Summary Severe fracture-conductivity damage can result from proppant crushing and/or proppant flowback into the wellbore. Such damage is often concentrated near the wellbore and can directly affect postfracture performance. Most of the time severe fracture-conductivity damage can be minimized by choosing the correct type of proppant for a particular well. In many cases, however, this is not enough. To minimize excessive crushing or to prevent proppant flowback, it is also necessary to control carefully the flowback of the well after the treatment. Specific procedures can be followed to minimize severe fracture-conductivity damage. These procedures involve controlling the rates at which load fluids are recovered and maximizing backpressure against the formation. These procedures require much more time and effort than is normally spent on postfracture cleanup; however, the efforts could result in better performance. Introduction Because of the ever-increasing development of low-permeability oil and gas reservoirs, hydraulic fracturing has become one of the most important aspects of a a well completion. A fracture treatment can account for 10 to 50% of the total well cost.1 Thus, significant emphasis should be placed on optimizing the treatment design, especially the selection of proppant.2 However, there is another aspect of the treatment that is just as important, but is often overlooked or taken for granted - i.e., the flowback and cleanup of the well immediately after the fracture treatment has been pumped. The detrimental effects of reduced fracture conductivity on well performance have been documented in the petroleum literature.3,4 Such damage can result primarily fromfracture plugging resulting from gel residue, fluid loss additives, or formation fines;severe proppant crushing; orproppant flowback in the wellbore. Severe crushing and proppant flowback are the major topics of discussion in this paper. These factors have been found to cause drastic reductions in fracture conductivity, particularly near the wellbore.5,6 In many cases, the damage has occurred as a result of flowing the well too hard in an attempt to produce more oil or gas. A brief review of inflow performance relationships, however, illustrates that very little additional production will result from this additional drawdown. Most of the time, this near-wellbore damage can be prevented by choosing the correct type of proppant and by carefully controlling flowback after the treatment.7 Even though a growing number of engineers now recognize this fact, there appears to be a need for further awareness in the field, where many of these operations are controlled. Basically, there is a lack of case histories in the literature that document fracture-conductivity damage on actual wells and that illustrate and emphasize to industry the severity of the problem. Foremost, there are no guidelines and procedures that are generally accepted by industry on how to minimize this damage. This paper presents field examples in which severe crushing and the production of proppant into the wellbore have occurred. In each of these cases, the problems can generally be attributed to flowing the wells too hard. Finally, techniques are discussed and procedures are recommended for minimizing these effects. Postfracture Pressure Decline Several papers8,9 have been written that describe techniques for analyzing fracture-injection pressures during the job and the pressure decline after the treatment is over. These techniques can be used to determine a variety of parameters that help to quantify a fracture and the fracturing process in general. One of the most significant variables determined from postfracture pressure-decline analysis is the fracture-closure pressure, which is important because it is approximately equal to the least principal stress. The fact that the fracture has closed, however, is critical from the standpoint of trapping the proppant before it has a chance to settle in the fracture. In addition, the fracture should be closed before the well is opened for cleanup. Measurement and detection of fracture closure require that an accurate pressure gauge be left on the wellhead or in the hole after the treatment is completed. The rate of pressure decline will depend on the leakoff characteristics of the formation. Thus, in permeable formations, the pressure may fall off rapidly, allowing the fracture to close in a relatively short period of time. Discussion of Field Case Histories. Fig. 1 presents the pressure-falloff data for a gas well in Indonesia, which illustrate such a high-permeability case. These pressure data are plotted vs. the square root of shut-in time. For this example, the reservoir permeability was about 1.5 md and the fracture closed at a square root of time equal to 0.53 hours or about 17 minutes. The fracture-closure pressure determined from these data was 6,930 psi [47.8 MPa] at the surface, which was equal to 13,000 psi [89.6 MPa] at bottomhole conditions. The value of closure stress gradient (0.95 psi/ft [21.5 kPa/m]) determined from these falloff data was approximately equal to other values obtained in this field from in-situ stress tests. This example illustrates fairly rapid fracture closure, and in such cases, one would not be too concerned about proppant settling. In low-permeability reservoirs, however, 12 to 24 hours may be required before the pressure declines sufficiently to allow fracture closure. In these instances, it may be necessary to flow the well back slowly on a 2/64- or 3/64-in. [0.8- or 1.2-mm] choke to bleed off pressure from the well and to assist fracture closure. In doing so, some proppant may be produced into the wellbore; however, because of the low flow rates that are recommended (5 to 10 gal/min [0.019 to 0.038 m3/min]), only a small amount of proppant is likely to be produced. After fracture closure is detected or when the pressure is bled down to below the known value of closure pressure, then the well should be shut in to allow the gel to break. Discussion of Field Case Histories. Fig. 1 presents the pressure-falloff data for a gas well in Indonesia, which illustrate such a high-permeability case. These pressure data are plotted vs. the square root of shut-in time. For this example, the reservoir permeability was about 1.5 md and the fracture closed at a square root of time equal to 0.53 hours or about 17 minutes. The fracture-closure pressure determined from these data was 6,930 psi [47.8 MPa] at the surface, which was equal to 13,000 psi [89.6 MPa] at bottomhole conditions. The value of closure stress gradient (0.95 psi/ft [21.5 kPa/m]) determined from these falloff data was approximately equal to other values obtained in this field from in-situ stress tests. This example illustrates fairly rapid fracture closure, and in such cases, one would not be too concerned about proppant settling. In low-permeability reservoirs, however, 12 to 24 hours may be required before the pressure declines sufficiently to allow fracture closure. In these instances, it may be necessary to flow the well back slowly on a 2/64- or 3/64-in. [0.8- or 1.2-mm] choke to bleed off pressure from the well and to assist fracture closure. In doing so, some proppant may be produced into the wellbore; however, because of the low flow rates that are recommended (5 to 10 gal/min [0.019 to 0.038 m3/min]), only a small amount of proppant is likely to be produced. After fracture closure is detected or when the pressure is bled down to below the known value of closure pressure, then the well should be shut in to allow the gel to break.

