Wilson, Thomas (West Virginia University) | Kavousi, Payam (West Virginia University) | Carr, Timothy (West Virginia University) | Carney, Brooke (Northeast Natural Energy LLC) | Uschner, Natalie (Schlumberger) | Magbagbeola, Oluwaseun (Schlumberger) | Xu, Lili (Schlumberger)
Inversion of 3D-3C data yields P- and S-acoustic impedances that can be combined to yield λρ and μρ (e.g. Goodway et al., 1997; Hampson et al., 2005; Russell, 2014; Sayers et al., 2015). λ and μ, Lamè's parameters, represent incompressibility and shear modulus, respectively. Interpretation of λρ-μρ volumes has been used recently to evaluate unconventional oil and gas shale reservoirs (see Alzate, 2012; Alzate and Devegowda, 2013; and Perez and Marfurt, 2014 and 2015). Alzate and Devegowda (2013) use λρ-μρ crossplots to identify organic rich and brittle sweet spots. They also associate lower Young's modulus with more organic rich intervals and lower Poisson's ratio with more brittle intervals.
In this study we compute λρ-μρ from log data for the Middle Devonian Hamilton Group and bounding Tully and Onondaga limestones taken from the vertical pilot well (Figure 1) drilled by Northeast Natural Energy, LLC on their Morgantown, WV well pad. We also compute brittleness using approaches proposed by Greiser and Bray (2007), Jarvie et al. (2007) and Wang and Gale (2009). We then note the results of a stimulation test and consider hydraulic fracture development within the context of these log derived parameters and mechanical properties. The stimulation tests are conducted using a geomechanical model developed from a comprehensive suite of logs collected in the vertical pilot well by Schlumberger (see Wilson et al., 2016).
Results indicate that the TOC (total organic carbon) rich Marcellus Shale is associated with lower Young's modulus, Poisson's ratio and lower values of λρ and μρ. High TOC intervals tend to be more brittle using both the Jarvie et al. (2007) and Wang and Gale (2009) approaches; however, brittle intervals are not confined to TOC rich zones. Model hydraulic fractures are, however, generally confined to TOC rich strata, while microseismic activity associated with shear failure of pre-existing natural fractures during treatment is distributed through the Hamilton Group.
Presentation Date: Tuesday, September 26, 2017
Start Time: 9:45 AM
Location: Exhibit Hall C/D
Presentation Type: POSTER
San Andres formation is a dolomitized carbonate and an oil-and gas-bearing member of the Upper Permian in the Permian Basin. It has been produced with vertical wells that were either waterflooded or CO2 injected for primary, secondary, and tertiary recovery. Some of the early waterfloods date back to the 1960s. Historically, the San Andres formation is associated with high water cuts. This paper proposes an integrated solution from planning to completion of a horizontal well, with an aim to control water production. The workflow involves the integration of various technologies such as crosswell seismic, petrophysical logs, geomechanical logs, fracture modeling, and real-time microseismic monitoring.
Stratigraphic surfaces were created using the crosswell seismic data tied in with well tops from offset vertical wells. The 3D model was populated with high-tier petrophysical and geomechanical properties from the pilot well. The zones with high water saturations were identified in the subsurface, which gave an insight into the source of the produced water. Fully 3D planar fracture modeling was performed using the log data from the vertical offset well at the landing point of the horizontal well. Sensitivities were performed on various fluid systems, job volumes, and pump rates, and a playbook was created for real-time operations as part of a contingency plan.
Lateral measurements included petrophysical and geomechanical data, which were used to place perforations, within a stage, in similar type of rock. Depending on the real-time microseismic events, the stimulation design was changed on the fly. Stages with events that were growing out of the zone were modified first, and a final pump schedule was established after the first five stages.
The production results indicated a 20% decrease in water cut, which is a notable improvement compared to the historical production data in the San Andres. The workflow proved that the water production can be significantly reduced by applying a methodology that includes integration of data from multiple domains, thereby improving the economics of a well.
