Perforating Requirements for Fracture Stimulations
- L.A. Behrmann (Schlumberger Perforating and Testing Center) | K.G. Nolte (Dowell)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- December 1999
- Document Type
- Journal Paper
- 228 - 234
- 1999. Society of Petroleum Engineers
- 2.5.2 Fracturing Materials (Fluids, Proppant), 5.3.3 Particle Transportation, 2.5.4 Multistage Fracturing, 5.1.2 Faults and Fracture Characterisation, 5.4.2 Gas Injection Methods, 2.4.3 Sand/Solids Control, 1.14 Casing and Cementing, 1.6 Drilling Operations, 2 Well Completion, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.2.2 Perforating, 4.1.2 Separation and Treating, 4.3.4 Scale, 2.4.6 Frac and Pack, 2.4.5 Gravel pack design & evaluation, 2.7.1 Completion Fluids, 3.2.4 Acidising, 2.5.1 Fracture design and containment
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Perforating provides the means of communication between the wellbore and the reservoir, and in a fracture-stimulated reservoir, the perforation is the fluid conduit between the fracture and the wellbore. The existence of, or lack of, a hydraulic microannulus critically affects the choice of perforating parameters. The existence of a microannulus is dependent on reservoir and wellbore properties, perforating parameters, and fracture stimulation execution.
Recommendations are provided to choose the best perforating parameters of: shot phasing, shot density, type of charge interval length and gun orientation. Recommendations are provided for hard and soft rock hydraulic fracturing and extreme overbalance stimulation.
Within this paper, fracturing implies using proppant. However, in general the presentation also applies to acid fracturing. The choice of perforating parameters can have a significant affect on the quality of the subsequent fracturing or matrix stimulated treatment.1-4 For the combination of gravel packing and fracturing (frac and pack), perforating practices are governed by the gravel-packing considerations. These considerations are discussed in the "Frac and Pack and High-Rate Water Packs" section.
The objective of perforating for fracturing is to choose perforating parameters that minimize near-wellbore pressure drops during both the fracturing operation and production with limited-entry fracture placement being an exception. Some of these near-wellbore effects are perforation friction, microannulus pinch points from gun phasing misalignment, multiple competing fractures and fracture tortuosity caused by a curved fracture path.5 Several of these near-wellbore effects from Romero et al. are illustrated in Figs. 1 and 2. For any type of well treatment, there are two additional perforation-related parameters that may also affect the choice of the perforating system: the integrity of the cement/sandface hydraulic bond (microannulus) after perforating and residual fractured-sand grains in the perforation cavity, particularly for a matrix treatment. Effective matrix treatments require communication through most of the perforations. This can be achieved by either effective underbalance, extreme overbalance (see "Extreme Overbalance Stimulation" section), or ball-out. If a reservoir is perforated with insufficient underbalance to remove most of the perforation sand debris, then fluid injection may cause the comminuted sand to create an external filter cake on the perforation cavity during fluid injection. This was first observed on a water injector and later on extreme overbalanced tests.6 Two unique characteristics were observed in these tests: productivity was not affected, and this "filter cake" was also an injection pressure barrier with an estimated pressure drop of more than 1,000 psi. The existence of comminuted sand in the perforation cavity limits injectivity and increases the injection pressure. High pump rates and high fluid viscosity enhance these effects, which are more important for extreme overbalance stimulation.
A microannulus is usually present after perforating and/or immediately after pumping begins. Maintaining a good bond during the breakdown phase can be problematic because of a hydraulically propagated microannulus that is analogous to hydraulic fracturing, as discussed in Appendix A. Fracturing then proceeds as though from an open hole with some defects (perforations) that may be near the preferred hydraulic fracture plane (PFP). Most laboratory fracturing studies have taken extraordinary measures to avoid a microannulus by epoxying the casing to the rock, using O-rings around the perforations, etc. Thus, the generality of these laboratory findings must be viewed with caution. The magnitude of the microannulus is dependent on the wellbore fluid and size and type of perforating gun (Table 1).
Except when gas is the wellbore fluid, perforating debonds a portion of the cement/sandface hydraulic bond. This is a result of the loading of the wellbore fluid from the gun swell (charge/explosive coupling for capsule charges), passage of the perforating jet through the wellbore fluid, and expulsion of the explosive detonation gases into the wellbore fluid. For hollow carrier guns, the debonding may be a function of the gun phasing. The debonding promotes the creation of a micorannulus during formation breakdown as discussed in Appendix A. Figs. 3a and 3b are examples of cement debonding observed in large-scale block tests7,8 with the microannulus effect evident in Fig. 3b.
An ideal perforation for fracture initiation would have a minimum injection pressure, initiate only a single fracture and generate a fracture with minimum tortuosity (turning from the initiated fracture into the PFP) at an achievable fracture initiation pressure. The following sections provide recommendations on how best to achieve this ideal perforation. In the following sections, a vertical well is one with deviation less than 30°.
Perforation Phasing for Hard-Rock Hydraulic Fracturing
No Microannulus, Vertical Wells.
For the following discussion, the PFP is assumed to be vertical and therefore can connect directly over a significant distance for a vertical well. When the PFP is not vertical, as can occur near a significant fault, the PFP deviates from the axis of a vertical well. For this case, the "Deviated and Horizontal Wells" section should be consulted.
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