Permeability Of Fault Rocks Research Articles

Non-Darcy flow and stress coupling mechanism of fault rocks: Effect of gas compression

This study aimed to analyze the evolution of the porosity and permeability of fault rocks under non-Darcy flow-stress coupling. The permeability of broken coal, mudstone, and sandstone with different particle size gradations under different stresses was investigated using an experimental system for the permeability evolution of broken rocks. Experimental results show that broken coal exhibits the best compressibility, followed by broken mudstone, and broken sandstone presents the worst compressibility. The porosity and permeability of the broken rocks decrease rapidly with the increase in confining pressure and then decrease slowly until they stabilize. The crushing of large particles into fine particles under stress is the main reason behind the decreasing porosity and permeability of mixed broken rocks. The smaller the fractal dimension of the particle size gradation during loading, the more serious the particle breakage, the greater the mass loss of large particles, and the greater the decrease in porosity and permeability.

Permeability of carbonate fault rocks: a case study from Malta

The inherent heterogeneity of carbonate rocks suggests that carbonate-hosted fault zones are also likely to be heterogeneous. Coupled with a lack of host–fault petrophysical relationships, this makes the hydraulic behaviour of carbonate-hosted fault zones difficult to predict. Here we investigate the link between host rock and fault rock porosity, permeability and texture, by presenting data from series of host rock, damage zone and fault rock samples from normally faulted, shallowly buried limestones from Malta. Core plug X-ray tomography indicates that texturally heterogeneous host rocks lead to greater variability in the porosity and permeability of fault rocks. Fault rocks derived from moderate- to high-porosity (>20%) formations experience permeability reductions of up to six orders of magnitude relative to the host; >30% of these fault rocks could act as baffles or barriers to fluid flow over production timescales. Fault rocks derived from lower-porosity (<20%) algal packstones have permeabilities that are lower than their hosts by up to three orders of magnitude, which is unlikely to impact fluid flow on production timescales. The variability of fault rock permeability is controlled by a number of factors, including the initial host rock texture and porosity, the magnitude of strain localization, and the extent of post-deformation diagenetic alteration. Fault displacement has no obvious control over fault rock permeability. The results enable better predictions of fault rock permeability in similar lithotypes and tectonic regimes. This may enable predictions of across-fault fluid flow potential when combined with data on fault zone architecture.

Permeability of fault rocks in siliciclastic reservoirs: Recent advances

It is common practice to create geologically realistic production simulation models of fault compartmentalized reservoirs. Data on fault rock properties are required, to calculate transmissibility multipliers that are incorporated into these models, to take into account the impact of fault rocks on fluid flow. Industry has generated large databases of fault rock permeability, which are commonly used for this purpose. Much of the permeability data were collected using two inappropriate laboratory practices with measurements being made at low confining pressure with distilled water as the permeant. New fault rock permeability measurements have been made at high confining pressures using formation compatible brines as the permeant. Fault permeability decreases by an average of five fold as net confining pressure is increased from that used in previous measurements (i.e. ∼70 psi) to that approaching in situ conditions (i.e. 5000 psi). On the other hand, permeability increases by around the same amount if reservoir brine is used as the permeant instead of distilled water. So overall, these two inappropriate laboratory practices used in previous studies cancel each other out meaning that legacy fault rock property data may still have value for modelling cross-fault flow in petroleum reservoirs.A poor correlation exists between clay content and fault rock permeability, which is easily explained by the application of a simple clay-sand mixing model. This emphasises the need to gather fault permeability data directly from the reservoir of interest. The cost of such studies could be significantly reduced by screening core samples using a CT scanner so that only samples that are likely to impact fluid flow are analyzed in detail. The stress dependence of fault permeability identified in this study is likely to be primarily caused by damage generated during or following coring. So it is probably not necessary to take into account the impact of stress on fault permeability in simulation models unless the faults of interest are likely to reach failure and reactivate.