To investigate the effect of vesicular property on mechanical characteristics of basalts a series of uniaxial and triaxial compression tests were conducted for basaltic intact rocks sampled in the northeastern onshore and offshore, southeastern offshore and northwestern offshore of Jeju Island, South Korea. The uniaxial compressive strength and parameters used in the More-Coulomb failure criterion, namely cohesion and internal friction angle, estimated from the results of the uniaxial and triaxial compression tests were compared and analyzed with effective porosity, a parameter representing the vesicular property of basalts. The results demonstrate that the uniaxial compressive strength and cohesion with respect to the effective porosity can be classified clearly as two different non-linear regression curves in accordance with two different linear relationships between bulk specific gravity and effective porosity. As the effective porosity increases, the uniaxial compressive strength and cohesion decrease exponentially. On the other hand, the internal friction angle decreases gradually with the effective porosity, regardless of the relationships between bulk specific gravity and effective porosity.
Basalt is one of the most common rock types of volcanic lava area, and has a fine-grained mineral texture. In addition, basalt has various shaped and sized vesicles formed by dissipation of gaseous phases in lava decompressed in the process of erupting onto the surface of the earth or flowing on the surface.
Vesicular structures of basalt have important effects on the physical and mechanical properties of the intact rock itself as well as the stability of rock mass which are crucial for the design of diverse foundation structures, tunnels, and other projects.
There are many studies of the effects of vesicular property on the physical and mechanical properties such as permeability, uniaxial compressive strength, elastic modulus, Poisson's ratio and ultrasonic velocities of vesicular basaltic intact rocks (Kelsall et al., 1986; Kim and Choi, 1991; Kwon et al., 1993; Al-Harthi et al., 1999; Saar and Manga, 1999; Eum, 2002; Kim, 2006; Gates, 2008; Cho et al., 2009; Moon et al., 2014; Yang, 2014; Yang, 2015a; Yang, 2015b; Yang, 2016; Yang and Sassa, 2016). Most studies on the basaltic intact rock revealed the relationship between physical parameters representing vesicular property and mechanical characteristics estimated from the results of uniaxial compression test. There are, however, very few studies about the strength parameters, such as cohesion and internal friction angle, which can be estimated directly from the results of three or more triaxial compression tests on basaltic intact rocks.
The Middle-Triassic Gulailah Formation, also known as the Jilh Formation, was poorly understood in Abu Dhabi due to lack of data integration. A recent study involving mapping of the internal architecture of the formation on the basis of regional seismic data and all available wells across Abu Dhabi shows the evolution of an intra-shelf basin during deposition of the Gulailah Formation which was overlooked during previous studies.
Interpretation of regional mud logs and updated isopach maps show a deepening trend from a shallow shelf in the northwestern offshore Abu Dhabi to a depo-center in the southern onshore. The isopach contours imply an increase in water-depth toward the basin center and mark the outline of the Gulailah intra-shelf basin as a restricted depression on the Middle-Triassic to Middle-Jurassic shallow-water carbonate shelf. The basin margin is characterized by a shallow-water shelf break, where the sudden change in slope leads to a higher thickness gradient. The regional variation of seismic reflection patterns from prograding and thickening events around the shelf-break to parallel reflections at the depo-center characterize the general geometry of the Gulailah intra-shelf basin from basin margin to basin center. Detailed well correlations based on GR cycles corresponding to 3rd-/4th-order sequences show a layer-cake model at the bottom followed by a prograding sequence towards the top of the Gulailah, representing the evolution from a gentle ramp to an intra-shelf basin.
In the Lower Gulailah, laminated algae-related dolo-mudstone with desiccation cracks and intercalated anhydrite layers indicate a low-energy tidal flat environment in the northwest. The increase of sub-tidal lime-mudstone to the east and to the south indicates a deepening of the carbonate ramp system in those directions. Influenced by the Late-Triassic uplift of the Qatar Arch, the Upper Gulailah subsequently developed into an intra-shelf basin with a more confined accommodation space, where carbonate sediments gradually filled-up the basin as low-angle prograding ramps from the northwestern offshore to the southern onshore. At the base of the Upper Gulailah, low-GR grainy facies extend from the basin margin to the basin center, indicating a shoal-related depositional setting. Above this interval, prograding ramps are dominated by muddy facies, indicating a more restricted environment. Micro-conglomerates and breccia intercalated with thin layers of grainy shoal sediments reflect a peritidal dominated environment between the shelf-break and the basin center. Tight limestones with thin beds of shale representing a deep sub-tidal environment were deposited in the basin center.
