Summary Abnormal treating pressures were observed during massive hydraulic fracturing (MHF) treatments in the Mesa Verde formation of the Piceance basin, CO. Data from three widely separated wells and in several zones per well showed a pressure increase during MHF treatments that we call "pressure growth." This pressure growth was at least semipermanent. The elevated instantaneous shut-in pressures (ISIP's) did not return to initial values over periods of pressures (ISIP's) did not return to initial values over periods of several days. The magnitude of this pressure growth is highly variable. When its value is less than about 2,300 psi [15.9 MPa], the MHF treatments are usually completed and results are obtained that are within normal expectations. When its value exceeds 2,300 psi [15.9 MPa), sandout occurs and the fracture length estimated from production data is much less than that calculated with crack production data is much less than that calculated with crack propagation models. Temperature logs indicate little or only propagation models. Temperature logs indicate little or only modest vertical extension of the fractures above the perforations. These data, along with sandouts, point to a large increase in fracture width in response to pressure growth. One possible cause of pressure growth is fracture branching. A multiplicity of branches could produce a plastic-like effect. Laboratory measurements have ruled out plasticity as the cause. The stress/strain behavior of the rock is similar to that of rocks where no pressure growth occurs. Pressure growth seems to depend on both pumping rate and Pressure growth seems to depend on both pumping rate and fluid viscosity. Thus, there is some hope for its mitigation through treatment design. Also, pressure growth appears to correlate negatively with pay-zone quality. This suggests that the phenomenon can be exploited as a fluid-diversion technique. phenomenon can be exploited as a fluid-diversion technique. Introduction Because of its large resource, the Piceance basin has been one of the more promising prospects for MHF applications in tight-gas sands. In this promising prospects for MHF applications in tight-gas sands. In this basin, the Mesa Verde and adjacent overlying formations provide several hundred feet of sand thickness at depths between 5,000 and 12,000 ft [1525 and 3650 m]. Porosity in much of this sand thickness ranges from 5 to 8%. The gas resource in the basin has been estimated at 33 Bcf [934 × 10(6) m3]. Massive fracturing methods have been tested extensively within the Piceance basin by Mobil and others. Results of these tests have shown that, with market conditions of earlier times, commercial wells can be developed in the Piceance basin using massive fracturing methods. MHF experience in these tight-gas sands shows an unusual characteristic. Fracturing treatments are always accompanied by large increases in treating pressure. This phenomenon, or pressure growth, has adverse effects on pressure. This phenomenon, or pressure growth, has adverse effects on fracture effectiveness. It appears to produce undesirable width/length aspect ratios as judged by fracture height and production data. It limits the size of massive fracturing treatments by causing premature sandout. And it increases the pumping horsepower requirements by as much as a factor of two. Understanding and finding ways to avoid this problem are clearly matters of practical importance. Pressure growth inhibits the generation of very long practical importance. Pressure growth inhibits the generation of very long fractures, which are needed for successful application of MHF methods in the Piceance basin. It is likely to be important in other basins where tight-gas sands are lenticular on the scale of Mesa Verde lenses in the Piceance basin. Pressure growth is not to be confused with any of the pressure changes treated by Nolte and Smith in their analysis of fracturing pressures. The pressure-growth phenomenon considered here begins with the first injection pressure-growth phenomenon considered here begins with the first injection of fluid into the fracture and continues throughout the treatment. It produces dramatic effects, typically resulting in a doubling of the surface produces dramatic effects, typically resulting in a doubling of the surface treating pressure in a massive fracturing treatment. In this paper, we present field data that help define the nature of pressure growth. We present a model based on fracture branching that may pressure growth. We present a model based on fracture branching that may explain the cause of pressure growth and is consistent with field observations. Other explanations should also be investigated. We suggest a possible way of avoiding or minimizing the problem and propose a method of using the pressure-growth phenomenon as a fluid-diversion technique.
