The Green River formation in the Utah Basin of eastern Utah is a series of low-permeability sands containing a viscous crude oil. Primary stimulation techniques involve the pumping of hydraulic fracture treatments. Usually several treatments are pumped per wellbore because, the sands are spread out over a large vertical interval. Typical treatments use a crosslinked Borate fluid with high proppant concentrations and moderate volumes of sand as proppant. The operator's changes in fracture treatment design were evaluated through comparisons to offsetting well production responses. The results indicate a 65% improvement in early, six-month, oil recovery and improved effective stimulations versus prior development projects. These results are primarily due to increasing the fracture conductivity through more effective proppant placement. Descriptions of the fracture treatment designs and predicted fracture geometry using fracture computer models will be presented. The economic impact of the increased production response has added $60,000 of additional revenue to early response while fracture treatment costs have actually declined. The paper will also detail the reservoir description work that has been performed to quantify the production response from individual sands in the Green River formation. This work will further improve economics by allowing true fracture optimization for individual treatments. The reservoir description technique uses standard openhole log suites and results in a prediction of in-situ formation permeability for individual sands. The technique has proven very accurate in predicting well production response and these results will be presented. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results. P. 249

More than 500 oil and gas wells in the Denver-Julesburg (D-J) Basin have been successfully stimulated using a water-base fracturing fluid, gelled with a diesel-base gel concentrate. Since the use of this system began in 1985, six different D-J Basin formations, with bottom hole temperatures ranging from 120F to 260F, have been treated. Ammonium chloride and potassium chloride have both been used with the continuously mixed gel to help protect clays. This paper presents a brief description of the chemistry of the system, however, the main emphasis of the paper is toward operational considerations and economics of using diesel-based gel concentrate. The considerations include continuous (on-the-fly) mixing of the gel and an evaluation of ammonium chloride versus potassium chloride for clay protection. Introduction Economic pressures of recent years have motivated the search for more efficient fracturing fluids. New fluids have been developed and existing fluids have been modified to meet the demands of the oil industry. Standard fracturing treatments in the D-J Basin normally vary in size from 1,000 bbl to 5,000 bbl of water. Conventional treatments are premixed jobs, where all the gelling agent is premixed in the frac tanks before any fluid is pumped downhole. The premixing process normally requires a minimum of 30 minutes to mix a 500 bbl tank. Bactericide and buffering chemicals are used to assist in the gelling process and to maintain integrity of the gel until it is pumped downhole. Preparation of fracture fluid from concentrated gel is a process that allows continuous mixing of the gel polymer. As early as 1977, a water-based concentrate was pumped in the D-i Basin, however, limitations in this system prevented it from becoming a viable alternative to pre-mixing. Research continued until 1985, when a hydrocarbon-based concentrate was introduced, permitting continuous mixing of gel with none of the problems presented by the water-based concentrate. In 1986, the addition of a clay control material (ammonium chloride) to the gel concentrate eliminated the need to premix potassium chloride (KCl) in the frac tanks. Only fresh water is placed in the tank. FLUID AND EQUIPMENT DESCRIPTION The concentrate consists of a stabilized polymer slurry (SPS) gel of an intermediate guar or derivatized guar added through an educator to a hydrocarbon, normally diesel. A surfactant and a viscosifying agent are added to stabilize the slurry. The mixture is circulated through a centrifugal pump before the mixture is allowed to stand. Ammonium chloride can also be added to the slurry to assist with formation clay stabilization. The SPS is now ready for use and can be stored or used as desired. To produce the aqueous base fracturing fluid, the gel concentrate must be blended with water utilizing a metering pump and a high shear energy mixing pump. A mobile "pre-gel blender" with a holding tank (80 bbl) is used to help obtain adequate gel hydration before the gel is pumped downhole. The blender tank is divided in half by a weir to prolong hydration time. Hydration rates of field-mixed (1) powdered intermediate guar and (2) liquid intermediate guar are shown in Fig. 1. Laboratory obtained hydration rates show similar responses for both gelling methods, however if field mixing procedures result in fisheyes, lumps, and/or deficiencies a difference such as shown in Fig. 1 may result. Viscosity of the aqueous gel is monitored at the weir. A second observation is made at the centrifugal pump on the job blender and a third viscosity reading is taken from a field rheology loop. P. 493^

