Massive Hydraulic Fracturing Treatments Research Articles

Chemically Modified Natural Gum for Use in Well Stimulation

Abstract A new polymer gelling agent has been developed to help satisfy the growing demand for "clean" hydraulic fracturing fluids. This polymer is a guar derivative that exhibits the desirable characteristics of conventional guar and that leaves low residue upon breaking. The derivatized guar was evaluated for its ability to function as a fracturing-fluid gelling agent in comparison with both a conventional guar and a nonionic cellulose derivative. The guar derivative possesses a number of advantages over both the conventional guar and the cellulose derivative. Laboratory experimental data and field results are presented. Introduction Hydraulic fracturing has been used successfully for oil- and gas-well stimulation for about 27 years. During this time the size of the treatments has grown from the original "tank of oil and sack of sand" to the current massive hydraulic fracturing treatments, entailing several hundred thousand gallons of fluid and large amounts of sand. These massive treatments have become routine in some areas of this country. Although many types of fluids have been used successfully, aqueous fluids have been preferred recently. Because of economic and safety considerations, aqueous fluids will likely continue to be preferred. Treatment designs usually require that the fluids possess a particular apparent viscosity. These stipulated viscosities are particular apparent viscosity. These stipulated viscosities are often many times higher than that of the base fluid in its natural state. The increased apparent viscosities are generally attained by the addition of hydrophilic polymeric "gelling agents." A variety of gelling agents for aqueous fluids is available. Each gelling agent possesses inherent chemical properties that often make it particularly applicable for a special function. These properties are a direct result of the chemical structure and stereochemistry of the repeating unit of the polymer, and the resulting conformation or macrostructure that the polymer assumes in the fluid. Polysaccharides, such as the guar polymer, possess many of the properties desired of a gelling agent. However, the relatively high percentage of insolubles (residue) present in commercial guar has been a matter of serious concern. Many believe that guar-gum residue can contribute to permanent formation and fracture conductivity damage. Because of the complexity of the situation, experimental evaluation of the over-all effect of this residue on the formation permeability and fracture flow capacity is difficult. However, there should be no question that the presence of the residue could result in damage to the formation and the proppant system, and that a reduction in the amount of residue proppant system, and that a reduction in the amount of residue present diminishes this possibility. present diminishes this possibility. A new low-residue, derivatized-guar (derivatized polysaccharide) gelling agent has been developed. This chemically polysaccharide) gelling agent has been developed. This chemically modified guar results in an 85-percent reduction in inherent residue over conventional guar gum, yet retains the desirable properties of the guar polymer. In addition, it provides an properties of the guar polymer. In addition, it provides an extension of guar chemistry and versatility into several new approaches for designing hydraulic fracturing fluids. This versatile polymer has application in most aqueous and polymer-emulsion hydraulic fracturing processes. polymer-emulsion hydraulic fracturing processes. In addition to possessing the obvious advantage of low residue, this new material can be dispersed controllably in aqueous fluids, thereby effectively reducing gel lumping tendencies. The result is a smooth, lump-free gel. It yields equivalent or slightly higher apparent viscosity values in fresh water and the usual brines compared with the old, conventional, guar-gum gelling agents. Alcohol tolerance of this new material is good, and it is readily complexed or crosslinked in water or alcohol-water mixtures with crosslinking agents. Fluids prepared with this new polymer may be manipulated to achieve temperature stability surpassing that of any gelled-water fracturing fluid containing the polysaccharides we have used in the past. SPEJ P. 5

The Application of Massive Hydraulic Fracturing to the Tight Muddy "J" Formation, Wattenberg Field, Colorado

