Unique Multistage Process Allows Pinpoint Treatment of Hard-to-Reach Pay

Abstract

Summary Perforating multiple-pay intervals to achieve optimum treatment coverage has long been a topic of considerable debate. Perforation selection can play a crucial role in well performance. The consequences of inadequate perforation coverage can compromise fracture optimization, limit production, result in missed pay, and limit reservoir access. Multizone-fracture treatments have been performed in the past with a variety of methods ranging from limited entry to mechanical isolation with bridge plug and packer. These and other techniques routinely have been applied to stimulate discrete intervals within a formation in an attempt to maximize the production of discrete-pay zones or stringers. One method consists of perforating and isolating each zone, then performing the stimulation treatment. Wireline is used to isolate the previous zone and perforate the next stage. The treatment of multiple intervals in this manner can be a costly and time-consuming process. A new multistage treatment process optimizes perforation and treatment design. This technique, known as "external casing perforating" (EXCP) allows the operator to perforate and isolate individual zones in as little as 5 minutes between treatment stages. As many as 17 discrete intervals have been treated within a 24-hour period. Moreover, this approach minimizes total-treatment volume by using the flush from the previous stage as the pad on the next stage, thus placing less fluid on the formation. The time to first sales has been reduced from days to a matter of hours by eliminating bridge-plug isolation and costly post-job cleanup. Production from multiple horizons may be brought online quickly in one rigless operation without damaging and time-consuming shut-ins. This paper describes the perforating and stimulation technique and quantifies cost savings to the operator associated with the reduced volumes and time saving. Additional benefits, such as reductions in friction pressure and polymer damage, and means for fracture optimization also will be discussed. Introduction In common practice, economic factors dictate pay selection in a given wellbore. In multizone completions, difficult choices must be made when determing whether to sacrifice optimum zonal coverage or to selectively isolate and stimulate discrete-pay intervals or stringers. In the selection process, productive intervals may be sacrificed or left behind because of economic considerations. In some cases, these zones have gone unproduced for years. These intervals could represent access to several hundred feet of idle reserves. Two such intervals were discovered in the Wilshire Devonian field in west Texas. During fracture stimulation, it became evident that part of one interval had substantially higher bottomhole pressure than the adjacent zones, making it more challenging to stimulate with limited-entry techniques (Lagrone et al. 1963). A post-job-tracer survey documented results from an attempt at limited entry where the middle zone was left unstimulated (Fig. 1). Previously, 3D fracture simulators indicated that the zones would fuse in a single fracture. Once an aggressive stimulation program was initiated, the higher pressures were verified by production logs and bottomhole-pressure tests. Bottomhole pressure, a key component in stress calculation, proved to be a key factor in zonal isolation and effectively stimulating these zones. The main consideration is pay identification for optimal-treatment coverage. In many cases, criteria for productive intervals must be redefined on the basis of in-field test analyses and, ultimately, production. What was once considered a nonproductive interval might prove economic in the future, especially as petroleum pricing drives the technology necessary to extract hard-to-reach reserves. Advances in log analysis, computer modeling, and 3D seismic surveys have further enhanced the industry's ability to rapidly identify and evaluate potential pay intervals (Mendoza 1996; Davies et al. 1994; Warpinski et al. 1995). Operators surveyed by the Gas Research Inst. (GRI) in the mid-1990s recognized opportunities for future improvements in production rates and cost reduction through the use of these new technologies (Penny and Conway 1996). The initial completion on a well can have an enormous impact on the ability to effectively access and produce the entire reservoir. After completion, it may not be practical to reenter a wellbore to reacquire missed pay. An optimized completion process is less costly and far more efficient during the initial completion. Any net gain in reserves must be weighed against completion cost. In many cases, risk associated with the initial completion may persuade an operator to resist technology that may provide optimum production and reservoir access. Technology often requires some initial risk and diligence in new applications to justify a project. The EXCP completion process is no exception, especially because most of the cost is incurred during drilling. Most drilling departments are driven to reduce cost and may not realize the potential of the EXCP process to reduce final completion cost, reduce formation damage, and increase booked reserves.