Faulting Induced by Forced Fluid Injection and Fluid Flow Forced by Faulting: An Interpretation of Hydraulic-Fracture Microseismicity, Carthage Cotton Valley Gas Field, Texas

2004 ◽  
Vol 94 (5) ◽  
pp. 1817-1830 ◽  
Author(s):  
J. T. Rutledge
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fluid Injection ◽  
Gas Field ◽  
Cotton Valley

Hydraulic stimulation of natural fractures as revealed by induced microearthquakes, Carthage Cotton Valley gas field, east Texas

Geophysics ◽  
2003 ◽  
Vol 68 (2) ◽  
pp. 441-452 ◽  
Author(s):  
James T. Rutledge ◽  
W. Scott Phillips
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Zone ◽  
Horizontal Stress ◽  
Focal Mechanisms ◽  
Fracture Plane ◽  
Natural Fractures ◽  
East Texas ◽  
Gas Field ◽  
Cotton Valley ◽  
Maximum Horizontal Stress

We produced a high‐resolution microseismic image of a hydraulic fracture stimulation in the Carthage Cotton Valley gas field of east Texas. We improved the precision of microseismic event locations four‐fold over initial locations by manually repicking the traveltimes in a spatial sequence, allowing us to visually correlate waveforms of adjacent sources. The new locations show vertical containment within individual, targeted sands, suggesting little or no hydraulic communication between the discrete perforation intervals simultaneously treated within an 80‐m section. Treatment (i.e., fracture‐zone) lengths inferred from event locations are about 200 m greater at the shallow perforation intervals than at the deeper intervals. The highest quality locations indicate fracture‐zone widths as narrow as 6 m. Similarity of adjacent‐source waveforms, along with systematic changes of phase amplitude ratios and polarities, indicate fairly uniform source mechanisms (fracture plane orientation and sense of slip) over the treatment length. Composite focal mechanisms indicate both left‐ and right‐lateral strike‐slip faulting along near‐vertical fractures that strike subparallel to maximum horizontal stress. The focal mechanisms and event locations are consistent with activation of the reservoir's prevalent natural fractures, fractures that are isolated within individual sands and trend subparallel to the expected hydraulic fracture orientation (maximum horizontal stress direction). Shear activation of these fractures indicates a stronger correlation of induced seismicity with low‐impedance flow paths than is normally found or assumed during injection stimulation.

A new approach to the hydraulic fracture geometric dimensions determination

2017 ◽  
Vol 12 (1) ◽  
pp. 126-134
Author(s):  
A.M. Ilyasov
Keyword(s):  
Exact Solution ◽  
Hydraulic Fracture ◽  
Pressure Gauge ◽  
Hyperbolic Type ◽  
Fluid Injection ◽  
Fracturing Fluid ◽  
New Approach ◽  
Gauge Data ◽  
Bottomhole Pressure ◽  
Half Length

Based on the generalized Perkins-Kern-Nordgren model (PKN) for the development of a hyperbolic type vertical hydraulic fracture, an exact solution is obtained for the hydraulic fracture self-oscillations after terminating the fracturing fluid injection. These oscillations are excited by a rarefaction wave that occurs after the injection is stopped. The obtained solution was used to estimate the height, width and half-length of the hydraulic fracture at the time of stopping the hydraulic fracturing fluid injection based on the bottomhole pressure gauge data.

Comparison of Hydraulic Fracture Models for Highly Elongated Fractures of Variable Height

1986 ◽  
Vol 108 (2) ◽  
pp. 107-115 ◽  
Author(s):  
I. D. Palmer ◽  
C. T. Luiskutty
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Reasonable Agreement ◽  
High Stress ◽  
Vertical Direction ◽  
Critical Examination ◽  
Wellbore Pressure ◽  
Fracture Models ◽  
Fracture Height ◽  
Stress Contrast