Dynamic Fault-Seal Breakdown - Investigation in the North Sea Egret Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170584, “Dynamic Fault-Seal-Breakdown Investigation - A Study of Egret Field in the North Sea,” by P.P. Obeahon, SPE, G. Ypma, and O.U. Onyeagoro, SPE, Shell, and A.C. Gringarten, SPE, Imperial College London, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. The ability to predict the effect of faults on locating remaining hydrocarbon is critical to optimal well-placement, reservoir-management, and field development decisions. The tools and techniques available for realistic differentiation between sealing and nonsealing faults have presented a great challenge to the industry. This paper discusses the results of an integrated study that incorporated detailed geology and reservoir engineering to understand production behavior of a complexly faulted high-pressure/high-temperature field in the North Sea. Introduction Predicting fault-seal breakdown is a challenging task because it involves many interrelated factors and complex relationships. Knowledge of these factors is both nonunique and subjective. Most faulting processes have been studied in isolation, and the relationships among many of the processes are understood poorly. Reservoir depletion can, in principle, induce stress paths capable of reactivating intrareservoir faults and, hence, potentially cause breakdown of their sealing integrity. Fault-seal breakdown may also be invoked falsely where oil/ water contacts change across a fault (i.e., the fault is a capillary seal) but the fault does not compartmentalize pressures in production. This apparent seal failure can arise because of pressure communication in the water leg below the oil column. It is not clear why pressure depletion should cause capillary-seal failure. However, publications exist that attempt to attribute production behavior observed in fields to fault-seal breakdown in a production realm, because of pressure depletion on one side of a fault. The first attempts to incorporate geologically reasonable fault properties into production-simulation models involved the calculation of transmissibility multiplier on the basis of absolute permeability and thickness of fault rocks. These calculations do not capture the multiphase behaviors of fault rocks. A key problem with this approach is that a huge number of pseudofunctions needs to be calculated to take into account the large variation in fault properties (e.g., thickness, absolute permeability) and flow rates and whether the fault is going through drainage or imbibition during production. The second attempt involved calculating transmissibility multipliers (also known as seal factors) on the basis of fault permeability. The key problem with this approach is that fault permeability depends on shale gouge ratio and fault displacement alone. The calculation does not capture the impact of reservoir permeability on fault permeability.

Microstructures Induced in Porous Limestone by Dynamic Loading, and Fracture Healing: An Experimental Approach

Fracturing and healing are crucial processes inducing changes in the permeability and mechanical behavior of fault zones. Fracturing increases the permeability of fault rocks, creating flow-channels for fluid circulation and enhancing the kinetics of such fluid–rock processes as pressure solution or metamorphism. Conversely, healing processes reduce permeability by closing the fractures and lead to rock strengthening. Consequently, the timescales of these two processes are important in determining the strength of fault zones and their ability to rupture during earthquakes. This article reports observations of the microstructure of porous limestone samples subjected to rapid dynamic loading, and long-term healing as a result of fluid percolation. Dynamic loading was performed by impacting the samples with steel bars inside a split Hopkinson pressure bar apparatus. Healing was performed by leaving the samples for three months within a triaxial machine with percolation of supersaturated fluids for five weeks. Two kinds of fracture network were observed in samples damaged at high strain rate: a series of radial and circular macrofractures and an incipient pulverization zone at the center of the sample loaded at the highest strain rate. Fracture density determined microscopically from X-ray images correlates with dissipated energy computed from macro-mechanical data. X-ray images enable good quantification of the damaged state of the samples. Percolation experiments under stress with high-solubility fluid at room temperature show that the main healing processes promoting closure of the fractures in the sample are a combination of mechanical and chemical compaction. Microfracturing networks were found to heal faster than the largest fractures, leading to heterogeneous strengthening of the rock. This feature affects the processes of earthquake nucleation and rupture propagation.

Experimental studies on gas and water permeability of fault rocks from the rupture of the 2008 Wenchuan earthquake, China

The permeabilities of fault rocks from the rupture of Wenchuan earthquake were measured by using nitrogen gas and distilled water as pore fluids under the confining pressure ranging from 20 to 180 MPa at room temperature. Experimental results indicate that both gas and water permeabilities decrease with increasing confining pressure, described by power law relationship, i.e., b = 0.2×10−3kl−0.557. The water permeability is about one order less than gas permeability and also half order smaller than the permeability corrected by the Klinkenberg effect, so-called intrinsic permeability. The differences in the permeabilies imply that the reduction of effective pore size caused by the adhesion of water molecules to clay particle surface and water-swelling of expandable clay minerals contributes to lessening the water permeability besides the Klinkenberg effect. Hence, the liquid permeability of fault rocks cannot be deduced by gas permeability by the Klinkenberg correction reliably and accurately, and it is necessary to use liquid as pore media to measure their transport property directly.

