Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
ABSTRACT Laboratory flow tests have been performed to assess the effects of normal and shear stresses on the permeability of radial fractures around borehole. The rock specimens are prepared from Phu Kradung sandstone to obtain hollow cylinders having outside and inside diameters of 18.6 and 3.3 cm with a length of 15 cm. The rock is uniform and effectively impermeable. A radial fracture is artificially made by tension inducing method. It cuts through the borehole axis and along the specimen diameter. After applying a constant diametrical loading, the water is injectedunder constant head into the center hole. The fracture permeability is determined for various fracture orientations with respect to the vertical loading direction with 15° apart. The flow tests arerepeated 3 times under each vertical load to assess the permanent closure of the fracture under loading. The diametrical loads are progressively increased from 0.63MPa to 1.85MPa. Finite difference analyses have been performed to calculate the normal and shear stress distributions on the fracture under various orientations. The results indicate that the increases of the normal stresses rapidly decrease the fracture permeability.When the normal of fracture is deviated from the loading direction, the shear stress can increase the fracture permeability. A permanent closure of the fracture is observed as evidenced by the permanent reduction of the fracture permeability measured from the second and third cycles. The changes of aperture, water flow rate, and applied are used to calculate the changes of the fracture permeability. The fracture permeability is in the range between 1 × 10 mand 1.5× 10m2.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.37)
ABSTRACT Two-dimensional numerical modelling of the influence of joint orientation on the Uniaxial Compressive Strength (UCS) of singly- and multiply-jointed cylindrical rock samples was performed using models with slenderness (length/diameter) values of 2 and 4. For steep joint orientations, the more slender models were found to produce smaller UCS values when compared to the less slender models in the case of the singly-jointed rock specimens. This observation was related to the need for more significant intact material rupture to accommodate sliding failure on the joint for the case of the less slender specimen models. When recommendations for specimen slenderness outlined in popular standards for UCS testing are adopted one should take care to ensure the slenderness values used do not place restrictions on the mechanisms by which failure can occur. Such restrictions are likely to cause overestimation of strength estimates for jointed rock obtained from UCS testing and could introduce significant risk in engineering design. No dependence on specimen slenderness was observed for the multiply-jointed specimen models. This appears to be related to the wider deformation zone available for sliding failure in the multiply-jointed models, which circumvents the need for significant intact material rupture in the failure process. The use of sufficiently slender rock specimens may not be required for realistic UCS values to be obtained for jointed rock in cases where the rock has multiple parallel joints and sufficiently small joint spacing.
Laboratory Testing and Numerical Modelling of Fracture Propagation from Deviated Wells in Poorly Consolidated Formations
Ispas, Ion (BP) | Eve, Robin A. (BP) | Hickman, Randall J. (BP) | Keck, Richard G. (BP) | Willson, Stephen M. (BP now with Apache) | Olson, Karen E. (BP now with Southwestern Energy)
Abstract This paper presents the results of an integrated laboratory and numerical modelling study on the effect of wellbore deviation and wellbore azimuth on fracture propagation in poorly consolidated sandstone formations. The goal of this project was to develop an understanding of how fractures would transition from single planar fractures to non-planar transverse fractures for fields in the deep-water Gulf of Mexico. The foundation of this work was over 40 fracturing laboratory tests to measure fracture propagation geometries for a range of well deviations, differential horizontal stresses and rock strength. The samples tested were from three outcrops with unconfined compressive strength (UCS) values ranging from 300 – 1000 psi. For boreholes having low deviation angles and small differential stresses a vertical single planar fracture was created, aligned with the wellbore, as expected. As the well trajectory and stress contrast increased the fractures became more complex, with transverse turning fractures no-longer aligned with the wellbore. These laboratory results were used to develop and calibrate a new fully-3D finite element model that predicts non-planar fracture growth. The model matches the details of the laboratory tests, including the transition from planar vertical to nonplanar transverse fractures as the well deviation, azimuth and stress differentials increase. After initial model development and calibration was complete a model of a complex case was run before showing any experimental results to the modellers. The model successfully predicted the transverse non-planar results found in the laboratory; this gave us increased confidence in the model as a predictive tool. This work has now been applied with excellent success to four deepwater fields. We have recommended changes in maximum well deviations, performed post-job analyses on wells that had high deviations, and have increased our understanding of the impact of layered formations on fracture growth in these fields.