Laboratory and field research in Colorado's Wattenberg field showed that commercial gas production was feasible from the very tight Muddy "J" formation using massive hydraulic fracturing. Results indicate that the largest treatments are economically justified in the better areas of the field. Introduction This paper presents the results of a joint research and field effort to develop the very low permeability (0.05 to 0.005 md) Muddy "J" formation in the Wattenberg field by the application of massive hydraulic fracturing (MHF). In this paper, MHF is defined as having a vertical fracture penetration of more than 1,500 ft in each direction from the wellbore. Wattenberg gas production is from the very tight Muddy "J" formation, which is about 50 ft thick and is found at a depth of about 8,000 ft. The bottom-hole temperature in Wattenberg wells is 260 deg. F. Initial attempts to develop the gas potential in this field were made by stimulating wells with 40,000- to 50,000-gal gelled-water fracturing treatments. These efforts resulted in increased gas production; however, the rapid decline of gas production rates with time indicated that the stimulations would be economic failures. Laboratory studies were made to evaluate various fracturing fluids and to investigate fracture flow capacity with various proppant plans. Using these studies, a stimulation program was developed that used a polymer emulsion fracturing fluid and a pillar proppant placement technique. Treatments with up to 500,000 gal of fluid and 1,000,000 lb of sand were conducted. Field case histories are discussed and the results of MHF treatments are compared with those of conventional fracturing treatments. In addition, shut-in temperature logs run before and after treatment, production performance, and mechanical rock properties were evaluated. This information clearly indicates that the largest treatments are economically justified in the better areas of the field, and the fracture penetration is on the order of 3,000 ft. Field Description With an increased demand for gas, better wellhead gas prices, and improved technology, energy companies prices, and improved technology, energy companies are now devoting more attention to the "tight" gas reservoirs heretofore considered noncommercial. The Wattenberg field near Denver is a reservoir that typifies the "tight gas reservoir." Through advancements in fracturing technology, Wattenberg is now considered commercial. The Wattenberg field is located in the western portion of the D-J Basin in Adams and Weld Counties, Colo., and comprises an area of 980 sq miles (627,000 acres) The field was discovered in 1970. During 1974 and 1975 it was under intense development, with approximately 480 gas wells drilled by various companies. Amoco Production Co. is the major operator, with more than 300 Production Co. is the major operator, with more than 300 wells drilled. The Muddy "J" formation of Cretaceous age is the major gas producing zone in Wattenberg. This blankettype sand of extremely low permeability (0.05 to 0.005 md) is found at depths ranging from 7,600 to 8,400 ft (see Table 1 for other pertinent data). The reservoir is stratigraphically controlled by sand pinchout to the southwest and loss in permeability to the northeast. Natural productivity from this very tight formation ranges from a small productivity from this very tight formation ranges from a small show of gas to 100 Mcf/D. JPT P. 10

Hydraulic Fracturing-New Developments

Abstract This paper discusses the theory of hydraulic fracturing and the new developments in fracturing fluids and fracturing techniques which are continuing to make fracturing n important production tool. The discussion of hydraulic fracturing theory includes reasons for fracturing, objectives in fracturing and considerations in designing hydraulic fracturing treatments. The considerations in designing hydraulic fracturing treatments include formation characteristics as they control fracture extension, type of fluids used in the treatment, treatment size, proppant type and economics. New developments in the last few years have proven successful in stimulating zones that were previously considered uneconomical or marginal. These new developments, relating to fluids and treating techniques, are being used in the massive hydraulic fracturing treatments now being conducted in the U.S. Rocky Mountain area. Introduction The hydraulic fracturing process, developed on a commercial scale in 1949, has been successfully employed to increase production many formations which could not otherwise have been produced economically. There are many factors which should be considered prior to conducting a stimulation treatment by hydraulic fracturing. These relate to conditions of the wellbore, the reservoir and the economics involved. The two primary objectives in hydraulic fracturing are (1) to bypass formation damage and/or (2) to stimulate the zones of interest. The design of a successful hydraulic fracturing treatment requires that consideration be given to the formation characteristics. These are a function of depositional environment and, therefore, knowledge of the geology of the formation is important. In many cases, the formation characteristics at the extent of induced fractures are different from the formation characteristics at the well bore. The characteristics can be known only from knowledge gained from offset wells and/or the geology of the area. With formation characteristics known, the fracturing fluid type, proppant type and other treatment variables may be evaluated. New developments in the area of hydraulic fracturing relate to fluids with specific characteristics and to techniques for application of these fluids. The recent emphasis in hydraulic fracturing has been on creating extremely long fracture systems in tight gas sands. From this emphasis, the Massive Hydraulic Fracturing concept has emerged. In the text of this paper, the term production increase will relate to the generation of a fracture system with flow capacity greater than the flow capacity of the formation. In this sense, the term production increase will be synonymous with the term injectivity increase. Discussion Hydraulic Fracturing Considerations Prior To Hydraulic Fracturing Several factors should be considered prior to conducting a hydraulic fracturing treatment. Some of these are:the wellbore damage;the formation flow capacity;the existing reserves and/or depletion; andthe economics. The extent of wellbore damage can be determined by production tests, pressure testing and production history. This information is helpful in determining the type of treatment required to remove or bypass the damage. Once it is determined that a fracturing treatment is necessary, the formation flow capacity should be considered. If it is high, only a small-volume treatment may be necessary to bring the well to its expected production.