A Denver-Julesburg (DJ) Basin operator, Anadarko Petroleum Corp., has had success with the optimization of its completions in the Codell formation. The use of a microemulsion additive (ME) is one of the keys that has allowed them to further improve production and increase reserves.Before the ME surfactant, the operator used a non-emulsifier (NE) as a surfactant in their stimulation treatments. By replacing the surfactant with the ME, their median production has increased by 10%. In addition, lower GOR wells show the most benefit from the use of the ME additive, meaning that margins on wells in lower GOR areas can be improved. Anadarko began testing the ME additive in 2005 while still completing some Codell wells with the NE. After review, the ME additive was run almost exclusively.This paper compares the wells using ME to those using the conventional NE surfactant. The study wells were chosen to minimize potential production effects caused by other factors, such as job size and depletion. After eliminating these other factors, the sample size consisted of 32 NE wells and 34 ME wells across the basin. The wells were compared on a broad scope and where possible, offset wells were compared.

Since the discovery of the Jonah field in 1977, many styles of hydraulic fracturing treatments have been employed to stimulate the Lance formation. Commercial production was not established in the field until the early 1990s, and technological improvements have permitted increased production since that time. Further trials of fracturing techniques, including slickwater fracs, induced stress diversion, and flow-through composite fracture plugs, continued over time. Since March 2010, channel fracturing treatments have been employed in the Lance formation in conjunction with more traditional, conventional fracturing treatments. For the purpose of this paper, conventional fracturing treatments consist of either crosslinked gel or slickwater fracturing treatments. The proppant is added in a continuous manner with an increasing proppant concentration. For crosslinked gel treatments, the typical proppant is 20/40 -mesh white sand added up to a maximum of 6 lbm/gal. For the slickwater treatments, the typical proppant is 40/70- or 30/50- mesh white sand added up to a maximum of 3 lbm/gal. The channel fracturing treatments use a pulsed method of adding the proppant to the fluid. Instead of adding the proppant continuously, the proppant is turned on and off in approximately 15-second time intervals. This concept is intended to provide high-conductivity, unpropped open flow paths through hydraulic fractures held open by the proppant pillars. To assess the effectiveness of the channel fracturing method in the Jonah field compared to conventional fracturing treatments, a spatial sampling technique was used. Spatial sampling is a documented method for comparing large groups of wells with their direct offsets. The original intent of the spatial sampling method was to identify underperforming wells; however, the method has also been employed as a way to compare various completion or stimulation techniques. In this case, spatial sampling was applied in an attempt to evaluate the effectiveness of the channel fracturing technique compared to conventional fracturing techniques using continuous proppant addition during the treatment. Five discrete areas of the Jonah field were included in the study. Only wells completed in the same time frame as the channel fractured wells were included. The treatment and production data for all wells were obtained from public sources. There might also be differences in production among the conventionally fractured wells, depending on whether a crosslinked or slickwater treatment was used; however, the effect of slickwater treatments, as opposed to crosslinked treatments, was not considered in this study.

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.

There have been extensive efforts to recover oil from the Bakken formation in North Dakota since it was discovered in 1951. However, these efforts were not particularly profitable until the 2000s when horizontal drilling and large, multistage hydraulic fracturing treatment methods were used. The new drilling and completions methods created a substantial increase to production, which escalated throughout recent years and created a demand for better, more efficient completions. One major component of these completions is the base fluid used for hydraulic fracturing treatments. This paper compares hydraulic fracturing treatments of a new, residue-free (res-free) hydraulic fracturing fluid to all other fracturing fluid treatments.The res-free fluid system was presented in 2012 as a premier fracturing fluid and economic alternative to guar-based systems to increase the resultant fracture conductivity. Since 2012, more than 40 wells have been completed in either the Bakken or Three Forks formations of North Dakota using the res-free fracturing fluid. While initial cost savings were realized, the production results from these wells have not been extensively studied. This paper presents the findings of a study comparing production from wells treated with res-free fracturing fluid to wells treated with other hydraulic fracturing fluids.Because the wells completed using the res-free system are widespread throughout North Dakota and belong to several different operators, choosing a specific study area was challenging. To overcome this challenge, a spatial sampling technique was used. Spatial sampling is a method for comparing a large group of wells to their direct offsets. For this study, spatial sampling was applied to compare wells completed using the res-free system to wells completed using other fluids. To normalize general completion methods, only wells completed since the beginning of 2012 are included in this study. Offset wells for this study are those within a 1-mile radius from the center well. The production data for all wells was obtained from public sources. The proppant amount and total fluid volumes were normalized per foot of lateral to minimize variables. Other factors, such as drilling placement, type of proppant, type of fluid, or compartmentalization can affect production; however, these effects are not considered during this study.

In low-permeability formations, natural fractures, fissures, and other geologic heterogeneities are important considerations in the design of hydraulic-fracture treatments. In some formations, it is considered beneficial to capitalize on these conduits to establish a greater network of connection to the reservoir. In the Bakken shale, near Westby, Montana, a simple planar fracture was desired because complex fracture growth could result in connectivity to a zone of nonproductive interest and led to the following issues:• Higher rates, which could result in extreme fracture complexity and limited fracture extension.• Inability to effectively place proppant for conductivity.• Excessive fluid leakoff caused by high net pressures requiring large pad volumes.• Connection to water-producing zone.• Less aggressive proppant schedule because of likelihood of screenout.• Increased cost, footprint, personnel, and equipment on location.With an understanding of the formation-rock properties, stresses, and the natural fracture system, the treatment design parameters were established to help ensure lower treatment pressures and optimum fracture extension in the zone of interest. This paper presents the successful execution of a multi-interval fracture-stimulation treatment for a long-lateral horizontal completion in the Bakken shale using a state-of-the-art hybrid coiled-tubing (CT) system and hydrajet-assisted fracturing (HJAF) technology. The new approach incorporated the following technology:• Low-rate treatment schedule.• Multiple-fracture stimulation treatment.• Aggressive proppant-treatment schedule.• Higher gel viscosity to encourage desired fracture growth and proppant transport.• Hydrajet perforating.• Dynamic fluid diversion to isolate treatment to intended zone.• State-of-the-art hybrid CT system.