The evolution of the offshore oil and gas industry has resulted in operators drilling multiple wells from single platforms targeting more challenging reserves in deeper waters. This progression has introduced many new technical challenges for the downhole tools used in conventional processes. These challenges must be addressed to maximize operational efficiency in these extreme service environments. This paper specifically discusses some of the shortcomings that have been identified in downhole tools currently used in offshore operations and presents a few recently released technologies specifically designed to address some of the challenges posed by the new offshore environment. Case studies including the impact of the new technologies on operational efficiency are presented.

Multiple-stage fracturing is a very common practice, especially in reservoirs with microDarcy permeability. The process of perforating, fracturing, and setting plugs has been performed for many years and has both advantages and disadvantages. Coiled tubing (CT) completion methods have increased completion efficiencies but can have limitations as well. Though multistage tools placed in the casing string have become a standard completion practice in horizontal completions, little has been done in vertical, cemented wellbores. As multiple wells drilled on single pads become more common, increased economic completion efficiencies are necessary. To address the increasing need for completion efficiency, an alternate method of multiple completions was tested in several vertical wellbores. The casing strings were conventionally cemented in place and ball-activated sliding sleeves were placed across target completion intervals. Failures in similar techniques can have catastrophic effects if the initial tool does not open. To address this issue, a new hydraulic-actuated sleeve was developed. It was successfully tested in multiple wellbores and performed as designed. Multiple fractures were completed in a continuous operation with excellent production results. This completion process can provide an efficient method for multistage fracturing in conventional and unconventional reservoirs in either vertical or horizontal wellbores. It can be used on single-well completions or on multiwellpads. This process provides an efficient, low-cost alternative to conventional multistage fracturing for vertical and horizontal wells. Introduction For decades, the standard method of multistage fracturing has been to perforate, frac, and set an isolation plug. Advances in CT fracturing have increased the efficiency for multiple completions that allow for deeper completions (Peak et al. 2007); however, eliminating perforating, wireline intervention, and problematic means of isolation from the completion process is still desired. The installation of sliding sleeves in casing strings, specifically ball-activated versions that enable the interventionless completion methods, is not new and has been common practice in openhole, horizontal applications (Vargus et al. 2008). However, there has been concern regarding if this type of system could be deployed in vertical, cemented wellbores. A new set of problems was identified with this completion method when cement was used as the method of zonal isolation. One specific challenge identified was how the interventionless process would be initiated. In past cemented applications, the cement was overdisplaced so that a wet shoe would be present, providing a flow path that enabled the initiation of the interventionless process. This was not an acceptable solution in many cases because of the downfalls of having a wet shoe (i.e., possible leak paths, lack of isolation, and no pressure integrity of the casing, etc). To address these issues, the development of a specialized hydraulic sliding sleeve, minor modifications to the remaining ball-activated sliding sleeves, and adjustments to the processes and procedures were required to enable an interventionless completion method for cemented applications. Development of the specialized hydraulic sliding sleeve, changes to the existing ball-activated sliding sleeves, and all process and procedure changes were completed within six months. The system was installed and field tested with excellent results. Challenges included development of a new hydraulic sliding-sleeve design that allowed for proper tool operation with cement contamination and setting up the remaining equipment, process, and procedures to help ensure the sliding sleeve was not unintentionally opened. Four field trails were conducted to determine the operational accuracy of the sliding sleeves as well as the production results after the fracture treatments.

This paper will discuss case studies and details of a pinpoint stimulation/completion process that uses stimulation sleeve technologies in conjunction with swelling packers as part of an openhole, horizontal, well lateral liner that is anchored by an expandable liner hanger. This system will allow an operator to accurately place several individual stimulation treatments without additional intervention in the wellbore. This is accomplished by installing the closed stimulation sleeves and swellable packers as part of the completion string, (horizontal openhole liner) and positioning the string in the wellbore so that the stimulation sleeves are located within the desired production pay zones. The completion string is then anchored in position with an expandable liner hanger. The swellable packers are allowed to expand for a few days and isolate the zones between each of the sliding sleeves. Stimulation/frac equipment is rigged up, and a series of progressively larger balls are dropped throughout the multistage pumping operation. The balls land on the tapered baffles in the sleeves, each of them opening in sequence and sealing off the previously treated zones below. Once opened, a stimulation sleeve allows pumping a treatment into the zone where it is positioned. After being opened, the stimulation sleeves maintain the capability to be closed and reopened, with minor intervention, with a shifting tool allowing for restimulation or other workover at a later date. This new service is a field-proven process with 120 wells completed and more than 850 stages/zones treated. This method reduces the time and cost needed to complete multiple intervals in a well, and bring production on line faster by comparison to conventional multizone horizontal fracturing/stimulation techniques such as multiple perforating and setting plugs. Introduction Multizone wells can pose completion challenges for operators. One challenge—isolating and fracture-stimulating multiple pay zones during the well completion process—is especially demanding when working with cemented production casing strings, openhole completions, or openhole packers and perforated liners. In a conventional completion/stimulation process, the cemented casing string is perforated in the toe and stimulation begins. Sequential steps in this completion process require the operator to set plugs, perforate, and fracture each zone individually. Depending on the well design and fracture-treatment design requirements, several hours per zone may be required for the plug and TCP/wireline trips that prepare each stimulation stage, leaving the fracturing crew idle. Continued innovation has made this process somewhat more efficient in horizontal applications by use of pumpdown composite plugs, but, at its best, operators can still only perform three or possibly four fracture stages per day on a single well. With the increased activity of today's industry, scheduling equipment and manpower for future fracture dates is becoming more difficult and could result in delays in production when multiple fracture treatments are desired. When using an openhole completion technique, the operator drills into the formation and opens a path to the wellbore for production. This works well in formations that have structural stability and contain natural fractures. However, problems arise when stimulation treatments are desired because 'bullhead' fracturing treatments usually result in fracturing the weakest point in the formation without treating the entire pay zone. This complication prevents operators from achieving the maximum potential payout on their investment, and can result in additional expenses for interventions associated with re-stimulating to increase production to make the well commercially viable.

