As longer laterals are drilled in the Utica to maximize acreage cover, the stimulation treatments must still establish high pumping rates to effectively treat multiple clusters even within the stages out near the toe area of the lateral. Overcoming this additional pipe friction as well as using various water sources of varying salinity (up to and including 300,000 ppm) with only one friction reducer (FR) polymer product is now possible. An additional benefit of this new salt-tolerant polymer (STP) as the FR additive is its ability to self-degrade with time and temperature to provide significant viscosity reduction for improving well cleanup after the treatment. This paper discusses use of this new STP to successfully place 131 stages in the Utica on a three-well pad in Ohio using various percentages of brine water with the freshwater supply. This is contrasted with traditional FR and guar used in 61 stages on the same pad and 39 stages on an offset pad. The ability to continue operations in the subfreezing temperatures of winter, coupled with the ability to reuse produced water, provides additional benefits to field operations. The use of a single component STP as the friction reduction provider also reduces inventory stock and simplifies on-location quality assurance of material usage. Analytical production simulation confirms improvement in productivity index (PI) and estimated ultimate recovery (EUR) forecast.
Throughout multiple shale plays, high viscosity friction reducers (HVFRs) have successfully placed more proppant mass with lower treating fluid volume; thus, the industry is accelerating adoption of these treating fluids. Previous published studies have included treatments in Bakken shale and Permian Basin formations. The characteristics of the Marcellus shale make it particularly beneficial to minimize water and gel injection into the formation. At the same time, operational constraints related to smaller footprint and pad sizes in the Marcellus region make it beneficial to reduce gel hydration equipment on location. In spite of these potential benefits, application of high viscosity friction reducers has only recently begun in the Marcellus region. One factor delaying the introduction of HVFRs into the Northeast has been the challenging waters and brines often used in treatments. This study documents the successful introduction of a brine tolerant, high viscosity friction reducer with multiple operators in the Marcellus region. Marcellus operators compared several different friction reducer chemistries through field trials on multiple pads. Based on measurements of surface treating pressure and proppant placement, an optimum fluid system was selected that is effective in a range of water qualities and allow increased pump rate. The friction reducer was also compared to conventional gel technology based on the same method. The brine tolerant friction reducer was found to be an effective replacement for linear gel fluids and allowed reduction of equipment on location. A brine tolerant, high viscosity friction reducer enabled treatments to be placed with increased sand loadings, higher pump rates, and decreased surface treating pressures. The fluid system was able to work with a variety of water conditions, including brines having more than 30,000 ppm chlorides. In one case the new fluid system allowed operations to entirely move away from gel chemistry and surface hydration equipment. The study presents measured results during the frac on one of the first applications of a high viscosity friction reducer in Marcellus shale treatment.
The Dry Utica play is an exciting unconventional gas development currently unfolding in the Appalachian Basin. Published results for several wells exceed an average Initial Production (IP) rate of 60 MMcf/day. However, complexities in the reservoir can make the developmental learning curve steep. Challenges include true vertical depths (TVDs) of 9,000 to 13,500 feet, pore pressures of 0.8 to 0.99 psi/ft, and bottom hole temperatures of up to 240 degrees Fahrenheit. In addition, the reservoir has high stresses, high closure pressures, complex and varying mineralogies. Among the greatest challenges in Dry Utica field development is cost effective proppant and frac fluid design and selection. In order to achieve an adequate return on investment: Proppant design has to be optimized to withstand high pore and closure pressures and overall high stresses, but also be cost effective.Frac fluid design has to be compatible with varying mineralogies to avoid a steep decrease in fracture conductivity. This paper discusses field testing of proppant design and selection and how cost, geological, reservoir, and rock properties affect the completion design and well production. The paper will also review frac fluid design used for proppant transportation and placement, and potential issues with formation mineralogies, as well as mitigation. Field case histories with managed production draw down and how that can affect proppant inside a fracture will also be reviewed.
This paper discusses a well-to-well spacing test on a 5 well pad in the Utica Shale that was stimulated with a unique stage sequencing plan. The stage sequencing plan provides an improved understanding of the way that fracture growth can be influenced by subsurface pressure differentials created by newly fractured, shut-in and depleted wells. Chemical (water) tracers and oil tracers were pumped into the center well of the 5 well pad. The non-traced wells on the pad, along with 2 wells on an adjacent pad, were all sampled during flowback and production. The samples were analyzed for the presence of oil and chemical tracers to determine the extent and degree of well-to-well communication. Additionally, surface microseismic data was collected and used to further assist in the study of the fracture growth. The tracer communication and microseismic data were represented together in a 3D visualization of the well pads. Generally, the tracers and microseismic events show that there is more extensive fracture growth from a treatment well to offsetting wells when there is no hydraulic pressure barrier between them. Better fracture containment and symmetry was observed on stages that were bounded on both sides by wells that were just fractured. Data from the study show that proper sequencing of the completions can mitigate the tendency for fractures to preferentially grow towards depleted wells. The study will therefore illustrate the value of tracer and microseismic data for understanding additional or new knowledge about multi-well pad stage sequencing and its role in fracture growth, and overall future well planning strategy.
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