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Collaborating Authors
Tight gas
Abstract Type curves for the production of gas from artificially fractured reservoirs have been used to determine the fracture characteristics that maximize the expected economic return. It is shown that if possible fractures should be propped to yield a dimensionless conductivity of 4.2. The volume of the fracture and, hence, its length are established based on an economic analysis such that the incremental cost a/increasing the fracture volumeis equal to the incremental increase in revenue generated by alarger fracture. In a particular case study examined, the present value revenue for a tight gas reservoir could be increased by 8.75% (i.e. $0.35 million) by decreasing the conductivity from 10 to the optimal value of 4.2. Introduction Hydraulic fracturing has become a standard treatment procedure for stimulating production from gas reservoirs. Particularly significant are the improvements in production which accompany massive fracturing in tight gas reservoirs. The design of hydraulic fractures is often undertaken in a rather casual manner. Treatment procedures are frequently chosen based on previous success in similar formations. Alternatively, several possible fracture designs are selected and compared for performance using standard performance curves, or using numerical simulators. Although such fractures invariably improve the production performance of a well, such approaches will not likely yield the best performance that could potentially be achieved. The cost of a fracture treatment can represent a significant fraction of the total cost of drilling and completing a well. Hence, the design of the fracture deserves a great deal of ttention. A fracture which is too small will result in an unnecessarily low rate of gas production, whereas one which is too large will result in excessive completion costs. Both undersized and oversized fractures will compromise the economic viability of a well. In this paper, a systematic approach is presented for the design of fractures in unbounded gas reservoirs. We consider only the case of vertical fractures because these are most requently encountered in deep formations which are characteristic of tight gas deposits. Analysis To begin the analysis, we will consider a well in an unbounded reservoir, that is to be produced at a constant rate, qp until some maximum desired drawdown, ฮPmax is reached. The lime 'It which ฮPmax is reached is referred to as the time until production drop-off, t'. After this time, the production rate will be assumed to decline, with drawdown held constant. For an infinite reservoir, if one considers several possible fracture treatments, the treatment which maximizes the timentil production drop-off will in general also maximize the present value revenue generated from the well. This point will be discussed in more detail later in the paper. This is an important observation, because it means that to a large extent, optimal fracture characteristics can be established based on the constant rate period. However, efforts to maximize t', without some additional constraint are not particularly productive because t ' an always be increased by making the fracture a little larger.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
Summary. The Gas Research Inst.'s (GRI's) Tight Gas Sands Program has been involved with research on low-permeability formations during the past 4 years. The main focus of the research has been to improve the general understanding, of producing tight reservoirs, while a specific focus has been to advance the technology involving hydraulic-fracture geometry. The unique aspect of this research is that the laboratories have been actual gas wells completed in the Travis Peak formation in east Texas. To extend the development of technology fully, GRI has planned four staged field experiments (SFE's) from 1986 through 1989. The SFF program provides the opportunity to collect a wealth of data that cannot be obtained from normal cooperative research wells. The purpose of this paper is to summarize all the tests and data collected on the first SFE and to present the available results from the analyses of these data. Introduction Research directed at reducing the cost and improving the recovery of gas produced from low-permeability reservoirs is currently being sponsored. Because the most viable method of improving recovery in tight formations is hydraulic fracturing, part of the research is aimed at better understanding of the processes that control fracture growth. If the petroleum industry can substantially improve its