Jon Holder

Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments

Gas production from the Barnett Shale relies on hydraulic fracture stimulation. Natural opening-mode fractures reactivate during stimulation and enhance efficiency by widening the treatment zone. Knowledge of both the present-day maximum horizontal stress, which controls the direction of hydraulic fracture propagation, and the geometry of the natural fracture system, which we discuss here, is therefore necessary for effective hydraulic fracture treatment design. We characterized natural fractures in four Barnett Shale cores in terms of orientation, size, and sealing properties. We measured a mechanical rock property, the subcritical crack index, which governs fracture pattern development. Natural fractures are common, narrow (0.05 mm; 0.002 in.), sealed with calcite, and present in en echelon arrays. Individual fractures have high length/width aspect ratios (1000:1). They are steep (75), and the dominant trend is west-northwest. Other sets trend north-south. The narrow fractures are sealed and cannot contribute to reservoir storage or enhance permeability, but the population may follow a power-law size distribution where the largest fractures are open. The subcritical crack index for the Barnett Shale is high, indicating fracture clustering, and we suggest that large open fractures exist in clusters spaced several hundred feet apart. These fracture clusters may enhance permeability locally, but they may be problematic for hydraulic fracture treatments. The smaller sealed fractures act as planes of weakness and reactivate during hydraulic fracture treatments. Because the maximum horizontal stress trends northeast-southwest and is nearly normal to the dominant natural fractures, reactivation widens the treatment zone along multiple strands.

Experimental determination of subcritical crack growth parameters in sedimentary rock

Mounting evidence suggests that subcritical crack growth is an important mechanism for the development of natural fractures. Numerical simulations of fracture patterns are sensitive to the subcritical crack growth index, the exponent used to describe the power law dependence of crack velocity on stress intensity. Few measured values of subcritical indices in sedimentary rocks have been published, however, and no systematic studies of diagenetic controls of subcritical crack index behavior are available. Subcritical crack index measurements are especially difficult in weak, porous rock, primarily because non-elastic material response can obscure fracture-related behavior. We have carried out numerous subcritical crack index measurements with the widely used dual torsion beam test configuration and developed a modified test methodology for subcritical crack index measurements on porous rocks. The principal element of the methodology is a specimen pre-loading procedure to minimize transient material response. Measurement reliability is documented in the study by documentation of reproducibility in three sets of sandstone and carbonate specimens.

The interaction of propagating opening mode fractures with preexisting discontinuities in shale

Field observations show that hydraulic fracture growth in naturally fractured formations like shale is complex. Preexisting discontinuities in shale, including natural fractures and bedding, act as planes of weakness that divert fracture propagation. To investigate the influence of weak planes on hydraulic fracture propagation, we performed Semicircular Bend tests on Marcellus Shale core samples containing calcite-filled natural fractures (veins). The approach angle of the induced fracture to the veins and the thickness of the veins have a strong influence on propagation. As the approach angle becomes more oblique to the induced fracture plane, and as the vein gets thicker, the induced fracture is more likely to divert into the vein. Microstructural analysis of tested samples shows that the induced fracture propagates in the middle of the vein but not at the interface between the vein and the rock matrix. Cleavage planes and fluid inclusion trails in the vein cements exert some control on the fracture path. Combining the experimental results with theoretical fracture mechanics arguments, the fracture toughness of the calcite veins was estimated to range from 0.24 MPa m1/2 to 0.83 MPa m1/2, depending on the value used for the Youngs modulus of the calcite vein material. Measured fracture toughness of unfractured Marcellus Shale was 0.47 MPa m1/2.

Natural fractures in some US shales and their importance for gas production

Abstract Shale gas reservoirs are commonly produced using hydraulic fracture treatments. Microseismic monitoring of hydraulically induced fracture growth shows that hydraulic fractures sometimes propagate away from the present-day maximum horizontal stress direction. One likely cause is that natural opening-mode fractures, which are present in most mudrocks, act as weak planes that reactivate during hydraulic fracturing. Knowledge of the geometry and intensity of the natural fracture system and the likelihood of reactivation is therefore necessary for effective hydraulic fracture treatment design. Changing effective stress and concomitant diagenetic evolution of the host-rock controls fracture initiation and key fracture attributes such as intensity, spatial distribution, openness and strength. Thus, a linked structural-diagenesis approach is needed to predict the fracture types likely to be present, their key attributes and an assessment of whether they will impact hydraulic fracture treatments significantly. Steep (>75°), narrow ( 100, indicating that the fractures are clustered. These fractures, especially where present in clusters, are likely to divert hydraulic fracture strands. Early, sealed, compacted fractures, fractures associated with deformation around concretions and sealed, bedding-parallel fractures also occur in many mudrocks but are unlikely to impact hydraulic fracture treatments significantly because they are not widely developed. There is no evidence of natural open microfractures in the samples studied.

