Hydraulic fracturing has proved to be one of the best technologies to improve productivity from tight gas wells. In such low-permeability reservoirs, careful consideration must be given to fracturing fluid selection. Some reservoirs are underpressured and require the use of energized fluids, while others are sensitive to water-based fluids because of clay swelling and migration.Proppant pack damage because of gel residue is one of the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and maximize production, a new premium, highly efficient fracturing fluid was developed. This premium system incorporates low-polymer-loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep-well fracturing and coiled-tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide (CO 2 ) and nitrogen (N 2 ) or may also be used in binary foam systems. This paper will provide details on the new fracturing fluid system, in terms of proppant pack cleanup, rheological properties, and fluid loss, as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop, fluid leakoff testing, proppant pack conductivity, and regain permeability evaluations are presented.Field case histories will evaluate fracturing treatments using new fracturing fluid and comparable treatments using conventional fluid. Normalized production data of the treated wells of both systems are also compared.

Restimulation of wells completed in the Codell formation, a tight gas sand, has proven to be successful in the Wattenberg Field in Colorado. Beginning in 1997, Codell refracturing evolved into a massive program involving hundreds of wells per year. To date, HS Resources has restimulated over 750 Codell wells, increasing reserves and resulting in a project ROR of 100% with finding costs below $4.23 per barrel oil equivalent. This is a case study of the program conducted by HS Resources. This paper summarizes the refrac program, and its evolution, since its inception. The candidate selection process is examined, as well as geological and operational considerations when restimulating old wells. The evolution of stimulation treatments and fluids are also investigated. The use of 3D fracture simulations, run in real-time during the refracture treatments, and their results are discussed. Finally, both economic and production results are presented. Introduction Fracture treatment fluids and designs have varied greatly since the full-scale development of the Codell zone in the Wattenberg Field of northeast Colorado (Figure 1) began in 1981. Initially, small sand volumes and a variety of fluids were used to complete the Codell zone. With the improvement of frac fluids and placement techniques in the 90's, frac treatment designs changed dramatically towards larger sand concentrations and higher pump rates. Furthermore, with the trend towards completing the Niobrara in addition to the Codell, cost cutting techniques such as limited entry completions were employed. This technique controls the anticipated placement of the frac treatment by the number of perforations shot across each interval. In many of these wells, there are only 4 to 6 perforations in the Codell zone, which has been shown to be the most prolific reservoir of the two in most areas of the field. Varying degrees of effectiveness have been demonstrated by the historical evolution of frac design and placement. Current fracture modeling has shown that the techniques discussed above can limit the induced fracture lengths in the Codell, and thereby, negatively affect the production performance of the well. Operators in the Denver-Julesburg (D-J) Basin discovered, as early as 1989, that restimulating wells with small or ineffective original treatments yielded impressive and sometimes dramatic results. In June 1997, HS Resources began their refrac program. General Geology In the Wattenberg Field, the Codell Sandstone (Figure 2) is a highly bioturbated marine bar-margin deposit, flanking a central bar facies to the south. Moderately low depositional energies and considerable authigenic alteration of feldspar and rock fragment grains have sourced clay contents as high as 30% in some portions of the field. These interstitial clays exhibit grain-coating, pore-lining and pore-occluding habitats, often reducing permeabilities below 0.1 md, although porosities range from 10 to 25%. As a result, hydraulic stimulation is used to establish high permeability fairways (hydraulic fractures) that connect larger cross sections of low permeability matrix and micro-fracture networks to the wellbore. Regionally, the Codell Sandstone in the central portions of Wattenberg Field contains unique reservoir characteristics and is bounded by multiple trapping factors. Reservoir pinchouts to the south, southeast and northeast of Wattenberg, regional basement faulting to the west and north and corresponding porosity and permeability reductions toward these features help create an effective regional oil and gas trap within the Codell in the central field area. Correspondingly, the central field area contains the greatest maximum porosity and permeability reservoir in the Codell play, with the highest GOR's, exceeding 15,000 scf/bbl. All of these factors mutually overlap to create an overpressured cell in the Codell reservoir in the central field area (Twps. 3 to 5N, Rgs. 65 to 66W). Pressure gradients range from about 0.445 psi/ft, on the flanks of the field, to a maximum of 0.669 psi/ft in the center of the overpressured cell.