ability to predict and to control the shape of hydraulic fractures accurately, then the chances of achieving optimum propped-fracture lengths are increased. The end result will be an improved economic incentive for developing tight gas reservoirs. To understand the hydraulic-fracturing process better, it is first necessary to improve our understanding of both the reservoirs being fracture treated and the formations surrounding the main productive interval. To achieve this goal, a comprehensive program was initiated to perform geologic, coring, logging, well testing, fracture-treatment monitoring. and fracture-diagnostic studies on select cooperative research wells in the Travis Peak formation of the East Texas basin. Our technical approach is to use the necessary electronic equipment and computers in the field so that the GRI contractors may actually analyze the fracture-treatment data in real time. Once this system is perfected, we should be able to predict fracture shape and extent. If this can be accomplished successfully, we will then attempt to control fracture growth by controlling the fracture-fluid viscosity or the injection rate. The success of the program hinges on the cooperation of operating companies. Through their participation, GRI contractors are allowed to collect the data necessary for a complete formation and fracture evaluation from actual gas wells referred to as cooperative wells. With these data, we feel that substantial progress can be made toward the development of tight gas through better stimulation technology. Table 1 lists all GRI contractors, service companies, and producing companies that cooperated with GRI in the field data collection effort. Table 2 summarizes the data collected during the first 3 years of this research program. The cooperative research wells are just the first step in the overall plan to characterize fully the formation and hydraulic fracture in three dimensions. The next phase of the plan is to pull all GRI contractors together on strategic wells to use all possible means of improving the understanding of tight gas reservoirs. This phase is called the staged field experiments (SFE's). Goals of the SFE's Four SFE's are planned from 1986 through 1989. An SFE will allow the research contractors to collect the same basic data that have been available from most of the cooperative wells. Additional data, however, that have not been collected on cooperative wells because of either high cost or high risk to the operator will also be obtained during the SFE. The specific goals of each SFE are listed below. SFE 1: 1986โ87.To bring together all tight gas sand contractors to study a common formation and wellbore. To drill, complete. and stimulate a highly instrumented well to collect and analyze one of the most comprehensive data sets ever obtained in the industry. To implement data-collection methods that will be structured to benefit the research contractors working on fracture-diagnostic techniques and fracture-modeling efforts. Information obtained during the SFE will be presented toindustry in an integrated form to facilitate technology transfer. The various analyses will not be linked and may not necessarily be consistent between any two of the contractors. SFE 2: 1987โ88.A three-dimensional (3D) fracture-design and -evaluation model will be able to analyze the data in real time and to offer suggestions concerning changes that should be considered to improve the treatment results. Fracture-diagnostic experiments will be evaluated to focusfuture research efforts on the most promising of the techniques. All fracture-diagnostic methods will be separate from the fracturemodeling efforts. Field-measuring and -monitoring systems of the GRI Mobile Testing and Control Facility will be superior to all other field systems in terms of versatility, accuracy, and reliability. Experiments will focus mainly on the determination of fracture-height and fracture-length measurements and/or calculations of these properties. SFE 3: 1988โ89.Fracture-modeling systems will be computing fracture shape with precision. Fracture-diagnostic systems will be functional and provide input to the fracture models in real time. SFE 4: 1989โ90.Move to a new location and prove that the technologydeveloped can be transferred to a different environment. SPEFE P. 519^
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.71)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.47)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.93)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > Sligo Field > Sligo Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
- (12 more...)