There is a pressing need to compare and evaluate hydraulic fracture models which are now being used by industry to predict variable fracture height. The fractures of concern here are vertical fractures which have a pronounced elongation in the direction of the payzone, i.e., there is a dominant one-dimensional fluid flow along the payzone direction. A summary is given of the modeling entailed in the basic ORU fracture model, which calculates fracture height as a function of distance from the wellbore in the case of a continuous sand bounded by zones of higher (but equal) minimum in-situ stress. The elastic parameters are assumed the same in each layer, and injected flow rates and fluid parameters are taken to be constant. Leak-off is included with spurt loss, as well as non-Newtonian flow. An advantage of the model is its small computer run time. Predictions for wellbore height and pressure from the ORU model are compared separately with the AMOCO and MIT pseudo-3D models. In one instance of high stress contrast the ORU wellbore pressure agrees fairly well with the AMOCO model, but the AMOCO wellbore height is greater by 32 percent. Comparison between the ORU and MIT models in two cases (also high stress contrast) indicates height disagreement at the wellbore by factors of 1.5–2.5 with the MIT model giving a lower height. Thus it appears there can be substantial discrepancies between all three models. Next we compare the ORU model results with six cases of elongated fractures from the TERRA-TEK fully-3D model. Although two of these cases are precluded due to anomolous discrepancies, the other four cases show reasonable agreement. We make a critical examination of assumptions that differ in all the models (e.g., the effective modulus-stiffness multiplier approximation in the AMOCO model, the effect of finite fluid flow in the vertical direction in the MIT model, and the effect of 2D flow and limited perforated height in the TERRA-TEK model). Suggestions are made for reconciling some of the discrepancies between the various models. For example, the ORU/AMOCO height discrepancy appears to be resolved; for other discrepancies we have no explanation. Our main conclusion is that the AMOCO, TERRA-TEK and ORU models for fracture height and bottomhole pressure are in reasonable agreement for highly elongated fractures. Despite the difficulties in understanding the different models, the comparisons herein are an encouraging first step towards normalizing these hydraulic fracture models.

Simulation of Fluid Flow through a Hydraulic Fracture of a Heterogeneous Fracture-Tough Reservoir in the Planar 3D Formulation

2021 ◽  
Vol 56 (2) ◽  
pp. 164-177
Author(s):  
A. B. Kiselev ◽  
Li Kay-Zhui ◽  
N. N. Smirnov ◽  
D. A. Pestov
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Flow Through

scholarly journals Evolution of Fracture Aperture in Quartz Sandstone under Hydrothermal Conditions: Mechanical and Chemical Effects

Minerals ◽  
2020 ◽  
Vol 10 (8) ◽  
pp. 657
Author(s):  
Chaojie Cheng ◽  
Harald Milsch
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Chemical Equilibrium ◽  
Pore Fluid ◽  
Pressure Solution ◽  
Fracture Aperture ◽  
Hydraulic Aperture ◽  
Mechanical Aperture ◽  
Stagnant Flow

Fractures efficiently affect fluid flow in geological formations, and thereby determine mass and energy transport in reservoirs, which are not least exploited for economic resources. In this context, their response to mechanical and thermal changes, as well as fluid–rock interactions, is of paramount importance. In this study, a two-stage flow-through experiment was conducted on a pure quartz sandstone core of low matrix permeability, containing one single macroscopic tensile fracture. In the first short-term stage, the effects of mechanical and hydraulic aperture on pressure and temperature cycles were investigated. The purpose of the subsequent intermittent-flow long-term (140 days) stage was to constrain the evolution of the geometrical and hydraulic fracture properties resulting from pressure solution. Deionized water was used as the pore fluid, and permeability, as well as the effluent Si concentrations, were systematically measured. Overall, hydraulic aperture was shown to be significantly less affected by pressure, temperature and time, in comparison to mechanical aperture. During the long-term part of the experiment at 140 °C, the effluent Si concentrations likely reached a chemical equilibrium state within less than 8 days of stagnant flow, and exceeded the corresponding hydrostatic quartz solubility at this temperature. This implies that the pressure solution was active at the contacting fracture asperities, both at 140 °C and after cooling to 33 °C. The higher temperature yielded a higher dissolution rate and, consequently, a faster attainment of chemical equilibrium within the contact fluid. X-ray µCT observations evidenced a noticeable increase in fracture contact area ratio, which, in combination with theoretical considerations, implies a significant decrease in mechanical aperture. In contrast, the sample permeability, and thus the hydraulic fracture aperture, virtually did not vary. In conclusion, pressure solution-induced fracture aperture changes are affected by the degree of time-dependent variations in pore fluid composition. In contrast to the present case of a quasi-closed system with mostly stagnant flow, in an open system with continuous once-through fluid flow, the activity of the pressure solution may be amplified due to the persistent fluid-chemical nonequilibrium state, thus possibly enhancing aperture and fracture permeability changes.

Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2292-2307 ◽  
Author(s):  
Jizhou Tang ◽  
Kan Wu ◽  
Lihua Zuo ◽  
Lizhi Xiao ◽  
Sijie Sun ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Rock Deformation ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Width ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

Summary Weak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement. I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.

Rheological properties of the shallow subduction interface: insights from the Chugach Complex, Alaska

2020 ◽  
Author(s):  
Zoe Braden ◽  
Whitney Behr
Keyword(s):  
Fluid Flow ◽  
Rheological Properties ◽  
Shear Zone ◽  
Strain Localization ◽  
High Strain ◽  
Shear Zones ◽  
Fluid Injection ◽  
Structural Mapping ◽  
Wide Range ◽  
Shallow Subduction

<p>The plate interface in subduction zones accommodates a wide range of seismic styles over different depths as a function of pressure-temperature conditions, compositional and fluid-pressure heterogeneities, deformation mechanisms, and degrees of strain localization. The shallow subduction interface (i.e. ~2-10 km subduction depths), in particular, can exhibit either slow slip events (e.g. Hikurangi) or megathrust earthquakes (e.g. Tohoku). To evaluate the factors governing these different slip behaviors, we need better constraints on the rheological properties of the shallow interface. Here we focus on exhumed rocks within the Chugach Complex of southern Alaska, which represents the Jurassic to Cretaceous shallow subduction interface of the Kula and North American plates. The Chugach is ideal because it exhibits progressive variations in subducted rock types through time, minimal post-subduction overprinting, and extensive along-strike exposure (~250 km). Our aims are to use field structural mapping, geochronology, and microstructural analysis to examine a) how strain is localized in different subducted protoliths, and b) the deformation processes, role of fluids, and strain localization mechanisms within each high strain zone. We interpret these data in the context of the relative ‘strengths’ of different materials on the shallow interface and possible styles of seismicity.  </p><p>Thus far we have characterized deformation features along a 1.25-km-thick melange belt within the Turnagain Arm region southeast of Anchorage.  The westernmost melange unit is sediment poor and consists of deep marine rocks with more chert, shale and mafic rocks than units to the east. The melange fabric is variably developed (weakly to strongly) throughout the unit and is steeply (sub-vertical) west-dipping with down-dip lineations. Quartz-calcite-filled dilational cracks are oriented perpendicular to the main melange fabric.</p><p>Drone imaging and structural mapping reveals 3 major discrete shear zones and 6-7 minor shear zones within the melange belt, all of which exhibit thrust kinematics. Major shear zones show a significant and observable strain gradient into a wide (~1 m) region of high strain and deform large blocks while minor shear zones are generally developed in narrow zones (~10-15 cm) of high strain between larger blocks. One major shear zone is developed in basalt and has closely-spaced, polished slip surfaces that define a facoidal texture; the basalt shear zone is ~1 m thick. Preserved pillows are observable in lower strain areas on either side of the shear zone but are deformed and indistinguishable within the high strain zone. The other two major shear zones are developed in shale and are matrix-supported with wispy, closely-spaced foliation and rotated porphyroclasts of chert and basalt; the shale shear zones are ~0.5-2 m thick.  </p><p>Abundant quartz-calcite veins parallel to the melange fabric and within shale shear zones record multiple generations of fluid-flow; early veins appear to be more silicic and later fluid flow involved only calcite precipitation. At the west, trench-proximal end of the mélange unit there is a 5-10 m thick silicified zone of fluid injection that is bound on one side by the basalt shear zone. Fluid injection appears to pre-date or be synchronous with shearing.</p>

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