The CodeII sandstone in the Denver-Julesburg Basin is a low permeability, clay-rich sandstone. It is bounded by the Ft. Hays limestone member of the Niobrara formation above and shales of the Carlile formation below. The Codell requires stimulation by hydraulic fracturing in order to produce at economic rates; however, some stimulation procedures are not effective.

The Sterling B4 sands is a reservoir underlain by an aquifer located on the Kenai Peninsula of Alaska. This dry gas-on-water reservoir, holding approximately 13.9 billion cubic feet (Bcf), has experienced challenges since its first development in the 1960s. The gas-water contact is very mobile and easily influenced upward by gas production. All four wells, largely producing in succession of one another, have experienced excessive water production which killed gas production. Faulty drilling and completion work exacerbated the challenges associated with bringing the gas to market. This paper summarizes an effort to model the Sterling B4 development and determine feasible alternatives for revival of the reservoir and commercialization of the produced gas. Those alternatives include infill drilling, variable production, and co-production. Co-production is a method by which gas is produced from the gas zone and water is produced from the water zone; each stream is produced independently by either mechanical means or different wells. The only feasible alternative found in this study is co-production. Of the two co-production methods analyzed, the highest ultimate recovery includes the utilization of an existing vertical well perforating the upper portion of the reservoir for gas production and a new lower horizontal well perforating the water zone to control the gas-water contact. Modeled production schemes proved the gas-water contact may be controlled from upward mobility by maintaining a threshold pressure difference between the bottom-hole pressures of the two producing wells. Utilizing co-production in this manner yielded incremental benefit of over 2 Bcf until shut-in limits were triggered, achieving an ultimate recovery of up to 43%. Economic analysis of the project has proved bringing the gas to market presents a significant prize able to support production and full facility operational expense despite no other revenue streams. Should other nearby formations demonstrate sufficient targets, the economic case would be enhanced and present an even greater prize.

Cop!n'ioht 199S.Society&Petroleum Engineers,Inc. This paper ws~red fw wesents~~at the 19SS SPE Permian Seein 011and Gas Recwery~ference hdd in Midland,Texas, 23-26 Mati 1998. This paperwas selectedfw -tstion by an SPE Program-Ittee fdl~ng M* of information mntained in an abstrscl submittedby Me ati(s). Contents~the PSW, as -ted hsw n~* IWI* by tie SoddY of Pe@olwmEnglnaaraandare eubj@ 10 wrredim by the authqs).~e material, es Eented, dw @ neceeesrily raflecl any pmm r.dthe Sociely& PetroleumEngim, its~-t w mem~. Pam v~led a! SPE readings are subject10 publication* by Edit-l Ctittw of the sodew of Pel_ En@neera.k -u-, fJlsbiLsJtiM, or stw M any pad of thispaw for mmmerdd purposeswithwt the wriftm cmaent @ the Sodety of Pdrdaum EngineersIs @ibited, PerrnissiMto @uca In @nt k reatrkled 10an abstrsd of not -e than 3C0 WS illustmtims meY d be *ad. me absbecl must mtsin amapiwws ad(tiedgment of tiara and by * ths~was~nted. Write Librarian,SPE, P.O. Sox83383e, Rkhardw, TX 7=3836, U.SA., fax 01-972-952-9435. AbstractThe Green River formation in the Uintah Basin of eastern Utah is a series of low-permeability sands containing a viscous crude oil. Primary stimulation techniques involve the pumping of hydraulic fracture treatments. Usually several treatments are pumped per wellbore because, the sands are spread out over a large vertical interval. Typical treatments use a crosslinked Borate fluid with high proppant concentrations and moderate volumes of sand as proppant.