Summary Our company began fracturing diatomaceous earth zones in the San Joaquin Valley (CA) in 1976. Fracturing has proved an effective method of exploiting these previously noncommercial reservoirs. Nevertheless, productivity behavior is typified by high initial rates followed by rapid decline. Reasons for this decline have been evaluated and are discussed. Also discussed are laboratory experiments performed to determine an appropriate fracture design for this formation. Introduction In 1976 Mobil fractured a well in a diatomaceous earth formation in the San Joaquin Valley. This was a highly successful treatment. Since then, hundreds of fracture treatments have been performed in several fields in formations of this type in the valley. This paper summarizes our hydraulic fracturing experience in the South Belridge field from early 1977 through early 1980 with particular emphasis on evaluation of the production behavior of these wells. Background At the time our research began, fracture treatments were uncommon in the diatomaceous earth zones in the San Joaquin Valley. Very modest, discouraging results were reported from one area1 with somewhat more encouraging results being reported from another area2 when oil-base fracturing fluids were used. Personal communications with various sources confirmed that fracturing had met with very limited success in these formations, and yet the evidence from limited core and production data indicated good potential for production improvement through fracturing. Therefore, we began a research and testing program to determine the fracturing potential of the diatomaceous earth zones in South Belridge field. Because few data were available on fracturability of these soft rocks and on the potential damage by aqueous fracturing fluids, we first performed some laboratory experiments on core samples. The initial fracturing designs were based on the results of these experiments. Reservoir Description Diatomaceous earth deposits in the South Belridge field form the bulk of the diatomite and brown shale zones of the Reef Ridge formation. This has been the primary formation of interest in the fracturing work in this area. Some portions of the upper part of the McLure chert also have been fractured. Depths of the productive intervals vary somewhat because of structural position but overall are between 800 and 3,000 ft [244 and 914 m] from ground level. These formations are Miocene and lower Pliocene in age. They are characterized by high porosity (50 to 70%), low permeability (generally less than 10 md to air and much less than that to oil in situ), and moderate to high (40 to 80%) water saturations. Pore size distribution (PSD) measurements indicate pore sizes in the micron to submicron range. Photomicrographs confirm this, showing whole and fragmented diatom tests of this size. This fine-grain character gives a core sample the appearance of shale even though the major component is amorphous silica. Clay minerals are present, reaching as high as 25 wt%. Of this, ±80% is mixed-layer illite and smectite. In general, clay content increases with depth. Zone quality appears generally to decrease with depth. Log and core analyses give values for porosity, oil saturation, and permeability, which all generally decrease with depth. There are some exceptions to this. Fracturing Considerations and Laboratory Evaluation Fracturing operations in the South Belridge field introduced some rather unconventional fracturing problems and concepts. The unusual mechanical properties of diatomaceous earth materials raise questions about fracturability and fracture closure problems. Wells in the South Belridge field are closely spaced, and oil-producing intervals are scattered throughout very thick zones. Individual oil-rich zones are difficult to identify from well logs. On the basis of the best available log analysis, it appeared most practical to complete a large portion of the entire upper part of the diatomaceous earth zone. This called for a series of fractures generated in such a way as to produce maximum fracture height but only modest length. As a practical goal, we hoped to produce individual fractures of 200 to 300 ft [61 to 91 m] in height and lengths of the same order.
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
Reservoir management of hydraulically fractured reservoirs can be improved with knowledge of the orientation of hydraulic fractures. Fracture direction can affect where wells are placed, the design of well patterns for EOR floods, the design of fracture treatments, and the stability and fracturing of horizontal wells. This paper presents a field study of the determination of hydraulic fracture direction in the San Juan basin in northwest New Mexico. Data from six different fracture direction techniques were integrated to improve the determination of fracture direction. Integrating results from the six techniques not only improves the accuracy of the results but also allows us to compare the techniques to one another on the basis of reliability of results, operational requirements, and cost effectiveness. The average of all the data from each of the four wells suggests a hydraulic fracture direction of 41° azimuth in this area of northwest New Mexico. The trends agree with regional in-situ stress direction for the area1. There were only small variations between wells and the fracture direction was consistent with depth over the 300 feet of formation tested. The direction of natural fractures as seen in the core and in the borehole televiewer was similar to the hydraulic fracture direction. Based on this study and other published reports2-13 on hydraulic fracture/in-situ stress direction, we believe hydraulic fracture direction is best determined by integrating results from multiple techniques in several wells in an area. We find that the ability to determine fracture direction is most affected by the horizontal stress contrast in the area and the presence of paleo-imprints on the rocks. Fracture direction can strongly affect the recovery of hydrocarbons from hydraulically fractured fields and should be a datum that is collected routinely in the development of such fields.
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.
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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