Summary. The ability to predict incremental rates and reserves reasonably from infill development drilling in tight-gas reservoirs is enhanced through use of a three-dimensional (3D), multiwell, dry-gas model. Single-well [two-dimensional (2D)] and multiwell [three-dimensional (3D)] input and results are compared, and examples of both are presented. Measured initial reservoir pressures on an eight-well infill program compared favorably with the 3D model predictions. Introduction Upon the Federal Energy Regulatory Commission's establishment of the Sec. 107 incentive pricing, development of the Cotton Valley tight-gas-sand resource base expanded significantly, with more than 1,100 wells drilled during 1977โ82. The soft gas market, coinciding with gas deregulation, slowed further development between 1983 and the present (Fig. 1). As of Oct. 1985, there were approximately 1,230 Cotton Valley sand producers on Texas Railroad Commission records for the area encompassing Harrison, Panola, and Rusk counties. Amoco Production Co. has drilled or participated in the drilling of more than 170 of these tight-gas-sand wells, situated primarily in the Blocker, Carthage, Dirgin, Henderson North, Tatum, and Woodlawn areas of the Cotton Valley field (Fig. 2). Most of this development has been on 640-acre [260-ha] density. The Cotton Valley (Jurassic) sandstone of east Texas is a series of marine and lagoonal deposits. Diagenesis in the form of calcite cementation and quartz overgrowth, combined with overburden pressure, has reduced its porosity and permeability. With permeabilities in the microdarcy range, massive hydraulic fracture (MHF) stimulations are usually required to make a commercial completion. Gas production from the east Texas Cotton Valley sands has been at depths ranging from 9,000 to 10,500 ft [2700 to 3200 m]. The gross thickness of the Cotton Valley sand/shale sequence averages 1,500 ft [460 m]. This paper discusses modeling associated with only the lowermost Yellow, paper discusses modeling associated with only the lowermost Yellow, or Taylor, zone as shown in Fig. 3, a type log from the Blocker Cotton Valley field. The model work presented here was undertaken to determine the incremental rates and reserves associated with infill drilling of existing units. Two types of reservoir models were used. The first, a 2D model, contains a single well located in the center of a rectangular, homogeneous drainage area. This model is appropriate for minimum-well-density situations. This single-well model, however, fails to account for interference from other wells, which was suspected after early infill drilling (160 to 320 acres/well [65 to 130 ha/well]) was analyzed. The second model has a 3D capability that allows areal and vertical variations in reservoir properties. Most important, it can model several wells at once, thereby providing the opportunity to determine realistic estimates of incremental production associated with new well drilling. The 3D model results were initially validated through the measurement of pressures on eight infill wells drilled during 1985. Discussion The following discussion details the basic data requirements for the model work, describes both the single-well (2D) and multiwell (3D) models, and provides an example analysis of an infill well location using both models. The single-well model was used to provide historical performance matches of existing wells for later use in the multiwell model. The single-well model can also be used to predict reserves of a proposed infill well. The modeling comparison predict reserves of a proposed infill well. The modeling comparison section of this discussion illustrates the benefits of using the multiwell model vs. the single-well model for the determination of infill-well reserves. Gas Properties. Separator tests from wells in each field area were used to estimate an average Yellow zone well-stream composition. Gas viscosity was estimated by Thodos-type correlations. Other gas properties were determined with the modified Redlich-Kwong equation properties were determined with the modified Redlich-Kwong equation of state. These field average properties were used in all pressure-transient and modeling efforts. pressure-transient and modeling efforts. Initial Reservoir Pressure. Estimates of initial reservoir pressure in the various field areas were determined from early well-pressure bomb measurements (greater than 140-hour shut-ins). The average pressure gradient in this Cotton Valley area equaled 0.55 psi/ft [12.4 kPa/m] (15 wells). Previous literature has documented the overpressured nature of the Yellow zone as compared with the uphole Cotton Valley sand intervals. Porosity, Water Saturation, Net Pay. Yellow zone volumetric gas Porosity, Water Saturation, Net Pay. Yellow zone volumetric gas in place was determined through detailed well log and core analyses. Some of the techniques used to estimate net pay in the Cotton Valley have been presented previously. Field average porosities and water saturations for the pay intervals ranged from 5.7 to 7.9% and from 27 to 49%, respectively. Formation Flow Capacity. Documented tight-gas-sand prefracture pressure-buildup techniques were used to analyze pressure-buildup pressure-buildup techniques were used to analyze pressure-buildup data from more than 100 Yellow zone producers. Average field values of formation flow capacity ranged from 0.39 to 0.92 md-ft [1.9 ร 10(-1) to 2.8 ร 10(-1) mdm]. Real-gas pseudotime and pseudopressure were used in conjunction with the equivalent-time function for the analysis. Refs. 5 and 6 detail the benefits associated with using these modified time and pressure functions in tight-gas reservoirs. Fracture Flow Capacity and Half-Length. Postfracture analysis of all available test data was attempted. Two techniques were used:the constant-rate and the constant-pressure type curves developed by Agarwal et al. for use in finite-flow-capacity fractures. With these techniques, values for fracture half-length, Lf, and dimensionless fracture capacity, FCD, were estimated. A third method, the scalar technique discussed by Tison et al. was also tested and found to provide some assistance in generating estimates for Lf. JPT P. 881
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Louisiana > Cotton Valley Field (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation > Cotton Valley Sand Formation (0.98)
- (4 more...)