Since the early 1970s, fracturing fluid systems utilized in the J-Sand treatments in the Wattenberg field have ranged from poly emulsion to cross link gels with and without an inert gas phase (e.g. N2, CO2). Current treatments typically consist of large proppant volumes and crosslinked fluid volumes (e.g. 500,000 lbs and 7,000 barrels). Large treatment volumes results in large job costs for the well operators who have searched for ways to reduce treatment costs without sacrificing well production. Also in early 2000, large treatments were resulting in poorer productive J-Sand wells due to suspected pressure depletion. In 2002, one well operator in the Wattenberg field implemented an alternative method to stimulate the J-Sand:substituting the slick water based fluid for the massive crosslinked gel based fluid andreducing the proppant volume by as much as 4.5 fold. This strategy reduced job costs significantly without impacting ultimate gas recovery. At the end of 2002, the well operator completely switched over to the slick water treatments (SWT) for the J-Sand interval. By lowering the completion costs of a J-Sand well, many additional wells will be drilled that otherwise would not be economic. In this paper, the production from eight J-Sand wells stimulated with SWT will be compared to the 15 offsetting wells stimulated with crosslinked gel treatments (CGT).Production analysis methods will be utilized to determine reservoir and fracture flow capacity (e.g. drainage area, kh, effective fracture half length) for the wells considered in this case study. Also, treatment pressure history matching will be performed for selected wells to evaluate the resultant fracture geometry of the different styles of treatments. Introduction Field Description. The Wattenberg field is located 25 miles north of Denver, Colorado (Figure 1). The field encompasses 980 square miles in Boulder, Broomfield, Weld and Adams counties in the western portion of the Denver Julesberg (DJ) Basin. To date, in the Wattenberg field, the J-Sand formation has produced over 14.0 TCF of gas and 42.66 million barrels of oil. Typical well spacing in the Wattenberg field was 160 acre spacing for all wells until 1998. The Greater Wattenberg Rule (318A), effective in May of 1998, permitted up to ten Cretaceous wells per 320 acre block. This allowed Operators to deepen a 7,100-foot Codell well bore just +/-500 feet to the J-Sand for a fraction of the cost of drilling a grassroots well. Because of the Rule, many Operators in the Wattenberg field began a J-Sand infill drilling program. Typically, operators are infill drilling at a density of five J-Sand wells per 320-acre unit[1]. The challenge to the infill drilling of J-Sand wells by the operators was now two-fold:continue with economical fracture treatments on the increased number of J-Sand wells andcontinued economic J-Sand production from a formation that has been productive since the early 1970s. Geology The J-Sand formation in the Wattenberg field is classified as a "tight" gas sandstone of Cretaceous age. The J-Sand comprises the upper portion of the Dakota Group in the Wattenberg field. The lower contact (gradational) is with the marine shales of the Skull Creek formation. The upper contact (sharp and erosional) is with the marine units of the Mowry Shale formation. The J-Sand is divided into two members, the older Fort Collins Member and the upper Horsetooth Member. Within the Wattenberg proper the Horsetooth member is typically thin or absent which leaves the Fort Collins member as the primary producer in the majority of the Wattenberg field. The Horsetooth member was deposited in a fluvial and estuarine environment that has resulted in less lateral and vertical deposits when compared to the Fort Collins member.

When viscoelastic fluids systems first appeared, they provided a very good non-damaging no polymer option for many tight gas applications. These fluids were operationally simplistic with only a few additives, usually less than five. However, they are temperature limited to about 140°F as a single fluid. For temperatures to about 220°F you have to foam with gas (carbon dioxide (CO 2 ) or nitrogen (N 2 ), usually 65 to 75 quality (Q) in order to achieve stability with adequate viscosity. In addition the typical VES systems do not have very good friction reduction because at high shear they tend to behave more like water.The new thermo thickening system raises the temperature limit for traditional VES fluids. Rheology testing exhibits good structure along with viscosity. The time necessary to gel with temperature can be accelerated and delayed chemically. Although it does contain a polymer, regain conductivity tests show very high numbers usually associated with VES fluids. The system also exhibits unique traits of clay control, surfactant properties and fluid loss. The system also has the potential to extend further as a foamed fluid. This project will show laboratory testing results and a field test case history of this new and unique fluid system.

Hydraulic fracturing has proven to be one of the best technologies to improve productivity from tight gas wells. In such low permeability reservoirs, careful consideration must be given to fracturing fluid selection. Some reservoirs are under-pressured and require the use of energized fluids, while others are sensitive to water-based fluids due to clay swelling and migration. Proppant pack damage due to gel residue is one the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and therefore maximize production, a new premium highly efficient fracturing fluid was developed. This premium system incorporates low polymer loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep well fracturing and coiled tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with carbon dioxide (CO2) and nitrogen (N2) or may also be used in binary foam systems. This paper will provide details on the new fracturing fluid system, in terms of proppant pack cleanup, rheological properties and fluid loss as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop; fluid leak-off testing; and proppant pack conductivity and regain permeability evaluations are presented. Field case histories will evaluate fracturing treatments using new fracturing fluid and comparable treatments using conventional fluid. Normalized production data of the treated wells of both systems are also compared. Introduction Water based fracturing fluids are the most common stimulation fluid used for hydraulic fracturing in the industry today. The water-based fluids can range from plain water with a friction reducer to a complex crosslinked polymer fluid with a variety of additives. Modern fluids can be pumped in batch-mix or continuous-mix modes. Rheological properties (viscosity, for example) can be adjusted as desired very easily by varying polymer or additive loading (either in stages or continuously) during the job if required. Crosslinking is the most cost-effective way of increasing the viscosity of the fluid. Water-based fluids can be crosslinked at high or low-pH conditions. To achieve the same viscosity at higher reservoir temperatures, one can use an order of magnitude less polymer by crosslinking than with linear polymer in aqueous solutions. Historically, these fluids typically required polymer loading from 40 to 80 pounds per thousand gallons (ppt). However, with the higher yielding more efficient polymers and with better crosslinking technology, the loadings have dropped to as low as 12 ppt on the low end and as high as 35 ppt on the high end for most applications (Dawson, et al., 1998). Most common crosslinked fluids used in the industry are in the high pH range. These include most borate and zirconate crosslinked fluids.