- Research Report > Experimental Study (0.66)
- Research Report > New Finding (0.48)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.56)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Green Canyon > Block 244 > Troika Field (0.99)
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- (2 more...)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Drilling > Well Planning > Trajectory design (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
Abstract In a heavy oil production steam-assisted gravity drainage (SAGD) project, two horizontal wells were separated by only a few meters. The separation had to be kept parallel to enable steam to be injected from one well and oil to be produced from the other twin well located below. In general, the currently practiced techniques rely on wireline technology to position the wells; in many cases, the technique requires access to the existing well in SAGD operations. This paper presents a novel technique for locating the relative position of one well with respect to another by using a rotating azimuthal logging-while-drilling (LWD) electromagnetic tool. With this technique, the relative position between a well with a rotating LWD electromagnetic tool and casing in an adjacent existing second well can be determined in real time. Consequently, the relative position and the relative distance between the two wells provide the field engineer with calculated inter-well spacing and direction to maintain the two wells parallel and spaced within a certain distance apart. This paper discusses and explains the fundamentals of the new LWD ranging technique. Several cases were modeled and compared with experimental data collected in a water tank with a conductive casing. The experiments successfully validated the computed responses. The casing position and distance to the LWD tool were successfully determined. This new LWD technique presents a ranging method alternative to the existing wireline technique and can be successfully used in a SAGD application.
- North America > Canada (0.70)
- North America > United States > Texas (0.29)
Abstract The study reported in this paper presents direct and in-situ measurement of critical fracture properties using analysis of downhole pressure data recorded in a horizontal well. The first well (Monitor Well) was fractured in multiple stages, produced, and later instrumented for downhole pressure measurement while a second (Active Well) was being fractured. Review of the pressure data from the Monitor Well showed intermittent communication between the two wells. Analysis of this data provides direct indications of in-situ fracture conductivity. Signatures of other non-intersecting fractures (shadowing) were also detected in the Monitor Well. This data is used for estimation of fracture orientation, length, and propagation pattern. Some of the results obtained from these measurements include; Two types of communication were observed between wells connected via hydraulic fractures; a shadowing effect, and direct hydraulic communication Fracture conductivity was very high during fracture communication and then decreased rapidly with time as fractures closed. The connection between the two wellbores was entirely lost soon after pumping stopped. Fractures extended vertically from Three Forks into the Middle Bakken The fracture growth pattern in this case study can best be classified as off-balance with low to medium branching and shear fracturing. Given the operational simplicity of these measurements and accuracy of its results, the technique is recommended as a tool for fracture diagnosis.
