In the past, the operational and cost concerns of being able to treat and evaluate multilateral wells have left operators with limited economical options for remediation and evaluation. This paper describes a combination of fiber optic-enabled measurement system and a selective multilateral reentry tool.The new system's bottomhole assembly design includes a multilateral reentry tool and real-time bottom hole feedback. The live feedback provides the operator with constant tool position in the wellbore which can serve as a key indicator of downhole tool function. With these specific measurements, downhole CT operations can be tracked and analyzed more quickly and clearly than ever before. Furthermore, this constant stream of critical data arms the onsite engineers and operators with information to make immediate decisions and thereby increase overall intervention efficiencies. This paper demonstrates how this system has been effectively used during stimulation services for openhole multi lateral wells in Canada.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMultilateral wells provide optimal recovery of reservoir pay and can become more prolific with stimulation or cleanout treatments. Downhole tools exist that index and allow the coiled tubing string to find and enter additional legs; however, they function using flow rate modulation. Any additional tool component beneath the multilateral tool that requires high pressure will suffer in performance because of the indexing multilateral tool. This technical paper addresses the performance of a new system that allows the indexing tool to find the lateral and then effectively treat the reservoir through the stimulation tool at the end. The entire cycle can be repeated for all laterals in the wellbore.The results of field tests using this multilateral jetting system were similar to what was seen in yard tests perform at test facilities in Rosharon TX. Field tests showed that operating parameters produced clear indications that the system was operating correctly. All legs were efficiently and effectively treated to improve well production. Additionally, this system reduced the number of trips into the well from three to one, resulting in a 50 % reduction of time at the client's well site.
Nitrogen coiled tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations, such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zones that are stimulated individually. The coal cleats are fractured by pumping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly. Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). Efforts to increase the energy have involved increasing CT size and increasing surface horsepower. Economics and logistics practically limit the pipe size to 2 7/8 in. for deeper wells and 3¼ in. for shallow wells using CT fracturing technique. This paper discusses the development of a technique which initially eliminates the CT friction limits on transferring energy to coalface. A large-volume pressure pulse is released downhole during the fracturing process to create an order of magnitude change in available energy at the fracture face, compared to current dynamic fracturing processes. The additional energy is dissipated by increasing the surface cleat area exposed. The development of the technique and field tests results will be discussed. Introduction The Horseshoe canyon dry coal formations have been commercially exploited since late 2000. From the beginning it was clear the Horseshoe Canyon CBM play was a unique CBM play, it is set apart by consisting of a dry under pressured coal. The coal therefore does not require dewatering before production. The coal consists of multiple thin seams, ranging from 10 - 30 seams per well. The coal seam thickness ranges lies between 0.1 and 2.5 meters. (Fig 1 - Horseshoe Canyon CBM log) The production rates from these CBM wells dictates that a efficient drilling and completion model be adopted in order to be economic. The current model that is utilized is the wells are drilled with coiled tubing drilling rigs, cased and cemented. Wireline perforating crews are then dispatched to perforate the zones of interest in a rig less operation. The individual coal seams are then stimulated via the injection of dry nitrogen at high rates through a coiled tubing reel that is equipped with a fracturing isolation tool. The dry coal has not responded well to any other form of stimulation. The lack of success of more traditional stimulation methods is deemed to be damage to the dry under pressured coal seams.
Subhydrostatic or low bottomhole pressure wells are wells with large hydrostatic overbalance, that is, the hydrostatic pressure of the fluid column inside coiled tubing, drillpipe, or similar well intervention means is greater than the wellbore pressure at the corresponding vertical depth. The number of subhydrostatic wells is growing as more and more fields mature. Consequently, there is an increasing number of interventions required for these wells to improve and/or optimize their production. U-tubing of the fluid column is a very common and uncontrolled phenomenon during interventions in subhydrostatic wells that can cause problems. In this paper the focus will be on coiled tubing interventions; however, the same basic principles apply to other areas as well.A backpressure valve (BPV) is a device that is used in subhydrostatic wells to hold the fluid column inside coiled tubing to prevent U-tubing. The BPV compatibility with other components in the toolstring is a critical operational requirement. Following recent tests conducted with the BPVs readily available in the market, it has been shown that these are not appropriate for a number of applications. One example is an application involving pressure pulse telemetry. For pressure pulse telemetry, conventional BPVs either cannot pass the pressure signals or greatly attenuate the magnitude of them.A backpressure valve that is fully compatible with pressure pulse telemetry has been developed and will be presented in this paper. The root cause of why the conventional BPVs were not able to transmit pressure pulse will be discussed using the results from fundamental physics, computational fluid dynamics analysis, and lab and filed experiments. Finally, a typical set of results from a field trial using the new valve will be presented.