Predicting and characterizing fractures in dolostone reservoirs: using the link between diagenesis and fracturing

Abstract Fracture geometries and fracture-sealing characteristics in dolostones reflect interactions among mechanical and chemical processes integrated over geological timescales. The mechanics of subcritical fracture growth results in fracture sets having power-law size distributions where the attributes of large, open fractures that affect reservoir flow behaviour can be accurately inferred from observations of cement-sealed microfractures and other microscopic diagenetic features, which are widespread in dolostones. Fracture porosity is governed by the competing rates of fracture opening and cement precipitation during fracture growth and by cements that post-date fracture opening. Combined analysis of structural and diagenetic features provides the best approach for understanding how fracture systems influence fluid flow. We review previous work and integrate new data on fractures and diagenetic features in cores from the Lower Ordovician Ellenburger and Permian Clear Fork formations in West Texas, and the Lower Ordovician Knox Group in Mississippi, together with outcrop samples of Lower Cretaceous Cupido Formation dolostones from the Sierra Madre Oriental, Mexico, in order to illustrate our approach.

Constraining the Spatial Distribution of Fracture Networks in Naturally Fractured Reservoirs Using Fracture Mechanics and Core Measurements

Observations of natural fractures in core or image logs typically give limited information on orientation, aperture and intensity. Because of the sparseness of wellbore intersections of fractures, data analysis results in incomplete statistical characterization of the fracture population, leaving interwell characterization almost impossible. Using basic fracture mechanics models and a novel core-testing technique, we propose that the fundamental shape of fracture parameter distributions can be predicted, and that there is a characteristic, quantifiable relationship between fracture length, spacing and aperture. We have performed subcritical fracture growth tests on numerous core samples, using credit card sized specimens, demonstrating the ability to characterize fracture mechanics properties of rock on a bed by bed basis. Using the subcritical index, a parameter that quantifies the relationship between natural fracture propagation velocity and tip loading conditions, we can predict the degree of fracture spacing regularity or clustering for a given reservoir bed. This subcritical parameter, along with information on the number of initial natural flaws in a given rock type, allows us to quantify the expected length distribution of the fractures. Under many conditions, as verified from outcrop data, fracture length is theoretically expected to follow an exponential distribution. Since natural fracture length is typically unobservable in subsurface data, we derive relationships that relate fracture length to aperture and spacing, both more readily measurable quantities. With this information, matrix block size and fracture drainage continuity can be estimated for the purpose of flow simulation in a fractured reservoir. Introduction Direct characterization of fracture network attributes such as length, spacing, aperture, orientation and intensity from core or image logs is often difficult. Fractures are infrequently intersected by wells, and if fractures do intersect the wellbore they are rarely abundant enough to give a good representation of the fracture geometry. Due to sparseness of these data sets, various predictive schemes, based on geostatistics or geomechanical models, are used to estimate subsurface fracture attributes. There are two types of statistical approaches in modeling fracture network geometry. The first approach addresses each fracture characteristic separately. Data for each attribute are gathered, and distributions are fit to the data. If not enough data are available, distributions published in literature are used (Table 1). This type of modeling is particularly useful to estimate the upper and lower bounds on reservoir response. However, lack of reservoir data often makes selecting a correct distribution difficult, thus leading to the use of outcrop data rather than wellbore data, which can sometimes be misleading. Recent advances in using microcracks as proxies for larger scale fractures have improved the capability of getting pertinent subsurface data, circumventing some of the problems associated with data sparseness. The second statistical approach takes the statistical data for individual fracture attributes and also specifies their interdependence, describing the 3D fracture network as a whole. The simplest model often used in petroleum applications is a network of three unbounded, mutually orthogonal fractures. However, there are many fracture characteristics and a seemingly limitless number of correlations between those parameters, although Dershowitz and Einstein argue that nature restricts the number of applicable models and only a few predominant models need to be defined. Choosing among the possible models may require more fracture data than is available, and it may be difficult to determine a priori whether, for example, a fracture network is clustering or more uniformly distributed spatially. An alternative to geostatistical characterization is a geomechanics-based approach, where a physical understanding of the fracturing process is combined with measurements of mechanical properties of rock to predict fracture network characteristics. This process-oriented SPE 71342 