Julia F. W. Gale

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.

Natural fractures in shale: A review and new observations

Natural fractures have long been suspected as a factor in production from shale reservoirs because gas and oil production commonly exceeds the rates expected from low-porosity and low-permeability shale host rock. Many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with hydraulic-fracture stimulation have been ascribed to natural fracture reactivation. Here we review previous work, and present new core and outcrop data from 18 shale plays that reveal common types of shale fractures and their mineralization, orientation, and size patterns. A wide range of shales have a common suite of types and configurations of fractures: those at high angle to bedding, faults, bed-parallel fractures, early compacted fractures, and fractures associated with concretions. These fractures differ markedly in their prevalence and arrangement within each shale play, however, constituting different fracture stratigraphies—differences that depend on interface and mechanical properties governed by depositional, diagenetic, and structural setting. Several mechanisms may act independently or in combination to cause fracture growth, including differential compaction, local and regional stress changes associated with tectonic events, strain accommodation around large structures, catagenesis, and uplift. Fracture systems in shales are heterogeneous; they can enhance or detract from producibility, augment or reduce rock strength and the propensity to interact with hydraulic-fracture stimulation. Burial history and fracture diagenesis influence fracture attributes and may provide more information for fracture prediction than is commonly appreciated. The role of microfractures in production from shale is currently poorly understood yet potentially critical; we identify a need for further work in this field and on the role of natural fractures generally.

Natural fractures in shale

Natural fractures have long been suspected as a factor in production from shale reservoirs because gas and oil production commonly exceeds the rates expected from low-porosity and low-permeability shale host rock. Many shale outcrops, cores, and image logs contain fractures or fracture traces, and microseismic event patterns associated with hydraulic-fracture stimulation have been ascribed to natural fracture reactivation. Here we review previous work, and present new core and outcrop data from 18 shale plays that reveal common types of shale fractures and their mineralization, orientation, and size patterns. A wide range of shales have a common suite of types and configurations of fractures: those at high angle to bedding, faults, bed-parallel fractures, early compacted fractures, and fractures associated with concretions. These fractures differ markedly in their prevalence and arrangement within each shale play, however, constituting different fracture stratigraphies—differences that depend on interface and mechanical properties governed by depositional, diagenetic, and structural setting. Several mechanisms may act independently or in combination to cause fracture growth, including differential compaction, local and regional stress changes associated with tectonic events, strain accommodation around large structures, catagenesis, and uplift. Fracture systems in shales are heterogeneous; they can enhance or detract from producibility, augment or reduce rock strength and the propensity to interact with hydraulic-fracture stimulation. Burial history and fracture diagenesis influence fracture attributes and may provide more information for fracture prediction than is commonly appreciated. The role of microfractures in production from shale is currently poorly understood yet potentially critical; we identify a need for further work in this field and on the role of natural fractures generally.

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.

Effects of diagenesis (cement precipitation) during fracture opening on fracture aperture-size scaling in carbonate rocks

Abstract A correlation is demonstrated between the presence of crack-seal texture and power-law kinematic aperture-size (width) distributions among opening-mode fractures in rocks of dominantly carbonate mineralogy. Crack-seal opening increments (opening-displacement increment sizes or ‘gaps’) within individual fractures follow narrow normal or log-normal size distributions, suggesting that fracture widening accumulates in characteristic (usually micrometre-scale) size increments. The scale invariance in overall fracture width distributions present in some fracture sets most likely arises from grouping of these increments (localization) to form larger fractures (millimetre- to centimetre-scale widths). Such localization could be a consequence of the tendency for larger, less cemented fractures to break preferentially during subsequent deformation. Cement accumulation patterns thus provide a mechanism for positive feedback whereby large-fracture growth exceeds small-fracture growth. Using characteristically sized growth increments, a fracture growth model accurately simulates fracture arrays having power-law fracture-width distributions. Model parameters can be altered to produce characteristic-width fracture size distributions. The results have implications for how fracture porosity and permeability evolve in carbonate reservoirs.