Laboratory measurements of the relative permeability of cataclastic fault rocks: An important consideration for production simulation modelling

It is becoming increasingly common practice to model the impact of faults on fluid flow within petroleum reservoirs by applying transmissibility multipliers, calculated from the single-phase permeability of fault rocks, to the grid-blocks adjacent to faults in production simulations. The multi-phase flow properties (e.g. relative permeability and capillary pressure) of fault rocks are not considered because special core analysis has never previously been conducted on fault rock samples. Here, we partially fill this knowledge gap by presenting data from the first experiments that have measured the gas relative permeability ( k rg ) of cataclastic fault rocks. The cataclastic faults were collected from an outcrop of Permo-Triassic sandstone in the Moray Firth, Scotland; the fault rocks are similar to those found within Rotliegend gas reservoirs in the UK southern North Sea. The relative permeability measurements were made using a gas pulse-decay technique on samples whose water saturation was varied using vapour chambers. The measurements indicate that if the same fault rocks were present in gas reservoirs from the southern Permian Basin they would have k rg values of <0.02. Failure to take into account relative permeability effects could therefore lead to an overestimation of the transmissibility of faults within gas reservoirs by several orders of magnitude. Incorporation of these new results into a simplified production simulation model can explain the pressure evolution from a compartmentalised Rotliegend gas reservoir from the southern North Sea, offshore Netherlands, which could not easily be explained using only single-phase permeability data from fault rocks.

Permeability of fault rocks from the Median Tectonic Line in Ohshika-mura, Nagano, Japan as studied by pressure-cycling tests

Abstract We describe laboratory measurements of the permeability of fault rocks and their host protoliths obtained from the Median Tectonic Line (MTL), the largest strike-slip fault in Japan. The measurements are made using a gas-medium apparatus that simulates in situ conditions. Samples of fault gouge, cataclastic mylonite, and protoliths were collected from the Kitagawa and Ankoh outcrops of the MTL and adjacent areas in Ohshika-mura, Nagano Prefecture, central Japan. Permeabilities of these samples were measured at room temperature under dry conditions, with nitrogen as the pore fluid. Most samples from the incohesive fault zone have a permeability ranging between 10 −13 and 10 −17 m 2 (100–0.01 mD). These permeabilities are greater than those of cemented cataclasites and mylonites by more than two orders of magnitude at all effective pressures ( P e ) up to 180 MPa. Clayey fault gouge material has a permeability as low as 10 −19 m 2 (0.1 µD) at high effective pressures, but such impermeable fault gouge does not constitute a continuous zone on the two outcrops we studied. Permeability of the incohesive fault rocks exhibits large hysteresis upon P e cycling, compared with cataclasite and mylonite, because those cemented, cohesive fault rocks undergo much less inelastic deformation during the pressure cycling.

Incorporation of fault properties into production simulation models of Permian reservoirs from the southern North Sea

Abstract Reservoir compartmentalization is one of the key issues that affects the development and production phase of gas fields. To improve prediction of the effects of compartmentalization on production, a new method has been developed to allow petroleum engineers to incorporate geologically-reasonable fault rock flow properties into upscaled dynamic reservoir simulation models. The first stage of the workflow is to estimate the permeability and capillary characteristics of fault rocks within the field. These data are then combined with estimates of fault rock thickness, derived from outcrop studies, to calculate transmissibility multipliers to take into account the impact of faults on fluid flow within the dynamic model. Our method differs from most others in that we have attempted to account for the two-phase flow properties of fault rocks in the dynamic models from producing reservoirs. Application of the model to real field examples provides far faster history matching than has been achieved previously. In addition, taking into account the multi-phase flow properties of fault rocks explains production behaviour that previous models could not. Although, the focus of this study has been on the Southern Permian Basin in the North Sea, the same approach could be applied to other areas.

