Industry experience has shown that frac pack completions can provide effective production stimulation and reliable sand control for unconsolidated sand reservoirs. One of the more rewarding areas of opportunity is in the completion of longer and more complex intervals that can be stimulated with a single frac pack treatment. Here, the cost saving of a single completion versus the cost of two or the recovery of reserves from pay zone sand added to the completion interval can add significantly to the cash value of the well. This paper discusses an innovative screen that has a concentric shroud that can treat two separate and distinct sand lobes during a single frac-pack operation. Two cases histories illustrate the use of an innovative assembly that uses the new screen to enhance the stimulation and sand control results of frac pack completions on unconsolidated sand reservoirs with complex lithology and permeability contrast. The capabilities of this technology have brought a long-sought-after solution to fruition. Introduction Although conventional screens have been very successful in controlling sand production in most situations,1,2 not every well configuration lends itself to traditional screens. For example, in completions where there is a risk of screening-out in the upper part of the completion before the lower part of the completion, a screen-out with conventional screens can prevent the gravel slurry from reaching the lower part of the completion. Questionable applications include:frac packs where potential annular restriction or bridging may compromise sand control or uniform stimulation of the pay intervalfrac packs in intervals where there are distinct layers with different lithologyfrac packs in intervals where there are significant variations in permeability and porosityfrac packs in long intervals where there is concern that a complete annular pack would be achievedfrac packs in highly deviated intervals where multiple fracture initiation may jeopardize complete annular packing. Because of the more complex completions now attempted, the incidence of failures experienced in scenarios such as those listed above have increased. To provide a solution, a new type of sand-control screen assembly that consists of an outer perforated shroud placed over a metal-mesh sand screen has recently been developed. With this assembly, the annular space between the outer shroud and screen forms a secondary slurry flow path to enable bypassing a blockage in the outer annulus between the shroud and the casing. The perforations in the shroud are designed to balance slurry flow control during the treatment and low inflow restriction during production.

Operators face numerous challenges when conducting deepwater operations, including hostile downhole environments, ever-increasing well and water depths, complex logistics and planning and excessive costs. As it pertains to exploratory well testing, most systems and equipment that are capable and reliably operate within this environment are valuable, but costly. In this arena, time is a commodity that is quantified in dollars, not minutes. Many exploration wells that deserve thorough analysis and measure—typically provided by a well-designed testing program and subsequent nodal and reservoir analysis—have settled for an incomplete data picture provided by logs, seismic data, and formation testers. For many Gulf of Mexico operators, the economic and logistical challenges have outweighed the benefit of data gleaned through well testing. In addition, the widening gap between these difficult environments and the capabilities of the equipment designed to control them is challenging our industry's ability to harness the yields within these frontiers. We propose a new way of testing exploratory wells using the world's first openhole deepwater exploratory testing system that will isolate each target interval, selectively flow and shut-in zones with radio-frequency identification (RFID) technology, acquire shut-in pressure-buildup data by acoustic telemetry to enable subsequent zones to flow while acquiring shut-in formation buildup data on the previous zones—all with robust completion equipment. Vulnerable, O-ring-laden, pressure-operated, limited-capability drillstem testing equipment is not meeting the current challenges of deepwater exploration. Exploratory well tests that were not previously viable are now well within reach. The system is run to depth as a completion-testing liner system, requiring no string manipulation once set and is replete with contingency capability. The proposed system and method will deliver the data needed to answer the reservoir questions asked by our operators within the industry that are exploring at the limits of technology. This document outlines the challenges, system components and operating sequence, and considers the cost, time, data and risk-reduction benefits of the new system versus yesterday's methods. Introduction Exploratory well testing is desirable in new discovery fields because it provides data crucial to characterizing the reservoir. Peripheral advantages of well testing in an exploratory situation include validation and calibration of other data against well testing data, accurate population of simulators, improved certainty of the producing zones' content and quantity, and allows a more focused direction regarding future appraisal and development activities. Many operators choose to forgo well testing opportunities because of resources and time required, and inherent risks involved in flow tests. The system is designed to address the challenges that make the execution of a well test prohibitive, and allow the operator to realize the value of a comprehensive depiction of the new reservoir. Specifically, the system was designed to improve zonal isolation and flow barriers, minimize trips in hole and pipe manipulation, and eliminate well intervention. Enhancement of well control was considered paramount.

A new system of tools has been developed to complete multiple producing intervals in unconsolidated sandstones during one trip into the well. The system was developed to make efficient use of a previously developed pumping process, which simultaneously incorporates fracturing with proppant, and chemical consolidation of that proppant. The system provides sand control by installing resin coated proppant during the pumping process on each of the production intervals but leaves the casing across those intervals unobstructed except for isolation packers, which can be used for production management during the life of the well. This new system enables low cost but highly productive completions, specifically enabling small and/or marginally economic reservoirs to be completed along with more valuable reservoirs. Multiple marginal reservoirs may be combined to make an entire project reach minimum required profitability. The system has been designed to allow low incremental cost for accessing additional reservoirs. The system was used for the first time in the Milne Point field on the North Slope of Alaska in a field operated by BP Exploration (Alaska). This paper will describe in detail the design and operation of this tool system, including component drawings, operational sequence drawings, and a field case history in which the equipment was used. Introduction Decreasing completion and lifting costs while increasing production rates are especially important requirements at the Milne Point facility on the North Slope of Alaska, (Fig. 1) where electric submersible pumps are used as a means of artificial lift to produce a shallow, viscous, low temperature reservoir, the Schrader Bluff. The Milne Point field is mature, and keeping operational costs low is considered critical to maintaining profitability and extending the life of the field. Various methods for completing multiple intervals of unconsolidated sandstones have been available, but these methods have been difficult to use. They have either proven to be very time-consuming, making them prohibitively expensive, or very complex. While the complex systems have been used with some success for lowering the cost of completing the wells, reliability problems, which often required extensive unplanned operational time, as well the initial high cost of these systems can significantly impact overall profitability. Other tool systems similar to the complex systems tried at Milne Point have been used successfully elsewhere, but they were considered unsuitable for the fracturing appliCat ions needed here.1,2 It is typical for the wells in Milne Point to encounter three economically producing sands. Treating each of those sands individually with gravel packs or frac packs consumed from 7 to 21 days of rig time, depending on unforeseen delays such as weather and hole conditions, in an expensive operational environment. With traditional techniques, time was needed to perforate and fracture each zone, wash or drill out the proppant left in the casing, and run the completion packers and other production equipment into the well. (The fracture treatments were designed to be tip screen-outs, thus leaving packed proppant inside the casing.) Multiple packers are desirable for managing production from the various zones for optimum recovery, and the otherwise unobstructed casing is desirable for maximum production. Where high oil rates typically coincide with sand production, and sand production often equates to pump failures and high lifting costs, innovation and continual improvement on completion design and operational techniques is an ongoing operational requirement. For these well scenarios, the operators and service/engineering personnel felt that a new tool system should be targeted to speed the completion process.

No abstract

No abstract