Different from the well-known reef-originated Bab basin, the Gulailah intra-shelf basin is a consequence of tectonic activities. High-relief reefs are not developed due to highly-frequent clastic influxes and high salinity. The basin is characterized by low-angle prograding ramps, thickening towards the basin center, and gradually filling-up the shallow basin during a period of relatively stable sea-level.
Structural styles in the deep-water Gulf of Mexico are largely a function of the distribution of salt, its interaction with sedimentary depo-centers, the specific Gulf of Mexico linked system involved, and position in that linked system. Nearly basin wide coverage of high quality 3D seismic data coupled with existing regional 2D data has allowed interpretation of sub-salt structural features and assembly into a broad regional framework. We identify and characterize the following provinces and subsalt structural elements. 1) A deep salt basin and frontal salt napppe; 2) Perdido fold belt and Alaminos Canyon gravity minima; 3) Eocene and Miocene regional welds; 4) an "egg crate?? province of isolated primary depo-centers separated by older salt and younger mini-basins; 5) an area of amalgamated salt and linked primary depo-centers; 6) Mississippi Canyon/Atwater, and Spirit fold belts; 7) Sigsbee salt lobe and allochthonous carapace basins; and 8) "ramps?? between weld and canopy levels.
Jones, Emrys (Chevron ETC) | Latham, Tom (AOA Geophysics) | McConnell, Daniel Russell (U.S. Department of Energy) | Frye, Matt (U.S. Department of Energy) | Hunt, Jesse (U.S. Geological Survey) | Shedd, William (U.S. Geological Survey) | Shelander, Dianna (Rice University) | Boswell, Ray | Rose, Kelly | Ruppel, Carolyn | Hutchinson, Deborah R. | Collett, Timothy Scott | Dugan, Brandon | Wood, Warren
The Gulf of Mexico Methane Hydrate Joint Industry Project (JIP) has been performing research on marine gas hydrates since 2001 and is sponsored by both the JIP members and the U.S. Department of Energy. In 2005, the JIP drilled the Atwater Valley and Keathley Canyon exploration blocks in the Gulf of Mexico to acquire downhole logs and recover cores in silt- and clay-dominated sediments interpreted to contain gas hydrate based on analysis of existing 3-D seismic data prior to drilling. The new 2007-2009 phase of logging and coring, which is described in this paper, will concentrate on gas hydrate-bearing sands in the Alaminos Canyon, Green Canyon, and Walker Ridge protraction areas. Locations were selected to target higher permeability, coarser-grained lithologies (e.g., sands) that have the potential for hosting high saturations of gas hydrate and to assist the U.S. Minerals Management Service with its assessment of gas hydrate resources in the Gulf of Mexico.
This paper discusses the scientific objectives for drilling during the upcoming campaign and presents the results from analyzing existing seismic and well log data as part of the site selection process. Alaminos Canyon 818 has the most complete data set of the selected blocks, with both seismic data and comprehensive downhole log data consistent with the occurrence of gas hydrate-bearing sands. Preliminary analyses suggest that the Frio sandstone just above the base of the gas hydrate stability zone may have up to 80% of the available sediment pore space occupied by gas hydrate.
The proposed sites in the Green Canyon and Walker Ridge areas are also interpreted to have gas hydrate-bearing sands near the base of the gas hydrate stability zone, but the choice of specific drill sites is not yet complete. The Green Canyon site coincides with a 4-way closure within a Pleistocene sand unit in an area of strong gas flux just south of the Sigsbee Escarpment. The Walker Ridge site is characterized by a sand-prone sedimentary section that rises stratigraphically across the base of the gas hydrate stability zone and that has seismic indicators of gas hydrate.
The Gulf of Mexico Methane Hydrate JIP is a consortium of energy and service companies, as well as government organizations, that began collecting data and performing research on marine gas hydrates in the Gulf of Mexico (GOM) in 2001. The project is sponsored by both the JIP members and the US Department of Energy (DOE). The last few decades have seen considerable interest in gas hydrates from both a resource perspective and the standpoint of potential seafloor stability concerns for conventional deepwater operations. Addressing either of these issues requires obtaining fundamental data on the properties of gas hydrate-bearing sediments, the formulation of predictive models for gas hydrate distribution and concentration, an understanding of wellbore and formation stability in gas hydrate-bearing sediments, and the development of methods to analyze existing and new data to infer gas hydrate concentrations.
