Pin-Point Fracturing (PPF) in Challenging Formations
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOver 145 pin-point fracturing (
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Fracturing work conducted on the 2006 Tip Top/Hogsback (TTHB) field horizontal well program proved that sand plug isolation will work in horizontal wells, even when the stimulation treatment calls for fracturing with a high energy fluid. The TTHB field is a tight gas field in southwestern Wyoming, and the wells will not produce without a fracture stimulation treatment. This paper will describe the evaluation process of various fracturing technologies considered for the program, and how learnings from a 1995 horizontal program were used to build the final pinpoint stimulation design. In addition, this paper will discuss the stimulation execution and the learnings generated from the program. The fractured horizontal wells were drilled to 11,000 ft measured depth (MD), 7,200 ft true vertical depth (TVD), with the laterals being approximately 3,800 ft of the total measured depth. Eight fracture treatments were planned for each horizontal. The foam stimulation treatments contained 60-quality CO2 and averaged 235,000 lbm total proppant per zone. The basic stimulation procedure consisted of cutting perforation holes by use of a hydrajet tool on the end of coiled tubing (CT), pumping a fracture treatment down the production casing, and setting a sand plug with CT in the lateral to provide zonal isolation. This process allowed continuous treatment of successive intervals without shutting down to set a mechanical plug or perforate the next interval. Although several challenges were encountered during the execution of the stimulation treatment, the stimulation design did prove to be a more time efficient and cost effective option than conventional horizontal well fracturing treatments. The paper will discuss learnings on setting sand plugs between fracs, frac designs, and equipment operation/limitations. As a result of the learnings, the average treatment time decreased from 24 hr/zone on the first well to 13 hr/zone on the second. The paper will also discuss additional changes made during the stimulation execution to increase the effectiveness of the hydrajet tool and increase the probability of setting a successful sand plug. The process for designing and placing successful sand plugs was optimized from well to well and can furthermore be tailored to fit other fields. Learnings and techniques applied in this work can be used to improve and optimize fracturing treatments of similar nature in other geographic/geologic areas. Introduction The TTHB field is a tight gas field in southwestern Wyoming (Fig. 1) which has been produced since 1953. Production is primarily from relatively shallow, normal pressure, sweet gas formations. Based on the nature of these tight gas sands, TTHB wells will not produce without hydraulic fracturing. Formation properties are listed in Table 1.
Fracturing work conducted on the 2006 Tip Top/Hogsback (TTHB) field horizontal well program proved that sand plug isolation will work in horizontal wells, even when the stimulation treatment calls for fracturing with a high energy fluid. The TTHB field is a tight gas field in southwestern Wyoming, and the wells will not produce without a fracture stimulation treatment. This paper will describe the evaluation process of various fracturing technologies considered for the program, and how learnings from a 1995 horizontal program were used to build the final pinpoint stimulation design. In addition, this paper will discuss the stimulation execution and the learnings generated from the program. The fractured horizontal wells were drilled to 11,000 ft measured depth (MD), 7,200 ft true vertical depth (TVD), with the laterals being approximately 3,800 ft of the total measured depth. Eight fracture treatments were planned for each horizontal. The foam stimulation treatments contained 60-quality CO2 and averaged 235,000 lbm total proppant per zone. The basic stimulation procedure consisted of cutting perforation holes by use of a hydrajet tool on the end of coiled tubing (CT), pumping a fracture treatment down the production casing, and setting a sand plug with CT in the lateral to provide zonal isolation. This process allowed continuous treatment of successive intervals without shutting down to set a mechanical plug or perforate the next interval. Although several challenges were encountered during the execution of the stimulation treatment, the stimulation design did prove to be a more time efficient and cost effective option than conventional horizontal well fracturing treatments. The paper will discuss learnings on setting sand plugs between fracs, frac designs, and equipment operation/limitations. As a result of the learnings, the average treatment time decreased from 24 hr/zone on the first well to 13 hr/zone on the second. The paper will also discuss additional changes made during the stimulation execution to increase the effectiveness of the hydrajet tool and increase the probability of setting a successful sand plug. The process for designing and placing successful sand plugs was optimized from well to well and can furthermore be tailored to fit other fields. Learnings and techniques applied in this work can be used to improve and optimize fracturing treatments of similar nature in other geographic/geologic areas. Introduction The TTHB field is a tight gas field in southwestern Wyoming (Fig. 1) which has been produced since 1953. Production is primarily from relatively shallow, normal pressure, sweet gas formations. Based on the nature of these tight gas sands, TTHB wells will not produce without hydraulic fracturing. Formation properties are listed in Table 1.