No abstract

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 SFE program provides the opportunity to collect a wealth of data that cannot be obtained from normal cooperative research wells.

Summary. In layered, complex, low-permeability gas reservoirs, the problem of excessive fracture-height growth and erratic fracture-growth patterns make fracture-treatment design and evaluation very difficult. In this paper, we describe the importance of collecting and analyzing data before, during, and after a hydraulic-fracture treatment so that the three-dimensional (3D) properties of both the formation and the fracture can be determined. Introduction Hydraulic fracturing has long been the most successful technique for stimulating low-permeability reservoirs. Deep penetrating fractures can substantially improve productivity and ultimate recovery to the point where uneconomical wells can become profitable. Many publications have illustrated the merits of obtaining tong, highly conductive fractures in low-permeability reservoirs, however, other publications have clearly shown that creating and propping long fractures is a difficult task. Several reasons have been recognized for the general failure to achieve long, highly conductive fractures. Perhaps the most common cause of poor fracture-treatment response is excessive fractureheight growth. If the excess pressure in the fracture becomes too large, excessive fracture-height growth will occur. When the fracture height is not contained, it becomes difficult to predict the shape of the fracture. Knowledge of the fracture shape is important if one wishes to estimate the propped-fracture dimensions. Many low-permeability reservoirs are multilayered systems. A typical low-permeability gas reservoir will contain alternating layers of sandstone, siltstone, and shale. These alternating layers win have various properties-e.g., thickness, porosity, fluid, saturations, per-meability, Young's modulus, and in-situ stress. To use 3D fracture design models, 11–14 it is absolutely necessary that these layered, complex reservoirs be properly defined in 3D. Of equal importance to fracture-treatment design is fracture-treatment evaluation. Accurate postfracture formation evaluation is necessary to understand what has occurred during a fracture treatment, so the fracture-treatment design can be improved on the next well. To perform an accurate postfracture formation evaluation, one must first perform an accurate prefracture evaluation. There are too many unknowns to obtain a unique postfracture solution, if some of the variables are not solved during the prefracture log, core, and well-test analyses. Prefracture Formation Evaluation Geologic Considerations. The first phase of a comprehensive formation evaluation must begin with a geologic analysis. Regional geologic studies are important, so that the environment of deposition can be established. The main concern is to determine how the sediments were deposited and whether the environment of deposition was conducive to forming blanket or lenticular reservoirs. To optimize the size of a hydraulic fracture treatment, one must optimize the ratio of fracture length, L f, to drainage radius, r,. In blanket reservoirs, the fracture length and the well spacing can be optimized by forecasting the present value of the future net income for a variety of fracture lengths and drainage areas. The optimum values of fracture length and well spacing will be the combination that maximizes present value for a given set of economic criteria. In lenticular reservoirs, however, it is necessary to rely on geologic expertise to determine the most probable value for drainage radii's. With an estimated value for drainage area, the engineer can determine the fracture length that will be needed to optimize the present value of the well- Regional geologic studies can be of benefit when one needs to understand the potential size and shape of the reservoirs that are to be fracture-treated. Once the regional geologic studies have been completed, localized geologic studies should be performed near the well to be fracture-treated. To design and evaluate a fracture-treated reservoir in 3D, the local geologic characteristics also must be known in 3D. Cross sections, structure maps, and isopach maps of the various layers of rock in and around the formation to be fracture-treated can be very important to the design of the treatment. The thickness and areal extent of all rock layers, including sandstones, siltstones, and shale intervals, must be known or estimated to use 3D fracture design models properly. It is also important to understand the size, shape, and areal extent of the permeable producing intervals if one expects to use a 3D reservoir model to analyze production and pressure-transient test data to calculate propped fracture dimensions Coring and Core Analysis. One of the more important aspects of formation evaluation is coring and core analysis. Actually seeing the formation rock material and measuring the physical and chemical properties of the reservoir rocks are invaluable contributions to a comprehensive formation evaluation. Accurate core analysis begins with proper core-handling procedures in the field. Oriented core should be cut, when possible, and care should be taken to remove the core from the core barrel so as to minimize breakage. The cores should be wiped with rags to remove any drilling fluids, and the core should be marked so that it can be reassembled correctly in the processing laboratory. The core also should be measured, with even foot marked for depth. Once the core has been received in the processing laboratory, it should be reassembled and described in detail. A core gamma ray log should be run to correlate the depth of the cores to the openhole logs. Because the typical formation is a multilayered system, it is important that core be cut and obtained for all layers. In a productiv interval, one is normally more interested in measurements of permeability, porosity, and water saturation. These parameters are needed to determine the amount of oil and gas in place and the expected production rates from the reservoir. SPEFE P. 523^

No abstract