This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Summary This paper presents the results of coupling a reservoir simulator with an acid fracture design program. This model is used to identify program. This model is used to identify refracture candidates and to optimize acid refracturing treatments. Methods used to study treatment efficiency for specific reservoir properties are given for various acid systems. Introduction The Cottonwood Creek field in Washakie County, WY, was discovered in 1953 ad produces primarily from the Phosphoria produces primarily from the Phosphoria formation, a low-permeability, dolomite oil reservoir. This reservoir, covering about 60 sq miles, is one of the largest stratigraphic oil columns in Wyoming. Early development of the Cottonwood Creek Unit was concentrated in the updip portion of the field because of good production response obtained from high-permeability streaks. These streaks were originally interpreted as natural fractures. Reservoir modeling ad core data indicate that the reservoir is not naturally fractured. A waterflood was initiated in 1958 in the updip portion of the field, which maintained pressure support to the high permeability streaks. Productivity of these permeability streaks. Productivity of these wells was high ad stimulation was not believed to be necessary. The low-permeability portions of the reservoir, vertically adjacent portions of the reservoir, vertically adjacent to the high-permeability streaks were virtually unswept by the waterflood and contain a large amount of recoverable oil. As development continued in the Cottonwood Creek Unit, less prolific producers were drilled. Because of prolific producers were drilled. Because of the low permeability encountered, most of the wells required fracture stimulation to be commercial. During 1987, a detailed reservoir and logical engineering study of the Phosphoria formation in the Cottonwood Creek Unit area was initiated to determine whether the producing rate ad ultimate oil recovery producing rate ad ultimate oil recovery could be improved. The study indicated that may wells in the area had short fracture half-lengths. Extensive reservoir simulation indicated that increasing the effective fracture half-length would increase the producing rate ad ultimate recovery. Because of producing rate ad ultimate recovery. Because of these results, a acquisition program was pursued in the area. The most significant pursued in the area. The most significant acquisition was the Cottonwood Creek Unit, acquired Jan. 1, 1989. Geology The Cottonwood Creek Unit is located in the Big Horn basin about 8 miles east of Worland. The field produces primarily from the Ervay member of the Permia, Park City formation (Phosphoria), covers about 33 sq miles, and includes 150 oil wells. The Phosphoria reservoir is a stratigraphic trap Phosphoria reservoir is a stratigraphic trap covering roughly 60 sq miles at depths varying between 4,500 and 11,000 ft. The downdip limit is controlled by a oil/water contact.

This p@r wa~a--d for p=sentafion me~8 SPE Rocky Mountain Region alLow-Perrnaabifity Resemirs ,Symposlum and E~ibifion held in Denver, Colorado, 5-6 April 1998. 'rfds parer was selectad for presentation by an SPE Program Committee following retiew of information contained In an abstract submiflad by the author(s). Contents of the paper, as presented. habw not W retiewed by the %iefy of Petroleum Engineers and are subject tõ ty tha author(a). The materfaf, as presented, dms not necessarily reflect any position of the SmJe~-b~nMoTeufiF~V*E, W Mcem, or mamhra. Papers presented at SPE m-arR S* fo P*ficafi~m~ew by E~orial Committees of the Society of Petroleum Englneera. Electronic raproductlon, drstribuiion, or storage of any part of this paper for commerctaI purposes wffhout the wrfffen consent of the Society of Petroleum Engineers is pmhibitad Permission to rWroduce in print is restricted 10 an abstract of not more than 3C0Uus-s may nor be kqied. The abstract must contain conspicuous acknowledgment of whace and by whom the papr was presented Write tibrsrian, SPE, PO. Box 8W836, Richardson,~750s3-3636. U.SA., Tax01 .~-952-9435. -

Summary This paper shows proppant-induced pressure increase (i.e., tip screenout, pack, body pack, etc.) can relate to restricted vertical and lateral proppant distribution in hydraulic fractures. The discussion focuses on interpretation of the character of the pressure response during the proppant stages. Essentially, this pressure response relates directly to the quality of the production response and the level of success. The technology presented has been found to apply to all rock types, frac packs, and low-permeability and water-frac applications. This area of study is based on extensive engineering studies and common sense observation. Prior to publication of this work, this approach fit the reservoir engineering interpretation of the producing character and advanced fracture-treatment-pressure interpretation on a minimum of 1,000 wells. When premature proppant-induced friction occurs in the hydraulically induced fracture, lateral and vertical proppant distribution adjacent to the pay interval can be affected negatively. Restricted proppant distribution results in less effective stimulation because proppant is not distributed well both vertically and laterally adjacent to the pay interval. The fracture stimulation