This paper describes a comprehensive field study of eight horizontal wells deployed in the stacked Niobrara and Codell reservoirs in the Wattenberg Field (Denver-Julesburg Basin). The overall goal was to understand the geometry of the hydraulic fractures (propped) and the producing volume with respect to completions design, target reservoirs, and well spacing. Through this understanding, the asset can be developed more effectively and economically.
The Wattenberg Field is a basin-center petroleum accumulation located northeast of Denver, from which hydrocarbons have been extracted over the last 50 years. Development in the Wattenberg Field began in 1970 from vertical J‑Sandstone wells, with production of the Niobrara following in 1976. In 2009, horizontal development began in the Niobrara formation. The Upper Cretaceous sequence from Codell to Niobrara is the current focus of horizontal development in the Wattenberg Field.
A robust 3D mechanical Earth model (MEM) provides the framework for data integration and physical simulations. In this work flow, the MEM calculates or approximates a number of input parameters. Each of these variables is defined both spatially and stratigraphically and is housed in a 3D geocellular model. Because many of the input calculations are dependent on other variables, a set of variable relationship definitions keeps the model dynamic so that, during the tuning process, all initially established data relationships are honored.
Initially, properties are calculated basinwide on a coarse resolution that is later enhanced locally around data-rich pilot sites for simulation. Regional distributions of mechanical rock properties are calculated from dipole-sonic logs and compared with core measurements to determine static values of Poisson’s ratio and Young’s modulus. Relationships between the dipole-sonic curves and triple-combination logs are determined to distribute the properties across the basin widely and produce maps of Poisson’s ratio and Young’s modulus, both spatially and stratigraphically. Pore pressure is mapped with interpretations from diagnostic fracture injection tests (DFITs) along with maximum mud weights from horizontal wells. Because of the widespread presence of existing vertical wells, it is important to determine whether the DFIT represents virgin pore-pressure conditions. The maximum-horizontal-stress orientation is determined from six-arm-caliper and full-bore formation-microimager logs. The vertical-stress magnitude is obtained by integrating a bulk-density log from the surface downward. The minimum horizontal stress is calculated spatially with a poroelastic stress equation and calibrated with DFITs. Use of DFIT interpretations of closure stress along with spatial and stratigraphic grids of Young’s modulus, Poisson’s ratio, and pore pressure make it possible to solve for the tectonic strain variable at the location of each DFIT. In this work flow, the horizontal-stress anisotropy remains as a tuning parameter during the geomechanical simulation. Petrophysical analysis of grain density, bulk-density logs, and clay volumes allows for the calculation of a derived effective-porosity log that is mapped regionally and stratigraphically. Porosity/permeability relationships are established from core and used to calculate a derived permeability; however, permeability is used as a significant tuning parameter during the production-history match. Last, a description of the discrete natural-fracture network (DFN) is obtained by use of both formation-microimager logs and outcrop maps....
Understanding Completion Performance: Software-Guided Work Flows and Models
15 August 2016