluid flow occurs mainly inside a heterogeneous fracture network made up of vertical faults and bedding planes. Hydromechanical response of the reservoir was measured using six pressure–normal displacement sensors located on discontinuities and two surface tiltmeters. A dual hydraulic behavior was characterized for low-permeability bedding planes well connected to high-permeability faults. Displacement responses show high-variability, nonlinear changes, sometimes with high-frequency oscillations, and a large scattering of magnitudes. Initial normal stiffnesses and effective normal stresses along fault planes were estimated in the field by interpreting pressure–normal displacement relations with a nonlinear function between effective normal stress and normal displacement. Two-dimensional discontinuum modeling with transient fluid flow was performed to fit measurements during hydraulic loading tests. Results show that the hydromechanical behavior of the reservoir is restored if a high stiffness contrast is allocated between low- and high-permeability discontinuities. Thus, a dual-permeability network of discontinuities will likely also be a contrasting stiffness network, in which the deformation of major flow-conducting discontinuities is significantly influenced by the stiffness of the surrounding less-permeable discontinuities.

HYDROTHERMAL LAUMONTIZATION AND MICROFRACTURE FORMATION IN RESERVOIR ROCKS AT THE YUFUTSU FIELD, HOKKAIDO, NORTHERN JAPAN

Reservoir rocks at the Yufutsu oil‐ and gasfield (southern Hokkaido, Northern Japan) comprise Eocene conglomerates and Early Cretaceous granitoids in which networks of fractures < 0.02 mm across are widespread. These basement reservoir rocks were fractured during normal faulting in the late Oligocene — early Miocene. In the early to middle Miocene, the fractured rocks are thought to have been permeated by acidic formation waters derived from Eocene coal measures. Laumontite (a Ca‐rich zeolite) and smectite/illite (S/I) mixed‐layer clay minerals were precipitated in the microfractures and occluded them.The Yufutsu field is located on the western margin of a duplex structure formed during Pliocene or later shortening. As a result of this regional compression, the preexisting “early” microfractures which had been occluded with structurally‐weak laumontite and S/I mixed‐layer clay mineral aggregates reopened as “late” microfractures. Natural gas, which had been generated in deeply‐buried Eocene coal measures in the synclinal area to the east of Yufutsu field, migrated westwards and accumulated in the re‐fractured reservoir rocks.The duplex structure in central Hokkaido probably extends to the unexplored offshore Iburioki structure to the south. Fractured reservoir rocks similar to those at the Yufutsu field may also occur at Iburioki.

DETERMINATION OF PALAEOSTRESSES FROM MESOSCALE SHEAR FRACTURES IN CORE SAMPLES USING THE MULTI‐INVERSE METHOD

Palaeostress reconstruction is the key to quantitative characterization of fractured hydrocarbon reservoirs. In order to calculate the palaeostresses responsible for fault activity, faults in oriented core samples can be analysed and the optimal stresses can then be determined from fault‐slip data in a least‐squares sense. Many fractured reservoir rocks, however, include faults generated during a number of different tectonic phases. In these cases, the optimal stresses can be determined for subgroups of faults which are considered to be of approximately the same age. The difficulty with this is that criteria for accurate age‐dating are often absent, especially from core samples.Recently, the so‐called “multi‐inverse” method has been proposed to address this problem. This is a numerical technique for separating palaeostresses within a heterogeneous fault assemblage in the absence of a priori information on the faults’relative ages. In this paper, we apply the method to eighteen faults in two short (9m) cores from an exploration well in Hokkaido, northern Japan. The cores came from a fractured hydrocarbon reservoir and were oriented by correlation with borehole images. Core lithologies included massive Cretaceous basalts in which there was no layering which would show fault offsets; for these samples, we determined the sense of shear by studying asymmetric microstructures on the fault surfaces. The results show that the rocks have experienced six different stress regimes. In general, these are compatible with the tectonic history of the study area as inferred from the regional stratigraphy and from macroscale geological structures.These results show that the multi‐inverse method can be used to extract palaeostress data from cores, thereby providing information which will assist with the exploration of (and production from) fractured hydrocarbon reservoirs.

