Jones, Drew (Deep Imaging) | Pieprzica, Chester (Apache Corporation) | Vasquez, Oscar (Deep Imaging) | Oberle, Justin (Deep Imaging) | Morton, Peter (Deep Imaging) | Trevino, Santiago (Deep Imaging) | Hickey, Mark (Deep Imaging)
We used a new, large-scale, surface-based, controlled-source electromagnetics (CSEM) approach to map the locations of frac fluid during flowback following a three-well hydraulic fracture stimulation in the Permian Basin. CSEM records and analyzes electric field signals induced in the electrically conductive frac fluids by a surface-based transmitter. For this study, we placed a grounded dipole transmitter directly above the central horizontal well of three parallel neighboring wells. The transmitted signal was a broadband pseudo-random binary sequence. To record the frac fluid response signal, we placed an array of 161 receivers on the surface covering the three horizontal wells. We recorded the induced, response signals of the flowback fluids in three-hour intervals (three on, three off) for 228 hours. The CSEM recording started eleven days after flowback began on the central well and four days after flowback began in the two outer wells. From this time-lapse recording we captured the spatial and temporal change in electrical conductivity within the fractured reservoir, allowing us to infer the location of flowback fluid and its movement. During the stimulations chemical tracers had been included in the frac fluid. Analysis of the tracers captured during flowback agreed well with the mapped fluid locations and movement found in the CSEM data.
Flowback monitoring and its interpretation offer another valuable tool for frac and reservoir engineers. This understanding is especially critical in developing and managing unconventional reservoirs. Here, the stimulation responses are not simple, more and more evidence show complex fracturing and complex fracture networks (e.g., Rassenfoss, 2018). Characterizing a fracture network or networks in shale (i.e., an unconventional reservoir) is a challenging task. It is complicated by multiphase and complex flow regimes, non-static permeability and porosity, natural fracture and flow systems, heterogeneities and complex stress, changing stress with production, liquid loading, and a host of operational concerns (Zolfaghari et al., 2016). In the past, to determine hydraulic fracture properties, operators used production data in a variety of models to manage wells and reservoirs. Garnering production data can take months or even years delaying, for example, upgrades to well and stimulation designs and designing infill drilling (Williams-Kovacs, Clarkson, & Zanganeh, 2015). In contrast, a flowback occurs during the transition between stimulation and bringing the well online. Understanding the flowback provides significant improvements in determining early production rates enabling estimates of the effective size of stimulations, distinguishing key reservoir properties, and predicting long-term production rates (Jacobs, 2016). In addition, there can be direct savings if, for example, flowback interpretation identifies an underproducing play in time to redirect funds into a more lucrative play before infill drilling (Williams-Kovacs et al., 2015).
Hickey, Mark (Deep Imaging Technologies) | Vasquez, Oscar (Deep Imaging Technologies) | Trevino, Santiago (Deep Imaging Technologies) | Oberle, Justin (Deep Imaging Technologies) | Jones, Drew (Deep Imaging Technologies)
Controlled Source Electromagnetics (CSEM) is used to monitor and image a three well zipper frac operation. We examine the interaction between the completions operation and a fault zone at reservoir depth.
Using two grounded dipole transmitter lines and 350 receiver locations, 27 frac stages were monitored in the Anadarko basin for three horizontal wells. Our broadband signal is transmitted before the start of the frac stage, during the frac stage, and after the frac stage is completed. This allows us to establish a baseline image prior to the start of the frac stage and to generate a response throughout the frac. The electromagnetic data collected provides a direct measurement of the conductivity change in the subsurface caused by the hydraulic fracturing process and from this we infer fluid movement.
This case study presents the effects of a fault at reservoir depths that is intersected by the three wells and examines the possible effects of formation heterogeneities on frac fluid migration. Images produced by our CSEM method illustrate the lateral extent of the fluid, fracture azimuth, and identify reservoir heterogeneities. In addition, unlike microseismic, the CSEM method records signal generated from fluid flow in natural fractures as well as those fractures created by hydraulic pressure. As a result, CSEM allows us to infer fluid propagation and location to gauge frac behavior near and away from the fault where the fault zone is seen possibly acting as a sink and barrier. CSEM monitoring of a frac operation not only serves as a tool for monitoring and fracture diagnostic, it can also be used to identify geologic controls that can affect reservoir stimulation.
Akinnikawe, Oyewande (Texas A&M University) | Chaudhary, Anish (Texas A&M University) | Vasquez, Oscar (Texas A&M University) | Enih, Chijioke (Texas A&M University) | Ehlig-Economides, Christine A. (Texas A&M University)
Previous studies have shown that bulk carbon dioxide (CO2) injection in deep saline aquifers supplies insufficient aquifer storage efficiency and causes excessive risk because of aquifer pressurization. To avoid pressurization, we propose to produce the same volume of brine as is injected as CO2 in a CO2/brine displacement. Two approaches to CO2/brine displacement are considered--an external brine-disposal strategy in which brine is disposed of into another formation such as oilfield brine and an internal saturated brine-injection strategy with which the produced brine is desalinated and reinjected into the same formation. The displacement strategies increase the storage efficiency from 0.48% for the bulk-injection case to more than 7%. A conceptual case study with documented aquifer properties of the Woodbine aquifer in Texas indicates that the available volume is sufficient to store all the CO2 being generated by power plants in the vicinity for approximately 20 years only. However, the CO2/brine displacement increases storage efficiency enough to store the CO2 produced for at least 240 years at the current rate of coal-fired electric-power generation. Sensitivity analyses on relative permeability, permeability, and temperature were conducted to see the effects of these reservoir parameters on storage efficiency.
For bulk injection, increased permeability resulted in increased storage efficiency, but for the CO2/brine-displacement strategies, decreased permeability increased storage efficiency because this resulted in higher average pressure that increased CO2 storage per unit of pore volume (PV) and increased CO2 viscosity. Also, storage efficiencies for the displacement strategies were highly sensitive to relative permeability. There is an optimal CO2-injection temperature below which the formation-fracturing pressure is lowered and above which CO2 breakthrough occurs for a smaller injection mass. The CO2/brine-displacement approach increased capital expenditures for additional wells and an operating expense for produced-brine disposal, but these additional costs are offset by increased CO2-storage efficiency at least 12 times that achieved by the bulk-injection strategy.