The unconventional shallow gas market is the fastest growing oil and gas sector in Western Canada. Although these gas reserves are enormous, the economic output of a single well is marginal. The low production rate of each well has forced operators to reduce costs wherever possible. The largest expense in the completion of a well is stimulation. The advent of the coiled tubing fracturing method has reduced these costs substantially, as all zones can be individually isolated and stimulated in one operation. Operators are taking further action by drilling multiple slanted wells from a single surface location. This configuration requires only one lease, one access road and reduces production costs with a single pipeline collection point. Workover equipment with the ability to rig onto these wellheads safely is in short supply. Many shallow gas wells utilize threaded wellheads that are not designed to support sideloads. Coiled tubing equipment is relatively massive, and previous attempts to 'block up' the wellhead and blowout preventers (BOPs) have resulted in near-tragic consequences. To overcome these obstacles, a patented support system capable of safe and efficient rig-up of BOPs on slanted wellheads was designed and built. The support system can be rigged onto wellhead angles ranging from 30–95 degrees. The system can manipulate the BOPs in virtually all planes to allow for flexibility when positioning onto a wellhead. The weight of the BOPs and CT equipment are then buttressed by the support system, and not the wellhead. The development of this system has enabled safe coiled tubing fracturing within the economic and technical contraints of shallow gas and coalbed methane type fields. Introduction The coiled tubing fracturing technique has dramatically reduced the cost of completing low-production, multi-zone wells, such as those found in the shallow gas market of western Canada and the western United States. After a wellbore is drilled and cased, all zones of interest are perforated in one trip with a wireline unit. To stimulate the well, a coiled tubing fracturing tool is attached to the end of large diameter coiled tubing (Figure 1). The tool has a fracturing port located between two neoprene or urethane cups, which act as packoffs to isolate the zone of interest. The straddle between the cups can be adjusted by adding pup joints to accommodate zones of virtually any size. Over 25 zones can then be individually isolated and stimulated in one trip to the well. The shallow gas market in Alberta requires drilling a high number of wells to fully exploit a play. A typical square mile (2.6 km2) section of land will usually contain 6–8 wells. For every lease, operators must pay initial access rights fees and annual rent to the landowner. A large portion of the well cost in the shallow gas market over the economic life of a well is the result of land access fees. The enormous volume of wells, coupled with the increasing cost for land access rights, has prompted many operators to consider slant well pad drilling (Figure 2). The slant well pad configuration requires only one lease, one access road and reduces production costs with a single pipeline collection point. The operating company is only required to pay the landowner access fees and rent for one lease only. A slant well pad will also reduce construction and production costs, as all wells are concentrated in one area. Early attempts at coiled tubing fracturing on slant wells were conducted using two cranes to rig the BOPs onto the wellhead. Once the BOPs were attached, various items were used to attempt to 'block up' the wellhead, including coiled tubing injector legs and wooden planks (Figure 3). Once the wellhead was 'supported', one crane was removed from the BOPs to assist a third crane in lifting and tilting the coiled tubing injector. Incidents have occurred during coiled tubing fracturing operations due to excessive sideloading of the wellhead. One incident occurred while removing the BOPs from the slanted wellhead after a fracturing treatment. A pup joint threaded onto the casing failed at the threaded connection below ground. The root cause of the incident was determined to be inconsistent support of the weight of the BOPs while rigging on and off the well with two cranes. Similar incidents were repeated across the industry while using cranes to support the BOPs on slanted wellheads. Operators were forced to re-evaluate the feasibility of drilling slant wells due to the limited service equipment available and the inherent difficulty of completing these wells.
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