Hands-On Exercise in Environmental Structural Geology Using a Fracture Block Model

A scale analog model of an actual fractured rock reservoir was developed to demonstrate the relative utility of structural methods in predicting groundwater flow directions. Students performed several standard structural analyses directly on the fracture block rather than paper copies of fracture maps as in standard exercises. They predicted flow directions from these exercises. Then they performed tests to determine actual flow direction(s) by injecting dye into the water and tracking its course through the block. Comparison between the results of the structural methods and the flow tests allowed students to appreciate the complexities of fracture flow and utility of each of the methods. Because many of the graduates are employed in the environmental industry in the area, the exercise is decidedly pragmatic and kept the interest and even enthusiasm of the students throughout.

INTEGRATED FRACTURED RESERVOIR CHARACTERIZATION USING NEURAL NETWORKS AND FUZZY LOGIC: THREE CASE STUDIES

Two categories of natural fractures are generally recognized: regional orthogonal fractures and structure‐related or tectonic fractures. Over the past eight years or so, we have developed a methodology using neural networks and fuzzy logic to assist with the characterization of naturally fractured reservoir rocks. Conventional methods use only one or two geological parameters to characterize a naturally fractured reservoir. However, an integrated approach that utilizes all the information available (including lithology, thickness, state of stress and fault patterns) is required. Our approach makes use of fuzzy logic to quantify and rank the importance of each geological parameter on fracturing; a neural network is used to find the complex, non‐linear relationship between these geological parameters and the fracture index.Three case studies are described in this paper to illustrate the use of this methodology. They report respectively on a faulted limestone oil reservoir in North Africa which is deformed by fault‐related fractures; a carbonate oil reservoir in New Mexico which is characterized by fold‐related fractures; and a sandstone gas reservoir in NW New Mexico which has regional orthogonal fractures.These three case studies illustrate fracture identification and prediction using static information (i.e. image logs) and/or dynamic information (i.e. well performance) as a fracture index. The results of these studies are described as they relate to infill drilling, understanding the fractured reservoir and improved reservoir simulation.

Application of Wavelet Transforms to Reservoir-Data Analysis and Scaling

Summary General characterization of physical systems uses two aspects of data analysis methods: decomposition of empirical data to determine system parameters and reconstruction of the system attributes using these characteristic parameters. Spectral methods, involving a frequency-based representation of data, usually assume stationarity. These methods, therefore, extract only average information and, hence, are not suitable for analyzing data with isolated or deterministic discontinuities, such as faults or fractures in reservoir rocks or image edges in computer vision. Wavelet transforms provide a multiresolution framework for data representation. They are a family of basis functions that separate a function or a signal into distinct frequency packets that are localized in the time domain. Thus, wavelets are well suited for analyzing nonstationary data. In other words, a function or a discrete data set when transformed into a time-scale space using wavelets shows how it behaves at different scales of measurement. Because wavelets have compact support, it is easy to apply this transform to large data sets with minimal computations. We apply wavelet transforms to one-dimensional and twodimensional permeability data to determine the locations of layer boundaries and other discontinuities. By binning in the time-frequency plane with wavelet packets, permeability structures of arbitrary size are analyzed. Wavelets are also applied to scaling up spatially correlated heterogeneous permeability fields.

Multiazimuthal modeling and inversion ofqPreflection coefficients in fractured media

We present a method for the exact modeling and inversion of multiazimuthal qP-wave reflection coefficients at an interface separating two anisotropic media. This procedure can be used for media with at least one of its planes of symmetry parallel to the interface (i.e., monoclinic or higher symmetries). To illustrate the method, we compute qP-wave reflection coefficients at an interface separating an isotropic medium (representing a seal rock) from a transversely isotropic medium (representing a reservoir rock with vertical aligned fractures). Forward modeling shows that the difference in the offset of the critical angles for different azimuths is proportional to the fracture density: the higher the fracture density, the larger the difference. In the second part of the paper, we use a global optimization technique (genetic algorithm) to invert wide‐angle amplitude variation with offset (AVO) synthetic data. The model space consists of mass density and five elastic parameters of a transversely isotropic medium with a horizontal symmetry axis (HTI medium), which, to the first order, represents the fractured reservoir rock. For this model, we find that the configuration of three azimuths of data acquisition is the minimum number of acquisition planes needed to invert amplitude variation with offset/amplitude variation with azimuth (AVO/AVA) data. Further, there is a need for incidence angles up to 40°; a more narrow range of angles can lead to models that fit the data perfectly only up to the “maximum” incidence angle. We assume that the velocities and density of the isotropic rock are known, but use no prior information on the values of the model space parameters of the fractured rock except for reasonable velocity values in crustal rocks and constraints of elastic stability of solid media. After inversion for the model space parameters, we compute statistics of the 30 best models and likelihood functions, which provide information on the nonuniqueness and quality of the AVO/AVA inverse problem.