may have been "put away;" but the negative aspects of how the stimulation was designed and implemented may have a significant effect on the resultant production response. To establish the basis for additional thought and investigation, there is discussion about deficiencies in overly simplified pretreatment minifracture-analysis procedures. Many of these analysis methods are not focused on the proppant-induced friction character, and therefore do not optimize proppant distribution. Discussion is provided regarding differences in the proppant-induced friction character of various fracturing fluids which is not an inherent variable typically included in fracture-treatment-design methodology. Introduction The technology presented is derived from a significant volume of work based on an integrated engineering approach to determine the effectiveness of the completion and stimulation method. Over the last 6 years, the technical advancement by Integrated Petroleum Technologies Inc. (IPT) presented in this paper has been extensive in the application of this area of study. The resultant production responses in many areas have been significant, supporting the credibility of the technology presented. During the mid-1990's, downward proppant movement (i.e., clustering, settling, convection1–4) in hydraulic fractures received significant attention in technical papers, forums, meetings, etc. It was depicted as a dominant variable in hydraulic fracturing and, if not addressed, the reason many wells did not produce properly. Proppant was theorized to move to the bottom of the fracture and not be adjacent to the pay interval. An approach for minimizing downward proppant movement was to "tip screenout" or "pack" the fracture. The viewpoint existed for many years that a tip screenout is the ideal response. If conductivity is desired, then build the fracture conductivity by screening out or packing the fracture. This may apply in high-permeability, low-modulus rocks; however, packing the fracture in low- to moderate-permeability rocks has been found to be detrimental to desired results. During the early to mid-1990's, many fractures were packed at various levels of pressure increase to minimize the hypothesized severity of downward proppant movement and achieve a tip screenout. Through detailed reservoir engineering evaluation, these packed fractures were determined to have either short effective fracture lengths or skin damage. Our initial evolution was to reduce the level of proppant-induced pressure increase/pack. Excessive levels of proppant-induced pressure increase were determined to be causing damage as a result of polymer dehydration ("polymer squeeze") in the formation and fracture. With proppant-induced pressure increases of less than 1,000 psi, reservoir engineering analysis continued to show effective fracture lengths shorter than expected. Design criteria evolved to a lower (<500 psi) proppant-induced pressure increase. The effective fracture length from reservoir analysis became longer, but still did not meet fracture model-treatment-design expectations. To improve the predictive capability derived from stimulation designs, customized fracture models were developed that matched the proppant-induced friction character observed for various fluids, formations, fracture geometries, etc. Using these customized models further reduced the level of proppant-induced pressure increase. With the application of these customized models, resultant fracture lengths determined from reservoir analyses became longer and matched fracture lengths predicted in the original fracture-treatment design. When evolving in this direction, it was found that many minifracture techniques and standard industry fracture-model usage were flawed and did not rigorously account for proppant-induced friction effects. Standard minifrac evaluation was designed based on leakoff and fracture geometry assumptions during an era when a tip screenout was the ideal approach. These methods were not tailored toward optimizing proppant distribution because they do not focus on the influence of proppant-induced friction. During this same period, we began studying and observing microseismic and tiltmeter imaging of hydraulically induced fractures.5–6 Conclusions from these projects relate primarily to hydraulically induced effects and do not discern proppant distribution in the fracture. However, a consistent observation was that injection of proppant affected the imaged fractures. Changes observed in fracture-growth profiles included reduced lateral-fracture growth and additional fracture-height growth, usually upward. Fracture-imaging observations were coupled with the reservoir engineering and fracture-treatment net-pressure interpretation of many wells. The lateral proppant-distribution hypothesis was the consistent logic path that fit all scenarios. If proppant was entering the fracture and building proppant-induced friction, then how was the proppant efficiently distributing vertically and laterally adjacent to the pay interval? Furthermore, what effect does this frictional back-pressure have on the hydraulic-fracture geometry and injection profile of the slurry? As Baree7 presented in 1991, increased pressure at the fracture tip will cause fracture-height growth. The propped tip that is screening out could be significantly different than the hydraulic tip of the fracture.