Study on estimate method of wave velocity and quality factor to fault seals

Based on ultrasonic test of fault rocks, the responses for wave velocity and quality factor (Q value) to lithology, porosity and permeability of fault rocks and mechanical property of faults are studied. In this paper, a new quantitative estimate method of fault seals is originally offered. The conclusions are as follows: (1) Wave velocity andQ value increase and porosity decreases with the increase in stress perpendicular to joint; (2) In compressive and compresso-shear fault rocks that are obviously anisotropic compared with their original rocks, the wave velocity and Q value are greater in the direction parallel with foliation, and usually less perpendicular to it. In tensile and tenso-shear fault rocks that are not obviously anisotropic, the wave velocity andQ value are under that of original rocks; (3) In foliated fault rocks, the direction with minimal wave velocity andQ value is the best direction for sealing; on the contrary it is the best for flowing; (4) Structural factures develop mainly along foliation, the minimal wave velocity andQ value reflect the flowing capacity in parallel direction to foliation, and the maximal wave velocity as well as Q value reflect the sealing capacity in normal direction to foliation. The new estimate method is based upon contrast of wave velocity and Q value between fault rocks and their original rocks, and is divided into three parts that are respectively to identify rock’s lithology, to judge mechanic property of faults and to Judge sealing capacity of faults. Although there is vast scale effect between ultrasonic wave and seismic wave, they have similar regularity of response to fabric and porosity of faults. This research offers new application for seismic data and petrophysical basis for seismological estimation of fault seals. The estimate precision will be improved with the enhancement of three-dimensional seismic prospecting work.

Sealing assessment of normal faults in clastic reservoirs: Modeling the petrophysical and stress attributes of faults.

We describe procedures for estimation of the petrophysical properties of fault rocks and the stress regime in normal faults as incorporated in the PC software (FAULTAP) developed at the Technology Research Center of Japan National Oil Corporation (JNOC/TRC). A quantitative appraisal of the petrophysical properties of fault rocks provides key information for fault sealing assessment and reservoir management. Empirical evidence shows that the permeability of fault rocks appears to be approximately two orders of magnitude lower than that of the host reservoir rocks. Among the deformation processes in clastic rocks, shale smear by faulting seems to be a most efficient mechanism of permeability reduction in fault rocks. The permeability of fault rocks has an inverse relationship with the clay content incorporated from the host rock as well as with the depth of fault rock and fault displacement. The relationship between clay content and pore throat radius in fault rock forms a basis for calculation of the capillary pressure of fault rock and the hydrocarbon column height that a fault can laterally support. The integrity or the failure of fault seals is crucially dependent upon how various portions of the fault surface are subjected to stress accumulation in the recent geological time. Simple methods for calculation of in-situ stresses on normal faults are presented for evaluation of fault failure by slip tendency or dilation tendency. An integration of fault failure and shale smear parameters provides a better assessment of fault sealing or potential leakage in response to the recent stress regime or changes in the pressure regime during field production.

Fault sealing processes in siliciclastic sediments

Abstract The microstructure and petrophysical properties of fault rocks from siliciclastic hydrocarbon reservoirs of the North Sea are closely related to the effective stress, temperature and sediment composition at the time of deformation, as well as their post-deformation stress and temperature history. Low permeability fault rocks may develop due to a combination of processes including: the deformation induced mixing of heterogeneously distributed fine-grained material (principally clays) with framework grains, pressure solution, cataclasis, clay smear, and cementation. Fault rocks can be classified into various types (disaggregation zones, phyllosilicate-framework fault rocks, cataclasites, clay smears, and cemented faults/fractures) based upon their clay and cement content as well as the amount of cataclasis experienced. In the absence of extensive cementation, the distribution of fault rock types along a fault plane can often be predicted from a detailed knowledge of the reservoir sedimentology. The permeability of fault rocks can vary by over six orders of magnitude, depending on the extent to which the porosity reduction processes have operated. Utilizing the strong link between the petrophysical properties of fault rocks and their geohistory allows the risks associated with fault seal evaluation to be reduced.