Abbott, David (Microseismic Inc.) | Neale, R. Christopher (MicroSeismic Inc) | Lakings, James (MicroSeismic Inc) | Wilson, Lynn E. (Chevron Corp.) | Close, Jay Charles (Chevron Corp.) | Richardson, Evan (Chevron Corp.)
A surface microseismic array was utilized to perform hydraulic fracture diagnostics during stimulation of the Chevron Skinner Ridge (SR) #698-22-1 well, Williams Fork Formation (Late Cretaceous), Garfield County, western Piceance Basin, western Colorado. Production from very low permeability Williams Fork gas sandstones requires fracture stimulation to enhance wellbore-to-reservoir connectivity. The use of surface microseismic monitors without borehole equipment in downhole configurations represents a relatively new and untested technology for hydraulic fracture diagnostics. Analysis of the surface microseismic data was carried out for five (5) hydraulic fracture stages to: (1) determine the applicability of the surface microseismic approach in the absence of an offset observation well; and (2) characterize fracture height, azimuth, length and symmetry with respect to rock properties.
Hydraulic fracture stimulations to date at SR have encompassed limited entry "waterfrac?? treatment techniques. The hydraulic fracture characteristics were interpreted to document possible influences that natural fractures, horizontal stress trends and sandstone channel orientations may have had on hydraulic fracture emplacement. The Williams Fork Formation at SR contains natural fractures, and the primary open natural fracture sets strike generally east-west. Healed natural fracture sets strike generally northwest-southeast. The current principal horizontal stress trends are roughly east-west. The fluvial Williams Fork sandstone bodies have highly variable orientations due to meandering and braided stream depositional origins, but many channels trend roughly east-west and northwest-southeast. The SR #22-1 well is located in a deep and relatively narrow (1-2 mi wide) north-northwest-south-southeast trending valley roughly 2,000 ft below the adjacent "mesa?? tops, which is an important geomechanical consideration.
The surface microseismic data were of sufficient quality to enable successful interpretations of hydraulic fracture geometries. The hydraulic fracture stimulations were emplaced progressively uphole between 5,298 to 3,372 ft measured depth. The deeper stages grew mainly along east-west and northwest-southeast orientations, and the upper stages formed largely along northwest-southeast orientations. All stages showed asymmetric geometry. The lower stages may have been influenced by the northwest-southeast sandstone body and healed natural fracture orientations, along with east-west sandstone body, primary open natural fracture and horizontal stress directions. The upper stages may have been more influenced by the northwest-southeast sandstone body and healed natural fracture orientations, and topographic effects. Additionally, during some stimulation treatments, shallower stages appeared to be in vertical communication with previous deeper stages. A possible tectonic fault that had not been mapped due to widely spaced well control may have further influenced hydraulic fracture growth in one stage.
Introduction / Purpose of Study
The purpose of this paper is to present a case study of a passive surface emission tomography (PSET®) microseismic experiment conducted in a well in the Williams Fork Formation, Piceance Basin, western Colorado. The Williams Fork is widely recognized as a classic Western Interior USA low permeability ("tight??) gas sandstone (TGS) play, and is being actively developed by a host of major and independent companies. Chevron amassed approximately 100,000 acres of fee land over many years at "Skinner Ridge?? (SR) in Garfield County, centered roughly 15 mi northwest of Debeque, at the time for the vast oil shale resource potential. The TGS potential at SR has been known since the late 1980's, partly as a result of tests of the coal gas potential in six (6) wells in the Cameo coal zones at the base of the Williams Fork Formation. A combination of recent price, technology, and portfolio drivers resulted in a 14-well Williams Fork delineation program at SR in summer 2005 through summer 2006. The delineation well production rates, decline curve profiles and estimated ultimate recoveries (EUR's) satisfied economic hurdles, and planning for full field development starting in mid-2007 was authorized.