ALBERT

Description: From 2006 through mid-2018, there have been 125 [Formula: see text] recorded earthquakes within the Fort Worth Basin and the Dallas-Fort Worth metropolitan area. There is general scientific consensus that this increase in seismicity has been induced by increases in pore-fluid pressure from wastewater injection and from cross-fault pore-pressure imbalance due to injection and production. Previous fault stress analyses indicate that many of the faults are critically stressed; therefore, careful consideration should be taken when injecting in close proximity to these structures. Understanding the structural characteristics that control geomechanical aspects of these earthquake-prone faults is vital in characterizing this known hazard. To improve understanding of faults in the system, we have developed a characterization using a new basin-wide fault interpretation and database that has been assembled through the integration of published data, 2D and 3D seismic surveys, outcrop mapping, earthquakes, and interpretations provided by operators resulting in a 3D structural framework of basement-rooting faults. Our results show that a primary fault system trends northeast–southwest, creating a system of elongate horsts and grabens. Fault architectures range from isolated faults to linked and cross-cutting relay systems with individual segments ranging in length from 0.5 to 80 km. The faults that have hosted earthquakes are generally less than 10 km long, trend toward the northeast, and exhibit more than 50 m of normal displacement. The intensity of faulting decreases to the west away from the Ouachita structural front. Statistical analysis of the fault length, spacing, throw, and linkage tendency enables a more complete characterization of faults in the basin, which can be used to mitigate the seismic hazard. Finally, we find that a significant percentage of the total population of faults may be susceptible to reactivation and seismicity as those that have slipped recently.

Description: Production from self-sourced reservoirs relies on natural and induced fracturing for permeability and conductance of hydrocarbons to the producing wellbores, thus natural or induced fracturing is often a key to success in unconventional reservoir plays. On the other hand, fractures may compromise seals and large or well-connected fractures or faults may cause undesirable complications for unconventional reservoirs. Natural and induced fractures are influenced by (1) mechanical stratigraphy, (2) pre-existing natural deformation such as faults, fractures, and folds, and (3) in situ stress conditions, both natural and as modified by stimulation and pressure depletion. This special issue of the AAPG Bulletin elucidates some of these structural geologic and geomechanical controls. Understanding the occurrence and controls on natural and induced faulting and fracturing in self-sourced reservoirs is a key component for developing effective approaches for exploiting self-sourced reservoirs.

Description: We analyze fracture-density variations in subsurface fault-damage zones in two distinct geologic environments, adjacent to faults in the granitic SSC reservoir and adjacent to faults in arkosic sandstones near the San Andreas fault in central California. These damage zones are similar in terms of width, peak fracture or fault (FF) density, and the rate of FF density decay with distance from the main fault. Seismic images from the SSC reservoir exhibit a large basement master fault associated with 27 seismically resolvable second-order faults. A maximum of 5 to 6 FF/m (1.5 to 1.8 FF/ft) are observed in the 50 to 80 m (164 to 262 ft) wide damage zones associated with second-order faults that are identified in image logs from four wells. Damage zones associated with second-order faults immediately southwest of the San Andreas Fault are also interpreted using image logs from the San Andreas Fault Observatory at Depth (SAFOD) borehole. These damage zones are also 50–80 m wide (164 to 262 ft) with peak FF density of 2.5 to 6 FF/m (0.8 to 1.8 FF/ft). The FF density in damage zones observed in both the study areas is found to decay with distance according to a power law F=F0 r-n. The fault constant F0 is the FF density at unit distance from the fault, which is about 10–30 FF/m (3.1–9.1 FF/ft) in the SSC reservoir and 6–17 FF/m (1.8–5.2 FF/ft) in the arkose. The decay rate BLTN13173eq3 ranges from 0.68 to 1.06 in the SSC reservoir, and from 0.4 to 0.75 in the arkosic section. This quantification of damage-zone attributes can facilitate the incorporation of the geometry and properties of damage zones in reservoir flow simulation models.