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 ร 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.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- North America > United States > Wyoming > Greater Green River Basin > Sand Wash Basin > Niobrara Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Rulison Field > Mesaverde Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.94)
Abstract The Appalachian Basin contains a number of low permeability formations which have produced natural gas for many years. The lack of reliable data/information pertaining to parameters controlling production of natural gas from such low permeability (tight) gas bearing formations has hindered their continuous economic development. The data that have been available usually consisted of isolated date points held within the company files without a mechanism for comparison with other similar formation(s) in the Appalachian Basin. This has effectively prohibited the development of any kind of statistically bass from which one might infer the production mechanism, predict performance, determine the responsiveness of formations to stimulation treatments, and delineate the high potential areas for future development. The overall goal of this study in directed towards answering some of the questions needed to help the eastern low permeability formations become viable candidates for future development. This research project endeavors to solve the problem, at least for a subset of the tight gas bearing formations consisting of Big Injun, Boron, Benson, Oriskany, Big Six and Tuscarora that exist in the Appalachian Basin. The research objectives have been achieved through:Development of a Database through collection, interpretation, and compilation of data relative to completion, production, and stimulation on the eastern tight gas formations so that a good research foundation can be established. Analysis of the data so that the key parameters affecting gas producing can be identified and quantified. It should be noted that the Database contains data on over 1200 wells in Kentucky, Now York, Ohio, Pennsylvania Virginia, and West Virginia. The information has been collected from a variety of sources including many gas companion. The Database can be utilized to identify and evaluate a range of lithological, reservoir, and treatment parameters which control the production of natural gas from the eastern tight gas formations. The utilization of the Database and its applications relative to identification and evaluation of the potential areas for future economic development are discussed in this paper. Introduction It is widely recognized that the proven gas reserves of the eastern United States would be substantially increased if light formation gas resources could be developed more economically. These formations are characterized by insufficient permeabilities to allow economical production. Although the introduction of various stimulation treatments has improved the outlook for increased production, the general applicability of theme treatments is uncertain. Difficulties in reservoir characterization and prediction of the responsiveness of the formation to stimulation treatments are among the major problems. It must also be pointed out that the development of tight formations is limited not only by existing engineering technology but also by the identification of the areas where the technology can successfully be applied. The design and application of successful stimulation treatments requires collection and analysis of geological and reservoir data for determination of parameters which affect production. Therefore, it in necessary to accumulate enough relevant data on the eastern tight formations so that a good research foundation can be established.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Geology > Rock Type (0.71)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.66)
- North America > United States > West Virginia > Big Injun Formation (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (9 more...)