Estimating Average Fracture Spacing in Subsurface Rock

Knowledge of the spacing of fractures in reservoir rocks (i.e., the distance between parallel fractures in a subsurface joint set) can lead to a better understanding of the production characteristics of a reservoir and serve to quantify the relative degree of deformation in subsurface rocks. In this paper, I present a new method for estimating the spacing of subsurface fractures; this new method is easy to use from the standpoint of both data collection and data analysis. The average fracture spacing method can be applied with boreholes of any orientation relative to a fracture set. The method is especially powerful when it is used for the relatively common case of a borehole nearly parallel to a fracture set (e.g., vertical borehole intersecting vertical fractures). Average fracture spacing is estimated from an analytical solution based on observed borehole-fracture intersections and observed fracture porosity; the only data required are the dimensions of the core (or imaged borehole) and the total height of all sampled fractures. Because the likelihood of intersecting fractures increases when a well is deviated perpendicular to the fractures of a set, fracture reservoirs commonly are candidates for deviated boreholes. An informed decision on borehole deviation requires predicting the fracture intersection frequency as a function of both deviation magnitude and direction. A new method, based on probabilities of borehole-fracture intersections, uses spacing and height data from subsurface joint-like fractures and the borehole diameter to predict fracture intersection frequencies for all possible well deviations. Fracture intersection frequency solutions are presented with respect to a conventional geographic reference frame, thus simplifying even the most complex three-dimentional situations.

Pressure transient response of stochastically heterogeneous fractured reservoirs

A stochastic model for flow through inhomogeneous fractured reservoirs of double porosity, based on Barenblattet al.'s continuum approach, is presented. The fractured formation is conceptualized as an interconnected fracture network surrounding porous blocks, and amenable to the continuum approach. The block permeability is negligible in comparison to that of the fractures, and therefore the reservoir permeability is represented by the permeability of the fracture network. The fractured reservoir inhomogeneity is attributed to the fracture network, while the blocks are considered homogeneous. The mathematical model is represented by a coupled system of partial differential random equations, and a general solution for the average and for the correlation moments of the fracture pressure are obtained by the Neumann expansion (or Adomian decomposition). The solution for pressure is represented by an infinite series and an approximate solution for radial flow, is obtained by retaining the first two terms of the series. The purpose of this investigation is to get an insight on the pressure behavior in inhomogeneous fractured reservoirs and not to obtain type curves for determination of reservoir properties, which owing to the nonuniqueness of the solution, is impossible. For the present analysis we assumed an ideal reservoir with cylindrical symmetric inhomogeneity around the well. Fractured rock reservoirs being practically inhomogeneous, it is of interest to compare the pressure behavior of such reservoirs, with Warren and Roots's solution for (ideal) homogeneous reservoirs, used as a routine for determining the fractured reservoir characteristic parametersλ andΩ, using the results of well tests. The comparison of the results show that inhomogeneous and homogeneous reservoirs exhibit a similar pressure behavior. While the behavior is identical, the same drawdown or a build-up pressure curve may be fitted by different characteristic dimensionless parametersλ andΩ, when attributed to an inhomogeneous or a homogeneous reservoir. It is concluded that the ambiguity in determining the fractured reservoirλ andΩ, makes questionable the usefulness of determination of these parameters. Computations were also carried out to determine the correlation between the fracture pressure at the well and the fracture pressure at different points.

Fluid reservoir (?) beneath the KTB drillbit indicated by seismic shear‐wave observations

Indications for the possible presence of a fluid accumulation below the drillbit of the KTB (German Continental Deep Drilling Project)‐Hauptbohrung are provided by comparisons of seismic P‐wave and S‐wave reflection sections. A bright reflection with negative polarity at approx. 8 km depth is seen only on P‐wave sections. It is absent on S‐wave sections in contrast to deeper reflections. This observation can be explained by the following geological models or combinations of them: (1) brine accumulation within a strongly fractured rock reservoir, (2) liquid/gas interface within strongly fractured rocks, (3) rock composition with increased quartz content and corresponding low Poisson's ratio, and (4) varying symmetry system of seismic anisotropy due to rock foliation. Predictions concerning the nature and location of this reflector are expected to be verified by drilling and direct probing in spring‐summer, 1993.