- North America > United States > North Dakota (1.00)
- North America > Canada (1.00)
Abstract The geometry and complexity of hydraulic fracture stimulation treatments is largely controlled by the heterogeneous and anisotropic nature of rocks. Conventional practice in designing fracture stimulation treatments revolve around the parameters that can be changed and considers the rock being stimulated as homogenous and isotropic. Engineers can influence the frac geometry to some degree by changing the pumping rate, fluid viscosity and proppant loading. If the goal of a frac job is to get the fluid and proppant below the ground, most any formation can be frac’d. The degree to which a reservoir will generate complex fracture networks, break into fresh rock or create a simple bi-wing fracture can be influenced by the stimulation treatment job design. The creation of a complex fracture network is a function of the stimulation fluid rheology, rock properties and presence and orientation of preexisting planes of weakness acting in the stress state of the reservoir. The index of brittleness or fracability is a term frequently used to describe formations that are likely to create complex fracture networks when fracture stimulated. In a broader view, fracability is much more than just calculating mechanical rock properties. A new definition of fracability, the Complex Fracability Index (CFI), proposed here integrates the sedimentary fabric, stratigraphic properties, mineral distribution and the presence and orientation of preexisting planes of weakness operating in the present day stress state into a single metric. This approach establishes a means to qualitatively or quantitatively determine the degree to which the rock will have the ability to create a complex fracture network or just a simple planer hydraulic fracture using the mechanical rock properties and the dip and orientation of the preexisting planes of weakness in the rock in the modern day stress state. The CFI methodology is not limited to shale reservoirs. Examples from the Barnett Shale and the tight sand in the Piceance Basin will be discussed.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.36)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (0.51)
- North America > Canada > Alberta > Johnson Field > Cardinal Hz Johnson 2-15-16-14 Well (0.97)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.89)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.89)
Abstract A 3D finite-element model covering more than 10 blocks in the deepwater Green Canyon area of the Gulf of Mexico has been used to calculate the stress distribution around an extensive salt body. The complex model geometry, and the determination of rock properties and pore pressure, was based on multiclient seismic data and state-of-the-art imaging techniques. The model has been used to determine the impact that salt geometry will have on drilling decisions. The numerical model shows that the near-salt stresses are dependent mainly on the morphology of the salt body. Higher compressive stresses were found in supra-salt minibasins and sub-salt concave-down embayments, resulting in higher mud weight windows. Areas below convex-down allochthonous base salt show lower compressive stresses, resulting in narrow mud weight windows. A fast well planning tool has been developed to translate the results of the finite-element model to operational parameters for well design. With this tool, the full stress tensors are extracted along any arbitrary well trajectory, providing a high-resolution model for calculating the mud weight window. This allows the drilling engineer to create fast predictions along any chosen trajectory within the study area and to make quick comparisons of the drilling mud weight window along multiple trajectories, helping with the selection of the optimal wellpath design. The application of this tool is illustrated using a "case study" focused on four proposed trajectories for a hypothetical well that has to reach the Eocene-Paleocene Wilcox formation.
- North America > United States > Texas (0.48)
- North America > United States > Gulf of Mexico (0.34)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.48)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- (4 more...)
Abstract Completion designs for hydraulic stimulation of shale-gas reservoirs frequently accounts for vertical growth of the treatment volume in the formation. Where vertical growth is expected, wells are drilled near the base of the reservoir optimizing the distribution of proppant upwards. Other treatments may seek to transport treatment fluid across a lithologic barrier, effectively trying to "treat two formations for the price of one." Vertical growth needs to occur under controlled conditions, undesirable growth leads to a potential creation of pathways for treatment fluids to leak out of formation, or worse pathways allowing undesirable fluids to flow into formation. In either case, this could lead to a loss in optimization for production. To better understand vertical growth characteristics of hydraulic treatment volumes, microseismic monitoring arrays deployed downhole just above the formation provide a good discriminant for vertical growth of events. Further characterization of this growth can be accomplished through Seismic Moment Tensor Inversion (SMTI), when a sufficient angular distribution of multiple downhole arrays detects the microseismicity. SMTI can distinguish the source type of the mechanisms (e.g. openings, closures, shear, etc.) and the orientations of the activated structures, allowing for a more complete picture of the failure process. In the example provided, different stages of stimulation in the Marcellus shale formation are examined in the context of varying degrees of vertical growth. When vertical growth occurs, as identified through SMTI analysis, it appears to be related to the activation of sub-vertical natural joints whereas for vertically confined stages the primary fracture set is subhorizontal suggesting delamination of fissile bedding planes is the dominant process. These differences, from stages in the same completion program, suggest that subtle background stress changes can result in very different behaviors. Full understanding of these mechanisms will lead to further optimization of these treatment programs to promote vertical growth to traverse structural barriers and retain containment of the treatment within zone.