Summary. A dual seismic system designed to monitor the growth of hydrofractures was fielded during the first stimulation at the U.S. DOE-sponsored Multiwell Experiment (MWX) during Dec. 1983. The MWX consists of three 8,000-ft (2438-m) wells drilled in low permeability gas reservoirs. The wellbores are spaced less than 200 ft (60 m) apart most of their length. With this configuration, microseismic activity created by the fracture treatment in one well could be observed with downhole geophone packages in the two adjacent wells. packages in the two adjacent wells. Response of the two triaxial borehole seismic tools (BST's) were monitored in real time. Upon detection of a seismic event of known location, orientations of the BST's were determined from the polarization of the compressional wave arrivals. From knowledge of the horizontal and vertical angles of incidence and an empirical estimate of seismic velocities, the locations of the fracture-induced seismic sources were estimated. Thus the location of the microseisms could be estimated and, in turn, the fracture height and extent inferred. This paper presents the results of fracture diagnostics by use of this borehole seismic system for the first MWS stimulation. This information is compared and combined with the results obtained from other diagnostic techniques to provide an integrated estimate of the fracture geometry resulting from the stimulation. Introduction The Natl. Petroleum Council (NPC) estimates that there are 924 trillion ft (26.2 ร 10โ12 m3) of gas in place in U.S. tight-gas basins. Historically, tight-gas fields have been uneconomical and inefficient to produce because of low natural flow rates of gas. With the introduction of massive hydraulic fracturing, the outlook for increased production from blanket (continuous) formations has production from blanket (continuous) formations has improved. Current fracturing technology applied to lenticular tight-gas reservoirs containing more than 40% of the estimated recoverable tight gas, however, has been disappointing, and the general applicability of these treatments for unconventional gas reservoirs is uncertain. An MWS has been conceived to address the uncertainties concerning production of the lenticular tight-gas resource. Objectives of the field laboratory are to characterize lenticular gas-sands reservoirs and to evaluate technology for their production. A series of stimulation experiments has been planned to provide the data required to meet these objectives. Phase 1 of Stimulation Experiment 1 (SX-1) was completed in Dec. 1983. The primary goal of this experiment was to determine fracture behavior as a function of treatment volume as propagation progressed through and out of the lenses by monitoring microseismic activity created by the propagating fracture with downhole geophones, measuring pressure decay after shut-in for a Nolte-type analysis, running postfracture temperature logs, and analyzing treatment pressures. This paper summarizes the results of the fracture diagnostics obtained during the experiment with emphasis on the microseismic data. A more detailed treatment of the pressure and temperature data and the Nolte and treatment analyses has been reported by Warpinski. Site Description The MWS site is in the Rulison field in the Piceance basin of Colorado. It is located in Section 34, Township 6S, Range 94W, Garfield County, CO, 7 miles (11.3 km) west of Rifle and 1.4 mile (0.4 km) south of the Colorado river (see Fig. 1). The key feature of the MWX site is three closely spaced wells, Wells MWX-1, MWX-2, and MWX-3. Their separation at a depth of approximately 7,000 ft (2134 m) shown in Fig, 2, is less than the nominal dimensions as the stimulation/production well, while Wells MWX-2 and MWX-3 have been used for stress and interference testing ad for diagnostics. The first stimulation was performed in the paludal zone. This zone is organically rich, consisting of abutting sands and coals and situated at a depth of 6,600 to 7,450 ft (2012 to 2270 m). SPEFE p. 320
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Paludal Environment (0.62)
- North America > United States > Colorado > Piceance Basin > Williams Fork Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Rulison Field > Mesaverde Formation (0.99)
- North America > United States > Colorado > Piceance Basin > Mesaverde Formation > Williams Fork Formation (0.99)
Models of Quasi-static And Dynamic Fluid-driven Fracturing In Jointed Rocks
Shaffer, R.J. (Lawrence Livermore National Laboratory) | Heuze, F.E. (Lawrence Livermore National Laboratory) | Thorpe, R.K. (Lawrence Livermore National Laboratory) | Ingraffea, A.R. (Cornell University) | Nilson, R.H. (La Jolla) | Cubed, S- (La Jolla)