Description: Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, geomechanics, and fracture characterization. He is the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is an AAPG Distinguished lecturer, a Geological Society of America Honorary Fellow, and an adjunct professor at the University of Wyoming. In July 2008, a Hedberg research conference entitled “The Geologic Occurrence and Hydraulic Significance of Fractures in Reservoirs” was hosted jointly by the AAPG, Society of Petroleum Engineers (SPE), and Society of Exploration Geophysicists (SEG), and organized by AAPG in Casper, Wyoming. The original endorsement for the conference was by recommendation from the author and the AAPG Reservoir Deformation Research Group, a standing subcommittee of the AAPG Research Committee. The scientific justification for conducting the conference was the rapidly growing recognition by the industry and academia that natural fractures and their geomechanical framework commonly control the hydraulic behavior of reservoirs. The sciences of fracture detection, characterization, and hydraulic modeling must advance if we are to maximize recovery from fractured reservoirs and optimize our exploitation of emerging resources, especially in the nonconventional realm. Success in these areas requires interdisciplinary integration from geophysical acquisition, processing, and analysis, to petrophysics, geological interpretation, geomechanics, and reservoir engineering at scales from pores to fields. The last research conference in North America dedicated to the topic was conducted in 1997. Therefore, the agenda was designed to address fractured reservoirs at a fundamental level to assess progress in the last decade. The participants addressed the following questions.

Description: The aim of part 2 is to understand the development of complex hydraulic fractures (HFs) that are commonly observed in the field and in experiments but are not explained by most models. Our approach uses finite element simulations and a numerical rheology developed in part 1 to model damage fracturing, the fracturing process by damage propagation in a rock with elastic–plastic damage rheology. Using this rheology and a dynamic solution technique, we investigate the effect of far-field stresses and pressure distribution in the fracture on the geometric complexity of the fractures. The model is for the vertical propagation of an HF segment into an overlying bed located far from borehole effects. The layer is 2.3 m (7.5 ft) tall, has elastic–plastic damage rheology, and contains a 0.3-m (1-ft)–tall initial vertical fracture. Vertical and horizontal tectonic loads of 50 MPa (7252 psi) and 10 to 45 MPa (1450–6527 psi) are established, and then an internal fracture pressure of 10 MPa/s (1450 psi/s) is applied until the layer fails. The simulated fracturing is sensitive to the stress state and generated patterns range from single straight fractures to treelike networks. Reducing differential stress increases the injection pressure required to fracture and promotes off-plane damage, which increases fracture complexity. Consecutive periods of nonuniform weakening followed by unstable rupture generate multiple branches and segments. We find that the processes that form HF complexity occur under a range of in-situ reservoir conditions and are likely to contribute to complex far-field fracture geometry and enhanced network connectivity.

Description: It is becoming widely recognized that a relationship exists between stress, stress heterogeneity, and the permeability of subsurface fractures and faults. We present an analysis of the South Sumatra Suban gas field, developed mainly in fractured carbonate and crystalline basement, where active deformation has partitioned the reservoir into distinct structural and stress domains. These domains have differing geomechanical and structural attributes that control the permeability architecture of the field. The field is a composite of Paleogene extensional elements that have been modified by Neogene contraction to produce basement-rooted forced folds and neoformed thrusts. Reservoir-scale faults were interpreted in detail along the western flank of the field and reveal a classic oblique-compressional geometry. Bulk reservoir performance is governed by the local stress architecture that acts on existing faults and their fracture damage zones to alter their permeability and, hence, their access to distributed gas. Reservoir potential is most enhanced in areas that have large numbers of fractures with high ratios of shear to normal stress. This occurs in areas of the field that are in a strike-slip stress style. Comparatively, reservoir potential is lower in areas of the field that are in a thrust-fault stress style where fewer fractures with high shear-to-normal stress ratios exist. Achieving the highest well productivity relies on tapping into critically stressed faults and their associated fracture damage zones. Two wellbores have been drilled based on this concept, and each shows a three- to seven-fold improvement in flow potential.