Constraining the Spatial Distribution of Fracture Networks in Naturally Fractured Reservoirs Using Fracture Mechanics and Core Measurements Jon E. Olson, Yuan Qiu, Jon Holder and Peggy Rijken, The University of Texas at Austin 2 J. E. OLSON, Y. QIU, J. HOLDER AND P. RIJKEN SPE 71342 approach can also provide a theoretical basis for deciding what types of fracture attribute distributions are physically reasonable, and how attributes such as length, spacing and aperture are inter-related. The combined prediction of all fracture attributes is possible using geomechanics, and the mechanistic approach as postulated in this paper requires less direct fracture sampling than typical statistical methods. The subcritical fracture index, a rock parameter that can be measured from core samples, can be used to constrain the distributions of aperture, spacing and length. Additional geological information, such as the strain, pore pressure and diagenetic history of the reservoir can provide further constraint on fracture network predictions. Fracture Mechanics Constraints on Fracture Network Properties Linear elastic fracture mechanics has been successfully applied to many geologic fracture problems. The parameters of particular interest for fractured reservoirs are fracture length, spacing, aperture and connectivity. Each of these parameters can be addressed using mechanical analyses based on geologically-inferred or measured boundary conditions and rock properties. We find that fracture length and spacing are both tied to the same mechanical property, the subcritical crack index, and that further analysis can relate fracture aperture to fracture length. Fracture Length. The analysis of mode I (opening mode), en echelon fracture arrays has shown that mechanical fracture interaction will influence a fracture’s stress intensity factor, KI. The stress intensity factor for a uniformly loaded, isolated crack of length 2a is defined as a K I I π σ ∆ = ............................................................ (1) The mode I driving stress, I σ ∆ ,is defined as ) ( n p I P σ σ − = ∆ ......................................................... (2) where Pp is the pore pressure in the rock, and n σ is the in situ stress resolved perpendicular to the crack. The stress intensity factor is compared to the fracture toughness of a material, KIc, to determine crack propagation. For critical crack propagation, Ic I K K ≥ , but fractures in rock can also propagate subcritically ( Ic I K K < ). Fig. 1 shows the normalized stress intensity factor for the right (inner) tip of the left member of a two crack, en echelon array, as a function of overlap as the two cracks grow toward one another. An overlap of –0.5 corresponds to zero length for the echelon segments, an overlap of 0 corresponds to each segment having a length of 1⁄2 the total array length, and an overlap of 0.5 corresponds to each segment side by side with a length equal to the total array length. The stress intensity factor for the en echelon crack is normalized by the stress intensity factor of an isolated crack of the same length with the same driving stress (Eq. 1). As parallel, en echelon fractures approach one another and have just begun to overlap (overlap between -0.1 and 0.02 in Fig. 1), mechanical interaction increases the stress intensity at the inner tips. When the fracture tips pass one another and the overlap increases, the stress intensity is reduced at the inner tips, hindering propagation. However, the outer tips experience a stress intensity increase (propagation enhancement), such that the outer tips are expected to grow while the inner tips arrest. These interaction effects diminish as the fracture spacing increases relative to the fracture height, such that when spacing is equal to fracture height, the peak perturbation of the stress intensity factor is less than 20%. Based on the mechanical interaction behavior of nearby cracks, we developed a fracture length model for larger opening mode fractures (main cracks) propagating through a material with randomly distributed, parallel flaws (field cracks). If the propagating main crack passes within a critical spacing distance of a smaller field crack, the main crack propagation is arrested or captured at its overlapping inner tip, and propagation is transferred to the outer tip of the field crack. Simulation results indicate that the critical spacing for main crack capture is approximately equal to 1⁄2 the field crack length. The probability that a propagating main crack will be captured by a smaller field crack corresponds to the probability that a propagating crack will reach a particular length. The more field cracks present in a rock, the less likely fractures are to achieve great length. We have quantified this fracture capture probability, and thus quantified the expected frequency distribution of fracture length. The probability that a main crack with length 2a will be captured is equal to the probability that at least one field crack of length 2b will lie within its capture zone (Fig. 2). The capture zone is a rectangular region around the main crack with dimensions of crack length by 2 times the critical spacing (because the capture zone lies on both sides of the main crack), or 2a x 2b. Assuming N field cracks are uniformly randomly distributed in a total area A, the probability, P’, that at least one field crack will lie within the capture zone of a propagating main crack of length 2a is equal to 1 minus the probability that no cracks reside in the capture zone, or

Quantifying the Fracture Mechanics Properties of Rock for Fractured Reservoir Characterization