ABSTRACT: We describe the development and the applications of a numerical model to simulate fluid-driven fracturing in rock masses. It is a finite element computer program which couples solid mechanics, fracture mechanics and fluid mechanics. The fractures are driven either in a quasi-static fashion by conventional hydrofracturing liquids, or in a dynamic fashion by gases from burning solid propellants. Fracture propagation can be arbitrarily -modeled in a mixed-mode, in media which already contain discontinuities. The code is applied to the analysis of stimulation of tight gas reservoirs such as the Gas Sands in the Western U.S. and the Coal Beds in the Southern U.S. RESUME: On presente un nouveau modรจle numerique qui simule la propagation de fractures par des fluids, dans les milieux rocheux. Ce programme d'elements finis intรจgre de facon couplee la mecanique du milieu continu, la mecanique de la fracture et la mecanique des fluides. Les fractures se propagent de faรงon quasi-statique, comme en hydrofracturation classique, ou de faรงon dynamique, comme lorsque poussees par la deflagration de propergols. Le cheminement des fractures est arbitraire, en mode mixte, dans un milieu qui peut dejร รชtre discontinu. On presente des applications ร l'analyse de la fracturation dans les reservoirs de gaz ร roches trรจs peu permeables tels que les grรจs lenticulaires de l'ouest des U.S.A; on decrit aussi une analyse de fracturation pour degazage de bancs de charbon dans le sud des U.S.A. ZUSAMMENFASSUNG: Wir berichten ueber die Entwicklung und die Anwendung eines numerischen Modelles fuer Fluessigkeit betriebenen Bruch in geklueftetem Fels. Das Modell ist ein finites Element Computermodell das die Mechanik der Festkรถrper, der Fluessigkeiten und der Brueche gleichzeitig berechnet. Die Brueche werden entweder quasistatisch oder dynamisch durch Brennabgase von Festantriebsstoff betrieben. Das Wachstum von Bruechen kann beliebig in Kรถrpern berechnet werden die schon Diskontinuitaten enthalten. Das Computermodell wird auf die Anregung von Gas Reservoirs wie die Gas Sande in den west lichen Vereinigten Staaten und wie die Kohlelagerungen in den suedlichen Vereinigten Staaten angewendet. 1. INTRODUCTION To recover gas from low permeability formations it is necessary to "stimulate" the rock reservoirs, that is, to produce large, man-made fractures that penetrate the reservoirs and drain the gas toward wells. Fractures can be created either by injecting fluids under presure (hydrofracturing) or by burning solid propellants in the wells. To use either technique effectively, one must be able to predict how the rock will fracture. Rock reservoirs already contain natural fractures and joints, making it difficult to predict the effects of induced fracturing. An analysis of fracturing in such a medium must include models for the joint systems, and for the preexisting cracks packed with infill material. The joints are subject to compressive and shear forces; if compression becomes large, the joints become very stiff, and if shearing becomes too large, slippage occurs. Consequently, in a useful model, joint properties must change with stress conditions. In the Western gas sands, interfaces are the regions where shales and sandstones meet, and these interfaces behave much like joints. We have developed a computer code, FEFFLAP (Finite Element Fracture and Flow Analysis Program), that has enabled us to make great progress in describing the complex physics of fluid-driven fractures propagating in jointed media [1,2]. The coupled FEFFLAP model includes solid mechanics, fracture mechanics, and fluid mechanics. From the quasi-static to the dynamic regime this has applications to fluid-flow in jointed rocks, hydraulic fracturing for hydrocarbon recovery, and comminution of rock masses. For dynamic analyses, the steady-state FEFFLAP was coupled to the FAST fluid dynamics module [3]. 2. DESCRIPTION OF THE QUASI-STATIC FRACTURING MODEL 2.1 The Solid Fracture Model (FEFAP) Our FEFFLAP code represents the coupling of the FEFAP discrete fracture propagation code [4] and of the JTFLO program, a LLNL-enhanced version of an earlier code for analysis of fluid flow in rock fractures [5]. FEFAP analyzes planar and axisymmetric structures for crack initiation and growth. The program combines fracture mechanics theory, the use of interactive computer graphics, and a unique, automatic remeshing capability to allow the user to initiate and propagate up to ten discrete cracks simultaneously. The salient capabilities available in FEFAP were:โcomplete interactive-graphical execution of the program. One is not locked into a batch-produced result via the initial data input. โautomatic, discrete crack nucleation at arbitrary points and angles on an edge, as specified by the analysis. โautomatic, discrete crack propagation capability with optional interactive mesh adjustment along the propagating crack. โautomatic nodal adjustment for singular elements, and direct, automatic extraction of the stress intensity factors.