As shown by technical papers as early as the 1960s, our industry has long known that hydrajetting perforations or slots through cemented casing could often "bail-out" a problem well that otherwise seemed completely resistant to hydraulic fracturing attempts. For most of the first 50 years of fracturing applications, few operators had sufficient demand for the fracturing process to make it a commodity service, especially before the advent of coiled tubing (CT) services in the 1980s. Often, this type of well service was costly because of the need for both abrasive mixing and high-pressure pumping. In many cases, it was too time consuming to be practical as an "every-well" application, and lower-cost conventional explosive shape-charge perforating seemed sufficient for most wells. As oil and gas prices have drastically increased in recent years, many operators have realized that for some well conditions, the use of hydrajet perforating (HP) can improve fracture stimulation efficiency and well economics. In a few cases HP has proven to be the only way that effective fracture stimulation could be achieved. In the past few years there has been a growing acceptance among both operators and service companies that hydrajet (abrasive jetting) perforating can improve overall well economics for fracture stimulated wells in many reservoirs. Some newer methodologies have combined hydrajet perforating and hydraulic fracturing into a single, continuous, multi-stage stimulation method. For many wells needing multiple fracture stimulations, significant reductions in nonproductive time (NPT) allows for reduced well costs even when more actual fracture stages are pumped. Use of more stages has often provided significant production gains and greater recoverable reserves. Enhanced stimulation success in many moderately hard and very hard formations have proven the value of converting from shape charge perforating to hydrajetting as a stand-alone operation to avoid severe near-wellbore problems during hydraulic fracturing stimulation treatments. Since about 2000, and especially during the most recent 5 years, service providers have progressively expanded the processes, which included hydrajet perforating, especially in conjunction with hydraulic fracturing methods. This paper will review the expanding applications of hydrajet perforating in recent years, including case histories from several global applications. Background Early technical papers tell us that hydrojetting (w/o abrasives) was used with acidizing and fracture acidizing as early as 1939, primarily in zones completed open hole. However, with the incorporation of solid abrasives (hydrajetting, using abrasives) the jetting nozzles in use then could only perform for minutes before excessive erosion became a problem. The literature also reveals that around 1958 there was a renewed interest in sand-jetting and more abrasion-resistant carbide jets were developed. In May, 1961, the Journal of Petroleum Technology included three landmark publications that presented much of what had been happening since 1958 with respect to HP applications, and described other hydrajetting wellbore functions such as jetting cement from casing, cutting casing, scale removal, and other applications. The more extensive of these publications (Brown et al. 1961, and Pittman et al. 1961) had first been presented at technical conferences in October, 1960. The shorter, introductory article (Ousterhout 1961) indicated that by early in 1961 over 5,000 hydrajetting jobs had been performed with a success rate in excess of 90%; more than half of these were perforating applications. At that time, explosive/shape charge perforating was still in its infancy, with bullet perforating still common.
This case history paper presents fracture stimulation using coiled tubing (CT) hydrajetting, followed by (1) annular-path pumping of the fracturing treatment and (2) use of high-concentration proppant slugs to create proppant plugs for diversion. The process of hydrajet perforating and annular-path pumping (HPAP) has been used effectively for vertical well completions and is especially applicable for multi-interval completions. Further, use of this process for multi-interval fracturing of horizontal well completions has been performed successfully in several North America reservoirs, and in Texas at depths below 15,700 ft true vertical depth (TVD) and measured depths (MD) of more than 16,700 ft. Cased and cemented horizontal completions present several challenges for the HPAP method, including (1) unique CT calculations and operating procedures, and (2) proppant plug-setting procedures. This multi-stage completion process can also be applied in other methods of horizontal completions that incorporate a solid liner. Several case histories are examined to (1) highlight lessons learned in performance of this method on horizontal well completions, and (2) demonstrate efficiencies gained as compared to following conventional practices. Introduction Fracturing methods aimed at improving operational efficiency by reducing nonproductive time (NPT) have increased in importance as assets are being completed that involve multiple intervals, thick pay intervals, or horizontal wellbores (McDaniel 2005). Some of these methods, such as the use of high fracturing rates and limited-entry perforating, greatly reduce the overall completion time but have been shown to be less than adequate in stimulating all targeted intervals (Craig et al. 2005). Other fracturing methods that focus on treating intervals individually can result in many hours of NPT mainly as a result of discrete process steps that require trips in and out of the well between treatments while pumping equipment resources remain idle or are required to leave and return to the wellsite. These discrete steps include trips for (1) perforating, (2) setting or moving tools such as bridge plugs, and (3) wellbore cleanouts. In the late 1990s, a hydrajetting process (Surjaatmadja 1998) called hydrajet-assisted fracturing (HJAF), using dynamic diversion, was introduced to the industry as a means of treating horizontal wells, in particular openhole horizontal completions (Surjaatmadja et al. 1998; Love et al. 1998; McDaniel et al. 2002). The benefits of this process for reducing NPT were readily apparent and horizontal completions involving 20 separate fracture treatments in a single well have been performed in just 2 days of daylight operation (East et al. 2004). The process uses hydrajet perforating and HJAF, which eliminates a separate trip into and out of the wellbore (Fig. 1). The numerous advantages (and some limitations) of using hydrajetted perforations instead of explosive/shape charge perforating has been recently reviewed extensively in a recent paper (McDaniel et al. 2008). Because the HJAF process relies on dynamic diversion, no mechanical plugs are required to furnish diversion between intervals being treated. Therefore, there is no drilling of plugs or plug-retrieval operations after the treatments have been performed, further reducing NPT in the completion process. The HJAF method allows for recovery from premature screenouts because tubulars are in position for rapid cleanout of excess proppant at each stage of the fracturing and perforating process. This is particularly beneficial when aggressive proppant schedules are required, such as in the case of frac-pack or tip-screenout treatment designs.
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