Minimizing Damage to a Propped Fracture by Controlled Flowback Procedures

Abstract

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.