- North America > United States > Colorado (0.28)
- North America > United States > Alabama (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.88)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.54)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (0.54)
ABSTRACT ABSTRACT We have expanded our quasi-static finite element coupled fracture and flow model FEFFLAP to allow for time-dependent tracking of the fluid-driven fractures, under a constant pressure or a constant flow rate at the borehole inlet. These conditions apply to gas-driven fractures and to hydraulically-induced fractures, respectively. Example calculations are given to validate these new developments. INTRODUCTION model crack propagation in arbitrary directions characterize joints and interfaces, including their non-linearities, and reproduce fluid flow in cracks and joints. Stimulation of tight (impermeable) gas reservoirs involves the use of either large hydraulic fractures to drain gas-bearing sandstones in the Western tight gas reservoirs, for example, or propellant-driven multiple fractures to maximize drainage area around wells in Eastern shales. Analysis of these processes is complicated by the natural fractured state of the formations before stimulation. Theoretical models which hope to address these fracturing phenomena must be designed so that they will: Our FEFFLAP model (Einite Element Fracture and FLow Analysis Program) has these capabilities. The original quasi-static version of the model was documented previously. It was verified with fracturing experiments across slanted interfaces, as well as analytical solutions to single and multiple pressurized crack problems. It provided solutions to problems involving coupled elastic deformation and steady-state fluid flow with out-of-plane fracture modeling capabilities. FEFFLAP has now been expanded to time-dependent fluid flow by coupling it with the FAST module for gas-dynamics in fractures. Figure 1. Six-fold symmetric cracking from a borehole. All cracks propagate radially outward at the same speed.(available in full paper) Figure 2. Two-fold symmetric cracking from a borehole. The long cracks are extending nearly three times faster than the short cracks.(available in full paper) The time-dependent fluid flow version of FEFFLAP has been verified by checking it against self-similar solutions for constantly pressurized boreholes. 1 The model has also been verified for a constant flow rate into the crack at the borehole and for pressure- driven multicrack problems. Details are provided below, after a short description of the new fluid dynamics formulation from FAST. THE TRANSIENT FLOW-IN-FRACTURE MODEL The FAST model is quite general and allows for gas and liquid flow, laminar and turbulent frictional flow, and permeable flow. The solution of problems is obtained from coupled elastic fracture equations and fluid flow equations; each provide boundary conditions to the other. When operated in the stand-alone mode the elastic fracture equations result from a single in-plane crack formulation. The fluid velocity and pressure distribution in a propagating crack are determined from a one-dimensional analysis of momentum, heat, and mass transport down the fracture. Heat and fluid losses into the fracture walls can be included in an analysis. The conservation equations are satisfied in a global or "integral" sense over three regions of the flow, including: (1) the entire volume of the fracture, (2) a small sub-volume at the leading edge of the flow, and (5) the borehole or cavity volume which feeds the fracture. The other equations are all satisfied on a local basis.
- Geology > Geological Subdiscipline > Geomechanics (0.71)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.92)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (0.69)
SPE Members Abstract As an increasing number of gas fields are being developed or are planned to be developed in the permian red beds (Rotliegendes) of northwest Europe, hydraulic fracturing has become a major stimulation method to obtain economic production rates from this tight gas formation. Optimization of stimulation design and its implementation in the field become more crucial in the formation such as Rotliegendes, where a water bearing zone is underlain. The objective of this work was to simulate fracture growth under various conditions so that optimal treatments can be designed and implemented successfully to this tight gas reservoir. Formation rock properties of the payzone and adjoining barriers, fracturing fluid properties and their leakoff coefficients selected were experimentally determined in the laboratory using various Rotliegendes core samples. A 3-D model of Meyer and Associates was used to simulate the fracture length, width, height, proppant transport and settlement, fracture closure, and post-frac performance. The same treatment data were simulated using a 3-D model developed by Palmer and Carroll. Results obtained from the two models are compared on a rational basis. Two field applications are presented to demonstrate the proper design and successful stimulation treatments in the Rotliegendes. Introduction Since the discovery of the giant Dutch Groningen gas field in the north of the Netherlands (discovery