Over the last two years the increase in openhole interventionless horizontal completions in the shale markets has lead to higher production rates at lower completion costs for operators. In areas where wells are being air-drilled, specific techniques of using hydraulic set packers and sliding sleeves has proven to be a viable, low-cost, interventionless solution to complete when the wells are likely to be a gauge hole. However, in areas where the horizontal wells use foam instead of air because of the sensitivity of the shale, typically the wellbore is non-gauged and may lead to operational failures when trying to isolate the wellbore with hydraulic set packers because of the limitation of the expansion of the element package. The advances in the use of swellable elastomer packers provide an ideal solution for isolating these non-gauged holes for the completion process. But, as mentioned, there is sensitivity to the shale in these wellbores, and applying the typical hydrocarbon fluid to the formation to swell the swellable elastomer packers may cause a detrimental effect to the formation. To overcome the issue of isolation in non-gauged holes without damaging the shale formation, an interventionless solution was incorporated using sliding sleeves, swellable elastomer packers, and development of a new shale optimized fluid system to swell the packers. The shale-optimized fluid is an effective low-leakoff fluid that causes minimum physio-chemical damage to the shale while increasing the optimization of the swell time of the packers. This paper will discuss the development of this new completion process for use with foam-drilled openholes that are non-gauged and case history information of applications that have been run in the Lower Huron shale formation. Introduction In recent years, the North American land markets have seen a shift in focus towards developing gas shale plays such as the Lower Huron, Marcellus, and the Haynesville formations. This shift can largely be attributed to the development of new technologies that make the completion costs more economical. One of the technologies that has made a big impact on lowering completion costs is the combination of horizontal drilling and the use of sliding sleeve technology to provide an interventionless completion. The deployment of this type of system enables the operator to separately frac several different intervals within the horizontal section without shutting the pumps down. Operators can simply drop a ball from surface to isolate the intervals that have been treated and open the next zone for treatment. This cuts the completion time down by removing the downtime associated with running perforation guns and setting plugs. This type of completion also maximizes production possibilities by optimizing and tailoring treatments for each interval throughout the full horizontal section of the wellbore. To compartmentalize the horizontal section and optimize the fracture treatments, zonal isolation is required in the annulus in between each sliding sleeve. There are several ways to establish zonal isolation including traditional cement, openhole hydraulic set packers, or inflatable packers, but each method adds a certain complexity whether by adding operations to complete the installation or introducing more mechanical components, which increases the risks associated with installation. The introduction of swellable elastomer packers (SEPs) as the method of zonal isolation greatly simplifies the installation process and decreases the associated risks. SEPs are simply positioned onto the production casing and spaced out as per the wellbore plan. Once in position, the swelling activator, traditionally liquid hydrocarbons, natural gas, or water is introduced into the system allowing the SEPs to begin to swell. Once activated, the swellable elastomer packers will continue to swell and conform to the wellbore ID in which they are installed.

With a combination of (1) stimulation sleeves that are installed as part of production casing strings and (2) packers whose sealing elements expand by swelling when contacted by certain chemicals, operators may isolate and fracture-stimulate multiple payzones as part of the well-completion process. The sleeve and swelling packer system (SSPS) enables accurately located, pinpoint stimulation of several payzones through the casing wall. The stimulation sleeves, rated to 10,000 psi differential pressure, can be opened or closed in a single coiled-tubing (CT) or jointed-pipe trip. Opening the sleeve permits zonal stimulation through the selected sleeve and diverts the flow through ports in the sleeve. After stimulation, cleanup is assisted by flowing all lower zones simultaneously. Sleeves can be shifted (opened and closed) (1) mechanically, (2) with a hydraulic shifting tool, or (3) by ball activation. There is no limit to the number of stimulation and production sleeves that can be run in a single casing string. Once the well is completed, the sleeve will function as a standard production device, allowing full wellbore access. Stimulation sleeves have been subject to extensive laboratory and back-yard testing. Augmenting the function of the stimulation sleeve is the swelling packer. This packer is also installed as part of the completion string; rubber elements bonded to the tubular portion swell on contact with oil-base drilling muds, formation crudes, and other formation liquid hydrocarbons. Packer elements will not swell in fresh water. Packer-swelling action creates a seal in open hole; swell time is adaptable to suit the environment. A summary of the swelling packer's features follows: Introduction and Background Cemented Production Casing String. With this process, the operator sets a plug, perforates, and fractures each zone individually. Depending on the well design and fracture-treatment design requirements, this process could take several hours per zone and require the frac crew to be idle while the plug and TCP/wireline trips are made to get ready for another frac. Continued innovation such as pump-down plugs etc. have made this process more efficient, but at its best, operators are still only able to perform two or possibly three frac jobs per day on a single well. This process works well if over-flushing a previous fracture treatment is not an issue. It is a well-established process, but with the increased activity in the industry, frac dates are becoming harder to schedule, which leads to delays in bringing wells into production when multiple fracs are desired. Openhole Completion. In completing wells openhole, the operator drills into the formation and opens a path to the wellbore for production. This method works well in formations that have structural stability and contain natural fractures. The problem with the openhole method comes when stimulation treatments are desired. Openhole fracture treatments usually result in fracturing the weakest point in the formation and not treating the entire pay zone. By not stimulating the entire pay zone, the operators are not achieving the maximum potential out of their investment. This can result in additional expenses for interventions to re-stimulate and bring the production up to an economical point.