Natural fractures are important conduits for fluid-flow and can control the deformational behavior of rock. The accurate evaluation of natural fracture geometry in the subsurface is difficult because of the sampling problems inherent to wellbores and indirect investigation methods such as seismic. Because of these limitations in observational capability, predictive models are needed to provide more constraint on natural fracture characteristics. One approach is to look at the mechanics of fracture propagation in sedimentary rock as controlled by subcritical crack growth (also known as stresscorrosion cracking). We have measured the subcritical fracture properties of numerous sedimentary rocks, including core samples from petroleum reservoirs, in conjunction with detailed petrographic analysis. Our preliminary results suggest that carbonates and sandstones tend to have very different subcritical fracture properties, and the variation in sandstone properties can be linked to grain and cement mineralogy and volume fractions. Introduction The direct characterization of natural fracture network attributes such as length, spacing, aperture, orientation and intensity in most reservoirs is very difficult, primarily because of the low probability of intersecting vertical fractures with vertical wellbores. Accordingly, various predictive schemes based on geostatistics, or geomechanical models are used to estimate subsurface fracture attributes. Statistical approaches fit distributions of fracture characteristics to available data. The statistical fit can treat different fracture attributes independently, or it can incorporate interdependences into the fit, but in either case, the result is dependent on available direct fracture observations. Alternatively, geomechanics-based simulations of fracture attributes combine a physical understanding of the fracturing process with measurements of a small set of rock properties and geologic boundary conditions to predict fracture network properties, even in the absence of direct observations. This approach provides for the determination of physically reasonable fracture attributes, and of relationships between different fracture attributes. The geomechanical model used here is based on subcritical crack growth. Although subcritical fracture velocities are several orders of magnitude slower than rupture velocities, natural fracture growth can be significant in tectonically strained crustal rocks. A number of studies have demonstrated subcritical crack growth controls of fracture spacing and length distributions, connectivity and fracture aperture. Subcritical crack growth can be described by the empirical relationship

Modulus and permeability variations during air/water flow in shaley sandstones

Abstract Static deformations and simultaneous measurements of P- and S-wave velocities and air and gas permeabilities for dry, brine-saturated, and partially saturated shaley sandstones from a fluvial-deltaic depositional environment are reported and discussed. Correlations between measured elastic response and petrographic analyses of this material are explored. Variations in velocities for dry specimens are generally consistent with reported behavior in shaley sandstones, but systematic variations of dynamic shear moduli with quartz cement are also observed. Partially-saturated specimen behavior is effectively the same as that for brine-saturated specimens. Saturated behavior shows similar correlations with formation properties as those identified in previous studies of shaley sandstones.

Pore scale coupling of fluid displacement and unconsolidated sediment mechanics

In unconsolidated sediments, capillary pressure in the pore space may be large enough to move grains apart during drainage. This motion alters the pore throat sizes which control subsequent displacement in the sediment. We present two grain scale models for this coupled process. In both cases, we assume fluid interfaces are controlled by capillary forces, and determine the detailed geometry of those interfaces. We compute the net force exerted on each grain by capillary pressure, including cohesion at grain contacts supporting pendular rings. We combine those forces to determine the movement of grains using a a kinematic model b a rigorous model where mechanical stress and elastic properties of grains are included via a discrete element method. This is the first coupling in 3D, albeit in samples of limited size. Preliminary results in disordered dense sphere packs suggest the development of high permeability gas channels rather than planar structures.

HIGH-PRESSURE AIR INJECTION: APPLICATION IN A FRACTURED AND KARSTED DOLOMITE RESERVOIR

The Bureau of Economic Geology and Goldrus Producing Company have assembled a multidisciplinary team of geoscientists and engineers to evaluate the applicability of high-pressure air injection (HPAI) in revitalizing a nearly abandoned carbonate reservoir in the Permian Basin of West Texas. The characterization phase of the project is utilizing geoscientists and petroleum engineers from the Bureau of Economic Geology and the Department of Petroleum Engineering (both at The University of Texas at Austin) to define the controls on fluid flow in the reservoir as a basis for developing a reservoir model. This model will be used to define a field deployment plan that Goldrus, a small independent oil company, will implement by drilling both vertical and horizontal wells during the demonstration phase of the project. Additional reservoir data are being gathered during the demonstration phase to improve the accuracy of the reservoir model. The results of the demonstration will being closely monitored to provide a basis for improving the design of the HPAI field deployment plan. The results of the reservoir characterization field demonstration and monitoring program will be documented and widely disseminated to facilitate adoption of this technology by oil operators in the Permian Basin and elsewhere in the U.S.