Multiple, vertical fractures can be created from a single, directionally drilled wellbore. The procedure increases the attainable fracture area without adding wells, and provides more rapid and efficient drainage of a specific reservoir volume. Introduction For any reservoir with a given set of conditions there should be a drilling, completion, and production procedure that will optimize the financial recovery from procedure that will optimize the financial recovery from that reservoir. This paper focuses on a procedure that should be considered for application in certain types of reservoirs. This procedure involves creating multiple, vertical fractures from an inclined wellbore and the subsequent production from the system. The effectiveness of hydraulic fracturing is well known, both from experience and from theoretical considerations. The concept of a fracture represented by an enlarged wellbore is discussed by Prats et al. The effects of fracture penetration and fracture conductivity on improvements in production are shown by McGuire and Sikora and Tinsley el al. In low-permeability reservoirs, sufficient conductivity contrast between fracture and formation can be obtained to make well productivity increase almost directly proportional to fracture length. Thus, for vertical proportional to fracture length. Thus, for vertical fractures of fixed height, productivity increase is directly proportional to fracture area. From the above discussion we can conclude that a method to increase the effective fracture area attainable is desirable. To be useful, any such method must, of course, be more profitable than the practical alternatives. For a reservoir volume element of fixed size, the maximum vertical fracture area is attained when the fracture is extended to the boundaries of the element. Additional fracture area can only be obtained by drilling and completing additional wells within the volume element. A procedure for producing several vertical fractures from a single well would increase the attainable fracture area without adding wells. Such a procedure and a field experiment to test it are presented here. presented here. The Multifrac Concept The object of this multiple fracturing process (multifrac) is to obtain greater fracture area through closer fracture spacing than could be obtained from the same number of wells with single, vertical fractures. The increase in well productivity resulting from this greater fracture area per well is not gained without penalty. Because the process requires substantial penalty. Because the process requires substantial deviation of the wells from vertical, both measured well depth and drilling cost per foot are increased when compared with a vertical well. This idea has also been suggested by Pasini and Overby. The concept is illustrated in Figs. 1 and 2. Theory predicts, and observation confirms, that hydraulically predicts, and observation confirms, that hydraulically induced fractures are generally vertical, except in relatively shallow formations. Thus, it should be possible to generate several fractures from a single possible to generate several fractures from a single deviated hole, as shown in the figures. To accomplish this, the azimuth of the deviated wells must be at a high angle (preferably 94) to the fracture azimuth. The Borehole Televiewer (BHTV) is effective for determining the azimuthal orientation of vertical fractures in a vertical wellbore. JPT P. 641
Demonstration of massive fracturing to pro•vide gas production from tight gas sands in the Piceance Basin was the objective of this jointly.funded Mobil/DOE project. This effort has been at least partially successful. The uppermost interval fractured, the "Ohio Creek" formation a+ 7324-7476 ft., appears to be commercially viable. The remain!ng sequence to total depth of 10,800 ft •. may also be commerciafly attractive, depending on fractured well costs, gas prices and the risk offal ture to achieve production capacify equal to, or greater than, that achieved in the present well. Prior work was performed by Mobi I in the Brush Creek Unit, Mesa County, Co•lorado. One well, Brush Creek 1-25~ was drilled to 10,330 ft. and given two massIve fracturing treatments before the we I I _was pI ugged and. abandoned as non-commercial. It was concluded that formation permeability was too I ow to justify addItion a I work In the Brush Creek Unit. • Piceance Creek wei I F31~13G was drl I led to 10,800 ft. Nine zones were tested in the Mesaverde and "0h i o Creek" formations between 7_324.-1 0,680 ft. Six massive.fracturlng treatments were performed coverlng•7 of the 9 intervals. Average first-year flow potential of the wei I is estimated at 2.9 MMCF/day with 1.1 MMCF/day of this amount attributed to the uppermost zone.
Demonstration of massive fracturing to provide gas production from tight gas sands in the Piceance Basin was the objective of this work by Mobil. The project was partially funded by the U.S. Department of Energy. During the period 1974-1979 two wells were drilled, tested and fractured. Encourging results were obtained from the second well.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract A procedure is outlined for calculating the performance of a vertically fractured gas well contained within a square drainage area. Constant production rate and the constant well pressure cases are included. Because it is not pressure cases are included. Because it is not a numerical simulator, calculations can be performed practically on small computers. performed practically on small computers. Predicted comparisons with published reservoir Predicted comparisons with published reservoir simulator results and with actual production data from two massive hydraulically fractured wells were made. Agreement in both comparisons was very good. Introduction In recent years the concept of massive hydraulic fracturing (MHF) has been developed with particular interest in its application to gas recovery from very low permeability reservoirs. While several factors determine the profitability of applying this technology, one of the most important is the gas recovery rate. Adequate predictions of productivity behavior are imperative for proper economic evaluation. As has been illustrated by Morse and Von Gonten, transient flow effects exist for long periods of time (many years) in these low-permeability reservoirs. Therefore, productivity behavior during this transient productivity behavior during this transient period must be properly assessed in order to period must be properly assessed in order to perform meaningful evaluations. perform meaningful evaluations. Our own interests in MHF technology began several years ago as an integral part of studies considering multiple vertical fractures. At that time, there were no productivity prediction techniques available productivity prediction techniques available that would cover the spectrum of conditions of interest. The work of McGuire and Sikora adequately predicts, for the semisteady-state period, productivity improvements resulting period, productivity improvements resulting from vertical fractures in a bounded reservoir. Prats et al. expressed vertical fracture Prats et al. expressed vertical fracture performance in terms of an effective well performance in terms of an effective well radius. This concept predicts that, for infinitely conductive fractures of up to 50-percent penetration to a circular drainage boundary, there is a hypothetical well radius that would result in the same well performance as the fracture. This effective well radius is approximately equal to one-half the fracture penetration. This idea was shown to apply at penetration. This idea was shown to apply at all times except the very early transient period. The method reported here was developed period. The method reported here was developed to apply to fractures of any penetration with the ability to predict production rate for any time.
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