Late opening-mode fractures in karst-brecciated dolostones of the Lower Ordovician Ellenburger Group, west Texas: Recognition, characterization, and implications for fluid flow

Two distinct groups of fractures in an Ellenburger Group reservoir in Barnhart field, Reagan County, west Texas, were identified. The oldest fractures (FBR) are the most numerous; have irregular shapes, sediment, and baroque dolomite fill, and no preferred orientation; and have been attributed by previous workers to brecciation associated with the collapse of Lower Ordovician paleocave systems. Younger, subvertical, opening-mode fractures (FY) that have consistent east-southeast and south-southwest strikes postdate the baroque dolomite cement. FY fractures therefore formed during the late stages or after the Pennsylvanian Ouachita orogeny. We analyzed FY fracture orientation, intensity, and openness using well image logs, oriented rotary-drilled sidewall cores, and a full-diameter core. FY fracture aperture sizes range from several micrometers to a few millimeters, and the fracture intensity is consistent within and between the wells studied at 1.8–4.0 102 fractures/mm2 for fractures 1 mm (0.04 in.) wide. Dolomite cement that is synchronous with FY fracture opening seals fractures in some locations, but is limited to fracture linings and mineral bridges in other places. Calcite, which grew after FY fractures stopped opening, is variably present and postdates dolomite cements. Where present, calcite occludes most remaining FY fracture porosity. Diagnosing the presence of postkinematic calcite is therefore an important step in being able to predict open fractures and was done for part of Barnhart field using rotary-drilled sidewall cores.

Geomechanical analysis of fluid injection and seismic fault slip for the Mw4.8 Timpson, Texas, earthquake sequence

An earthquake sequence that culminated in a Mw4.8 strike-slip event near Timpson, east Texas, the largest reported earthquake to date in that region, had previously been attributed to wastewater injection starting 17 months before the onset of recorded seismic activity. To test if this earthquake sequence can be attributed to wastewater injection, we conducted coupled poroelastic finite element simulations to assess the spatial and temporal evolution of pore pressure and stress field in the vicinity of the injection wells and to calculate the Coulomb failure stress on the seismogenic fault as a function of the permeability of the injection layer, fault orientation, fault permeability, and orientation and magnitude of the in situ stress. We find that injection-induced fault slip is plausible within the range of selected model input parameters, with slip favored by low reservoir permeability, low fault permeability, and a favorable orientation of the fault relative to the in situ stress state. Other combinations of equally plausible input parameters predict no slip within 96 months of simulated injection. Under most favorable boundary conditions for fault slip, fault slip occurs 7 months after the start of injection. Our results highlight the importance of detailed geomechanical site characterization for robust fault stability assessment prior to wastewater injection.

Constraints on the timing of deformation, magmatism and metamorphism in the Dalradian of NE Scotland

Synopsis The Portsoy Gabbro was emplaced into Argyll Group Dalradian metasediments as part of a suite of mafic intrusives that outcrop around the low-P/high-T Buchan metamorphic domain in NE Scotland. This paper presents new field data together with geobarometry and calculated pseudosections for pelites and metabasites, and geochronological data from the Portsoy Shear Zone, on the western boundary of the Buchan domain, which constrain the relative and absolute timing of deformation, metamorphism and magmatism. Textural and cross-cutting relationships indicate the D2 event, magmatism and Buchan metamorphism overlapped. Pelitic schists containing all three Al2SiO5 polymorphs occur structurally beneath the Portsoy Gabbro. The sequence of aluminosilicate growth in these rocks is andalusite–sillimanite–kyanite, implying an anti-clockwise P–T–t path. This study indicates that the andalusite to sillimanite transformation took place during D2, synchronous with the intrusion of the Portsoy Gabbro, and was followed by kyanite growth after D2. The late growth of kyanite indicates that, at least initially, cooling was not associated with uplift. Magmatic zircons from the Portsoy Gabbro yield a U–Pb age of 471.3 ± 0.6 Ma. A U–Pb zircon age from an undeformed pegmatite that cuts the S2 foliation in the gabbro indicates D2 shearing had largely terminated by ~ 471 Ma. We demonstrate, using a metabasite pseudosection, that the titanite formed during deformation as the gabbros cooled. The cooling rate for the gabbro from 1000°C to 620°C was rapid – at least 49°C Ma−1 – and, allowing that the Portsoy Shear Zone was not an uplift structure, was caused by a change in the thermal regime.