Several major developmental programs in the Rocky Mountain region of the United States are in fields where zones of several hundred to several thousand feet of stacked, tight (<0.05 md) lenticular gas sands exist. In order to be productive, these wells require multiple fracture treatments over the pay interval. Since field development has been ongoing, the drilling programs are extending into more marginal production areas. Infill programs are downsizing spacing, and also, successful refracturing programs are being conducted in some fields. Before 1998, traditional methods were being used to isolate fracture treatments. These methods usually required killing the well between fracture treatments or during cleanout operations. Unfortunately, field studies have determined that the traditional isolation methods have negatively impacted well productivity. In view of the costs involved and the lower productivity experienced with the new drilling programs, it became apparent that either well costs had to be reduced or well productivity had to be improved! This paper will discuss the application of flow-thru composite frac plugs (FTCFP) and how they were capable of addressing the current needs to reduce operational costs and improve productivity. These plugs can be used as an alternative to traditional isolation methods, or induced stress diversion. Through June 2002, there have been over 3,200 FTCFPs run in the Rocky Mountain region. The benefits gained from FTCFP usage are derived from the following:Well drill-out costs are reducedPositive isolation is allowedAll zones can be produced during completion. Their use has now become a "best practice" in stacked-pay completions. Introduction Six states make up the Rocky Mountain region in the Western United States (Fig. 1). Hundreds of different formations are productive in this region with the vast majority of these formations being classified as tight gas sands with permeabilities of less than 0.05 md. Some formations may consist of one significant sand or a couple of sands and are economic by themselves, such as the Almond in the Wamsutter area of south west Wyoming. However, as shown in Fig. 2, formations like the Mesaverde, found throughout Colorado, Utah and Wyoming, may consist of 20 to 50 individual sands spread over 1,000 to 5,000 ft of gross interval. This later scenario is the more common in the wells currently being drilled. To economically produce these formations, the majority of these tight gas sands require hydraulic fracturing. For the formations consisting of only one or two sands, the process is straight forward. The sands are perforated, fractured, and then placed on production. For formations consisting of multiple sands and those that cover a long interval, the fracturing process is more complicated, since these formations require multiple fracturing treatments. A significant portion of the current activity in the Rocky Mountain region is in fields that were uneconomic prior to the 1990's. Throughout the 1990's, a variety of different techniques were tried to effectively stimulate multiple-sand formations. The most common technique was to break up a well into several fracture treatments with each treatment consisting of several sands. For each treatment, the sands were perforated using limited-entry perforating1 to help ensure that each sand would be treated. The interval sizes varied throughout this time period from 200- to over 500-ft per fracture treatment. In the Piceance basin, however, it was found that longer gross intervals for each treatment significantly reduced completion coverage.2 This study also showed that as the number of sands per treatment increased, the completion coverage decreased.

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Across the globe, liner casing strings are sometimes required. The installation process leads to a variety of challenges from both cementing and tools aspects. Among the challenges are proper isolation of both formation and liner lap, placement of the liner in the desired position, and associated operational time required to return to drilling operations. The use of the expandable liner hanger provides a way to better address each of these issues. Well conditions on the southeast Pinedale Anticline require drilling liners to be set at specific casing points to allow all of the productive strata to be penetrated. Because the strata behind the liner string is also gas productive and completed with multiple hydraulic-fracture stimulation treatments, proper isolation behind the liner is critical right up to the lap of the liner across the intermediate casing shoe. The mechanics of the expandable hanger system eliminate the potential for a premature set. The normal operating procedures require testing conventional liner tops and "dressing" cement left on top of the liner. These operations can require substantial investments of time and money. The new technology simplifies these processes and reduces the time required to return to drilling operations. The cases investigated in this paper have similar wellbore conditions, but were cemented using different methodologies. The first was isolated using a foamed-cementing process, while the second used conventional slurries. Both cases exhibited good isolation, good bond performance across formation and lap, and a faster, more simplified operation compared to conventional mechanical liner-hanger applications. Introduction The incidences of liner job failure have been well documented. In a recent survey conducted with three major operators who routinely set liners for both drilling and production purposes, the following problems were identified as recurring issues:Lap squeeze-leaky lapShoe squeezeStuck liner while running inWiper plug did not release or bump.Packer, hanger, centralization, premature set, or failure to setLost circulationCementing issues The most prevalent occurrences were the leaky lap, resulting in squeeze remediation attempts, and the packer/ hanger/centralization issues, which had a variety of ramifications. Each of these problem categories requires time and money to resolve. Expandable liner-hanger technology can alleviate many of these problems completely and help minimize many of the other issues (Fig. 1).1 This paper reviews two installation processes in southwest Wyoming. These two installations constituted the first such processes in the Rocky Mountain region. The wells presented a substantial number of challenges because this particular area exhibits many instances of lost circulation. Mud rheologies are adversely affected by CO2 present naturally in the producing strata, causing equivalent circulating density (ECD) issues. Many of the wellbores are deviated, fracture gradients and pore pressures are typically in a narrow window, and differential sticking can occur. These jobs use 7-in., 32-lb/ft and 7-in., 26-lb/ft drilling liners to cover potential pay and provide protection for further drilling operations. The use of this tool system minimized potential problems and reduced non-drilling time. Expandable Liner Hanger - The Tool The expandable liner-hanger (ELH) system incorporates the liner hanger body with an integral packer, tieback polished bore receptacle, setting sleeve assembly, and a crossover sub to connect the assembly to the packer. The expandable liner hanger/packer body contains no setting mechanism or external components such as slips, hydraulic cylinders, or pistons. The hydraulic setting mechanism is contained in the setting tool assembly and is completely retrieved, thus eliminating a potential leak path in the flow stream.

The industry has relied on three primary measurements during fracturing operations: surface pressure, surface flow rate, and surface proppant concentration. The downhole environment is challenging for instrumentation.What can the surface pressure indicate? What does the surface pressure not indicate? Often, the pressure measurement is miles away from the event. This long distance often obscures the transient pressure signature, the surface pressure measurement as a function of time. These obscurations are caused by the speed of sound in the carrier fluid, the compressibility of the pipe in the completion, and other factors.A transient finite difference model of a horizontal multiple interval completion for an induced fracture shale reservoir was developed to investigate the pressure transient signatures of different events during the fracturing operation. Model results will be shown for different types of events, such as sleeve shifting, fracture initiation, opening a sleeve into a zone with an existing fracture, fracturing a zone with high leakoff, etc. Certain types of events have distinct pressure signatures. Other events can have similar pressure signatures. Some events can have no surface pressure signature at all. The model results will be compared with field data.While the focus of the results is on horizontal multiple interval shale completions, the results can also provide insight into other types of fracturing operations and will aid in the interpretation of pressure signatures.