This paper demonstrates how multiple diagnostics, when applied effectively, can help accelerate the learning curve in an area and optimize field development. The operator can obtain exceptional knowledge concerning which technologies to choose when targeting specific issues for future developments. The project involved a wine-rack of wells completed in Niobrara A, B, and C benches. Learning objectives for this project included the completions order, height growth in various benches, well spacing, well lateral landing, effect of varying treatment type and size, and cross-well communication. An extensive survey was performed of the various diagnostics available for fracture mapping, which included both near-wellbore (NWB) and far-field diagnostics. Keeping the primary learning objectives in mind, a project matrix was developed incorporating a variety of diagnostics focused on specific objectives. Inferred vs. direct measurement from diagnostics was considered. This process of "design of experiment" is discussed. The wells on the pad were all hydraulically fractured, and then the entire pad was moved to production phase post the hydraulic fracturing operations. Different fracturing fluids were also evaluated as part of the experiment. The final project included far-field diagnostics, such as downhole microseismic, downhole fracture height, surface microdeformation, and interferometric synthetic aperture radar (inSAR), and NWB diagnostics, such as permanently installed fiber optics and radioactive (RA) tracers. The analysis was performed on individual diagnostics independently, and subsequently combined interpretations led to better subsurface understanding. Additionally, surface microdeformation data provided significant insight into the effects of "zipper fracturing" and how the treatment order of the wells was important for optimization. With all data available, a fracture model history match on the permanent fiber optics well was constrained to the measured diagnostics. The final match between the aerial deformation from the surface tilt and calibrated fracture model was excellent and is discussed further. Understanding the actual hydraulic fracture geometry is important in any unconventional field development because it dictates the stimulated reservoir and drainage patterns. While understanding the effects of various parameters (treatment type, fluid type, stage lengths, number of perforation clusters, etc.) on fracture geometry is essential, it is also important to understand the effect of multiple wellbores on a well pad.

Since its commercialization in 1949, hydraulic stimulation has been used on thousands of wells worldwide to increase hydrocarbon production. There are some areas where hydrocarbon production would not be economically viable without this process. The application of hydraulic stimulation has become even more critical when trying to produce hydrocarbons from unconventional reservoirs, such as coalbed methane, shale, and tight gas sands. Throughout the oil and gas industry, hundreds of millions of dollars have been spent by operators and service companies to develop stimulation-fluid systems that increase proppant-carrying capacity and minimize formation damage. The base fluid has run the gambit of oil, water, foam, alcohol, and sometimes a combination of these. Fluid selection can have a direct bearing on how much proppant can be placed in the formation of interest and have a direct impact on the economics for the operator. In some areas, the associated cost of hydraulic stimulation can be as much as 50% of the overall cost of drilling and completing a well. Because unconventional reservoirs have become more important in the oil and gas industry, fluid selection has become even more critical because of the nature of the reservoirs. Recently, there has been a change within the industry from using crosslinked gelled-fluids to water systems that use a friction-reducing additive as the fluid of choice when completing wells in unconventional reservoirs, specifically tight-gas sands. These fluid systems are referred to as slickwater. This paper describes a case history of comparing production data from wells stimulated using crosslinked fluid systems to slickwater fracs in an effort to determine which fluid system gives the best production from an economic standpoint. This paper compares wells from several different operators in the Natural Buttes field, located in northeastern Utah, that were stimulated from 2005 through 2007. Introduction Unconventional reservoirs such as tight-gas sands, have become more important to the oil and gas industry, and the selection of stimulation fluids has become more critical to the overall production of these reservoirs. Tight-gas sands are typically defined as gas-bearing reservoirs with extremely low-permeability formations, typically = 1 md (Kasemi et al. 1982). Formations with permeabilities less that 10 md need to be hydraulically stimulated to be economical. Historically, most hydraulic fracturing treatments used gelled fluid with a crosslinker to create a subterranean fracture to carry and place a proppant within the fracture (Harris et al. 2005). In recent years, the use of slickwater (SLW) fracs as the hydraulic stimulation treatment in these tight gas sands has increased in popularity. In this paper, a SLW frac is defined as being a treating fluid that uses water as a base fluid, with no type of gelling agent to act as a viscosifier. However, some type of friction reducer (FR) material is normally incorporated into the fluid system to reduce wellhead treating pressures during the stimulation treatment. FR products typically provide little or no increased viscosity to the base fluid; therefore, fluid viscosities are typically around 1 to 2 cp. Gelled fluids, on the other hand, normally contain some type of polymer added to the base fluid, typically water, which greatly increases the viscosity of the fluid. The base viscosity of gelled fluids used in this study ranged from around 15 to as high as 25 cp. Once the base-fluid rheology was increased to the required viscosity, a crosslinker was typically added that increased the viscosity as much as 25 times that of the initial base-gel viscosity. The primary purpose of using a gelling agent and then crosslinking it is to increase proppant-carrying capacity, not only for fracture length, but also increased proppant concentration placed in the fracture itself. The gelled fluids for hydraulic stimulation wells in this study were all crosslinked fluids and will be referred to as XLK throughout the remainder of this paper.