- North America > United States > West Virginia (0.88)
- North America > United States > Pennsylvania (0.88)
- North America > United States > New York (0.88)
- North America > United States > Ohio (0.70)
- Geology > Geological Subdiscipline (1.00)
- Geology > Structural Geology > Tectonics (0.96)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.92)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
Abstract Over the past decade, microsesimic monitoring has become the approach most often used to gain an in-situ understanding of the rock's response during hydraulic fracture stimulations. From initial monitoring performed in the Barnett Shale to monitoring currently being carried out for example in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from data collection (single versus multi-well array configurations, utilization of long lateral stimulation wells), to data analysis and the incorporation of microseismic parameters to constrain and validate reservoir models. Furthermore, we discuss the variations in microseismic activity for different stimulation programs (e.g. zipper-fracs) and stimulation fluids. Generally, we have observed that overall fracture height, width and length, orientation, and growth vary from formation to formation and within each formation, thereby highlighting the ongoing necessity for microseismic monitoring. Additionally, through the use of advanced microseismic analysis techniques, such as Seismic Moment Tensor Inversion (SMTI), details on failure mechanisms have been used to assess stimulation effectiveness and define complex Discrete Fracture Networks (DFN). This information provides estimates of Enhanced Fluid Flow (EFF), which assist in calibrating and validating reservoir models. Utilizing spatial and temporal distributions in DFN and EFF, along with estimates of fracture interconnectivity and complexity, the role of pre-existing fractures and fault structures in the rock matrix can be established and used to provide more realistic estimates of stimulation parameters such as Stimulated Reservoir Volume (SRV).
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.71)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.64)
- North America > United States > Texas > Sabine Uplift > Carthage Cotton Valley Field > Cotton Valley Group Formation > Cotton Valley Sand Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- (6 more...)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155476, ’The Importance of Slow Slip on Faults During Hydraulic- Fracturing Stimulation of Shale-Gas Reservoirs,’ by Mark D. Zoback, SPE, Arjun Kohli, Indrajit Das, and Mark McClure, SPE, Stanford University, prepared for the 2012 Americas Unconventional Resources Conference, Pittsburgh, Pennsylvania, 5-7 June. The paper has not been peer reviewed. Slow slip of pre-existing fractures and faults is an important deformation mechanism that contributes to the effectiveness of slickwater hydraulic fracturing for stimulating production in extremely-low-permeability shale-gas reservoirs. Experiments indicated that slippage of faults in shales that contain less than approximately 30% clay is expected to propagate unstably, thus generating conventional microseismic events. In contrast, formations containing more than approximately 30% clay are expected to slip slowly. Because slow fault slip does not generate high-frequency seismic waves, conventional microseismic monitoring does not routinely detect what appears to be a critical process during stimulation. Thus, microseismic events are expected to give only a generalized picture where pressurization is occurring in a shale-gas reservoir during stimulation, which helps explain why microseismic activity does not appear to correlate with relative productivity. Introduction Multistage hydraulic fracturing with slickwater in horizontal wells is an effective completion strategy for producing commercial quantities of natural gas from organic-rich shale-gas formations. Physical mechanisms responsible for reservoir stimulation are understood poorly. The prevalent hypothesis is that diffusion of water out of the hydraulic fracture stimulates shear failure of multiple small pre-existing fractures and faults in the shale. This shear slip creates a network of relatively permeable flow paths and, thus, enhances productivity from the extremely-low-permeability shale formations. Microseismic events recorded during hydraulic fracturing are evidence of this shear slip, and the clouds of microseismic events associated with multiple hydraulic-fracturing stages in a well generally are assumed to define the stimulated rock volume from which the gas is produced. However, simple mass-balance calculations show that the cumulative deformation associated with the microseismic events can account for only a small fraction of the production. In a single well, it has been shown that the number of microseismic events does not correlate with production from successive hydraulic-fracturing stages. Production from five wells in the Barnett shale was studied, and it did not correlate with the number of microseismic events generated by hydraulic fracturing in each well, even though the wells were stimulated in a similar manner. Slow slip of numerous fault planes may occur in shale-gas reservoirs during stimulation and may be the dominant deformation mechanism during hydraulic stimulation. The shear deformation associated with the slowly slipping faults is expected to create a network of multiple permeable planes surrounding the induced hydraulic fractures.
- North America > United States > Texas (0.35)
- North America > United States > Pennsylvania > Allegheny County > Pittsburgh (0.24)
- Geology > Structural Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.94)
- (2 more...)