well, Slochteren 1, 1959), an increasing number of gas fields are being developed or are planned to be developed in the permian basin of the North Sea, the Netherlands, Denmark, and Western Germany. The permian red beds of northwest Europe (or better known as "Rotliegendes" in Germany) are continental elastic sediments deposited under desert and semi-desert conditions. The mineralogical study of several Rotliegende core samples indicate that the sandstone primarily consists of quartz with minor dolomite, illite, and kaolinite (migrating type clays) and dawsonite (a bladed mineral). The general texture of such rock is shown in Figure 1. The proved and probable reserves of Rotliegendes gas in the North Sea, Netherlands, and Western Germany is estimated to be about 85x 1012 cu.ft. The development of these fields is only possible if the gas production rates can be maximized by effective hydraulic fracture treatments. Optimum fracture treatment techniques can substantially improve the supply of natural gas from these tight gas reservoirs. The effectiveness of hydraulic fracturing in a tight gas reservoir is strongly affected by the geometry of the created fracture. The geometry of a fracture deals with the propped fracture height and areal extent. The intrusion of a fracture from the payzone into the formations lying above and below is a serious concern in a fracture design. Moreover, if the hydraulic fracture is not contained within the producing formation and propagates in both the vertical and lateral directions, failure of the treatment can occur because there is a substantial loss of fracture fluid and proppant used to fracture the unproductive formations. The containment of a fracture within the producing zone is even more important where the underlying zone is water bearing. P. 247^
- Europe > United Kingdom > North Sea (0.44)
- Europe > Norway > North Sea (0.44)
- Europe > Netherlands > North Sea (0.44)
- (2 more...)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.66)
- North America > Canada > Alberta > Meyer Field > Aecog Meyer 11-27-70-26 Well (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > P 033 > Rotliegendes Formation (0.99)
- Europe > Netherlands > Groningen > Southern North Sea - Anglo Dutch Basin > Groningen License > Groningen Field > Upper Rotliegend Formation (0.99)
- (5 more...)
Abstract The Gas Research Institute's (GRI) Tight Gas Sands Program has been involved with research on low permeability formations during the past four years. The main focus of the research has been to improve the general understanding of producing tight reservoirs, while a specific focus has been to advance the technology involving hydraulic fracture geometry. The unique aspect of this research is that the laboratories have been actual gas wells completed in the Travis Peak formation in East Texas. To fully extend the development of technology, GRI has planned four Staged Field Experiments (SFE) from 1986 through 1989. The SFE program provides the opportunity to collect a wealth of data that cannot be obtained from normal cooperative research wells. The purpose of this paper is to summarize all the tests and data collected on the first SFE and to present the available results from the analyses of these data. Introduction Research is currently being sponsored which is directed at reducing the cost and improving the recovery of gas produced from low permeability reservoirs. Because the most viable method of improving recovery in tight formations is hydraulic fracturing, part of the research effort is aimed at better understanding the processes which control fracture growth. If the petroleum industry can substantially improve its ability to accurately predict and control the shape of hydraulic fractures, then the chances of achieving optimum propped fracture lengths are increased. The end result will be an improved economic incentive for developing tight gas reservoirs. To better understand the hydraulic fracturing process, it is first necessary to improve our understanding of both the reservoirs that are being fracture treated and the formations surrounding the main productive interval. To achieve this goal, a comprehensive program was initiated to perform geological, coring, logging, well testing, fracture treatment monitoring and fracture diagnostic studies on selected cooperative research wells in the Travis Peak formation of the East Texas Basin. Our technical approach is to use the necessary electronic equipment and computers in the field so that the GRI contractors may actually analyze the fracture treatment data in real time. Once this system is perfected, we should be capable of predicting fracture shape and extent. If this can be successfully accomplished, we will then attempt to control fracture growth by controlling the fracture fluid viscosity or the injection rate.
- North America > United States > Texas (1.00)
- North America > United States > Louisiana (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.48)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.93)
- North America > United States > Texas > Travis Peak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Whelan Lease > Waskom Field > Lowe Paluxy Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (11 more...)