Description: The geometric characteristics of natural fractures significantly impact the hydraulic behavior of fractured reservoirs. Prediction of fracture geometry is therefore important for reservoir development decisions and production forecasting. Although many geometric, kinematic, mechanical, geomechanical, petrophysical, sedimentary, and geophysical attributes correlate to fracture intensity, typically, only the attribute with the highest absolute value correlation is chosen to be carried forward to influence prediction. We employ a geostatistical Bayesian updating approach that quantitatively accounts for multiple important attributes together impacting fracture geometry prediction. The resulting models are more representative of the true geological complexity. This methodology is applied to the Oil Mountain anticline outcrop near Casper, Wyoming. Jason McLennan received his B.S. degree in mining engineering and Ph.D. in geostatistics from the University of Alberta, Canada. He is a member of the Subsurface Technology Organization at ConocoPhillips focused primarily on geostatistical modeling and reservoir performance. Tricia Allwardt received her B.S. degree in earth and planetary sciences from Harvard University and her Ph.D. in structural geology and geomechanics from Stanford University. Tricia is a member of the Subsurface Technology Organization at ConocoPhillips focused primarily on integrating structural analysis, fracture characterization, and geomechanics into reservoir performance. Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, fracture characterization, and geomechanics. He is currently the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is a former AAPG distinguished lecturer, a Geological Society of America honorary fellow, and is an adjunct professor at the University of Wyoming. Helen Farrell received her B.Sc. degree in geology from Exeter University, United Kingdom and her M.Sc. degree and Ph.D. in structural geology from Imperial College London. She specialized in fractured reservoir characterization and geological integration with reservoir engineering for Phillips Petroleum Company and ConocoPhillips. She is currently the manager of the Nonconventional Gas Technology Group in ConocoPhillips Technology Organization. She is a former AAPG distinguished lecturer and a Texas professional geoscientist.

Description: Fracture prediction in subsurface reservoirs is critical for exploration through exploitation of hydrocarbons. Methods of predicting fractures commonly neglect to include the stratigraphic architecture as part of the prediction or characterization process. This omission is a critical mistake. We have documented a complex heterogeneous fracture development within the eolian Tensleep Sandstone in Wyoming, which arguably is one of the least complex reservoir facies. Fractures develop at four scales of observation: lamina-bound, facies-bound, sequence-bound, and throughgoing fractures that span the formation. We documented a detailed facies and fracture-intensity model using LIDAR-scanned outcrops located at the Alcova anticline in central Wyoming. Through this characterization, we reveal the existence of a striking variability in fracture intensity caused by original depositional architecture, overall structural deformation, and diagenetic alteration of the host rock. Chris Zahm is a research associate at the Bureau of Economic Geology within the Reservoir Characterization Research Laboratory (RCRL) Industrial Associates program. He received his B.S. degree from the University of Wisconsin-Madison in 1993, M.S. degree from the University of Texas at Austin in 1998 and Ph.D. from the Colorado School of Mines in 2002. His research interests are fractured reservoir characterization, including integration of stratigraphy as a fundamental control on fracture development in outcrop analogs and subsurface reservoirs. Peter Hennings received his B.S. and M.S. degrees in geology from Texas A&M University and his Ph.D. in geology from the University of Texas. He has held various technical and supervisory positions in Mobil Research Company, Phillips Petroleum Company, and ConocoPhillips. His research and application focus in these positions includes structure and tectonics, seismic interpretation, reservoir description, geomechanics, and fracture characterization. He is currently the manager of the Structure and Geomechanics Group in ConocoPhillips Subsurface Technology. He is an AAPG distinguished lecturer, a GSA honorary fellow, and is an adjunct professor at the University of Wyoming.