Comparison of Sandstone Diagenesis and Reservoir Development Within Two Lower Cretaceous J Sandstone Fields, Denver Basin, Colorado: ABSTRACT

Thermal history reconstruction indicates Wattenberg field sandstones were buried deeper and were subjected to significantly higher heat flows than Kachina field sandstones. The greater burial temperature and pressure result in a higher degree of sediment compaction, fracturing of reservoir rocks, and generally more chert and polycrystalline quartz cements than Kachina field reservoir rocks.

COMPOSITE CLASSIFICATION OF FRACTURED AND BRECCIATED CARBONATE ROCKSB EXAMPLES FROM THE ORDOVICIAN ELLENBURGER GROUP, WEST TEXAS

The attention paid to rock fracturing in recent years is a result of the discovery of large volumes of hydrocarbons in fractured rock reservoirs. This regional study was conducted in order to facilitate a better understanding of the performance of fractured reservoirs, and to select the proper procedures and well intervals for artificial fracturing.Five classification schemes are proposed for fracture, breccia, porosity and permeability developments, as revealed by mega‐ and microscopic examination of cores, thin‐sections and outcrop samples. A composite classification combines the attributes of the other schemes in an attempt to predict residual porosity and permeability on a reservoir scale. Various genetic types of breccia were encountered in this study, but those of tectonic origin predominate and control hydrocarbon production.At the initial time of fracturing, porosities range from low in crackle breccia, to very high in random and pheno‐breccias. With moderate cementation, random and pheno‐breccias remain the most porous and permeable structures, However, with a high degree of cementation, porosity and permeability become negligible in crackle breccia, and very low or absent in pheno‐breccia. The degree of cementation which controls residual porosity depends on the availability of mineral‐laden solutions.

Hydrocarbon Generation as a Mechanism for Overpressuring in Rocky Mountain Region

Overpressured reservoirs are present in the deeper parts of most basins in the Rocky Mountain region. A variety of conditions can cause overpressuring. However, most high pressures in the region are caused by present-day or recently active oil and gas generation or generation in the last few million years in low-permeability rock successions that still contain organic matter capable of yielding thermally generated hydrocarbons. Rocks with above-normal pressure range from Devonian to Tertiary, and commonly are associated with low-permeability (tight) reservoirs. Most of the overpressuring occurs in Cretaceous and Tertiary rocks. Overpressuring in rocks older than Cretaceous is rare and where present only occurs in strata with very rich hydrocarbon source beds such as the D vonian-Mississippian Bakken Formation. Most organically lean pre-Cretaceous source beds are no longer capable of yielding enough hydrocarbons to maintain abnormal pressure. Nearly all overpressured reservoirs and source rocks have temperatures of approximately 200°F (93°C) or higher. In addition, available data indicate that hydrocarbon-related overpressuring does not generally occur if vitrinite reflectance (Ro) values are less than 0.6% in oil-prone strata or less than 0.7% in gas-prone strata. Overpressured gas-bearing strata generally have Ro values of 0.8% or higher. Maximum reservoir pressures are about equal to the fracture gradient pressure in the reservoir rocks. Some vertical fractures in reservoir rocks are probably caused by rapid expulsion of hydrocarbons from the source beds. High pressures in the Rocky Mountain region means that the rock succession is gas or oil saturated, and discrete hydrocarbon-water contacts are generally not present. Classical concepts of hydrodynamics do not appear to be applicable to these overpressured successions. The optimum depths for exploration are generally the upper 1,000-2,000 ft (305-610 m) of the overpressured succession.

Documenting Porosity Stress Sensitivity in Conventional and Fractured Reservoir Rocks: ABSTRACT

Most geologists and engineers are now aware of the large differences in core analysis measurements performed at bench and overburden conditions. The magnitude of change observed in these measurements is highly variable not only for different rock types, but also for similar lithologies within a single cored interval. Several rock fabric physical properties contribute to the variable stress sensitivity of reservoir rocks; however, the authors believe that the effects of coring, core recovery operations, natural dilation and/or contraction of the rock fabric, and preservation procedures are primarily responsible for increased porosity and permeability at bench conditions. Measurements of pore system parameters in fractured and conventional reservoirs can be achieved using new petrographic methods and special core testing techniques. Fluorescent epoxy impregnations of core samples performed under bench and simulated in-situ conditions of effective stress offer the ability to observe fracture and intergranular porosity at surface and reservoir conditions. Fluorescent microscopy, computer image analysis, and special core permeability testing are combined to document the variation of stress sensitivity within several different reservoir rock types.