New downhole straddle tools require no pipe manipulation.

In many wells it is advantageous, economically and operationally, to perform stimulation techniques using coiled tubing. Often this process will require that the zone of interest be isolated for effective treatment. Several basic means of isolation are available, depending on whether the application requires intervention through tubing or into a monobore, or "tubingless," completion. These basic tools require some form of pipe manipulation to set and retrieve, which in straight holes presents little difficulty, but in deviated wells becomes problematic.
Addressing this problem in highly deviated wells, a new generation of downhole straddle tools requires no pipe manipulation to set and retrieve. These tools, called fluid velocity set devices, use fluid pressure buildup created when pumping through a nozzle to activate a tool and relaxation of that pressure to deactivate a tool. Two types of tools have been developed:
• inflatable straddle packers for through-tubing applications, which can be inflated to seal in an inside diameter (ID) up to 2½ times larger than the running outside diameter (OD); and
• mechanical straddle packers for monobore applications, which have a running OD small enough to pass through standard tubing-mounted accessories, such as landing nipples and sliding sleeves, and set in the tubing ID.
The original tools developed for zonal isolation were designed to meet the requirements of two types of completion: the monobore completion, in which the productive zones are in well sections that have the same ID as the production tubing; and the standard completion, in which the well is completed in casing and production is "through-tubing" in nature. These requirements resulted in the development of several alternatives to suit the two requirements that have been used in isolating and treating zones in live wells on coiled tubing. However, the limits of each system, particularly in extended-reach, high-angle and horizontal wells, dictated that additional tool development was needed. The first step was to define the requirements for a new system:
• passive systems that require no coiled tubing manipulation to set and unset the straddle tools;
• for monobore applications, a tubing ID seal system that would not wear out while running to depth, would pass through ID restrictions such as landing nipples and sliding sleeves, and still seal effectively in the nominal ID of the tubing;
• systems that could be set multiple times on the same trip in the hole; and
• for inflatable systems, a system that would function in monobore and through-tubing applications.
Development stage
Most of the options considered would only allow a single set of the packer. Another major consideration was economics. It became apparent that packers set by differential pressure offered the best avenue for meeting the listed requirements and keeping the cost at a reasonable level. Following extensive testing, it was determined that modifications to existing packers could meet the requirements for straddle tool applications.
Next, customer needs and design limits had to be incorporated into design requirements. For monobore applications, some of those design requirements were that the tool be able to:
• operate effectively from 70°F to 325°F (21°C to 163°C);
• work at differential pressures between 1,000 psi and 3,000 psi;
• pass through nominal ID restriction such as landing nipples and sliding sleeves and still seal effectively in the tubing's nominal ID;
• be used in a treating acid environment; and
• allow adjustments in the size and number of orifices in the injection sub to accommodate varying rates and treating pressures.
Inflatable packers that work in monobore and through-tubing applications were determined to have lower maximum temperature needs - to 250°F (121°C) - but also need to pass through the no-go nipple at the bottom of the tubing and still inflate and seal effectively in the casing below the tubing.
Tool configuration
The monobore packer design was patterned after the nonslip packer used in the initial testing. The two primary areas of modification were an increase in the differential area for the setting pressure to act upon and an improvement in transmitting the setting force to the packer.
The orifice sub was set up to accept different size nozzles that could be changed easily as required. The same orifice sub would service the monobore mechanical packers and the inflatable packers.
The inflatable packer system used off-the-shelf equipment modified for the new application. The check valve inside the inflatable retrievable production packer was removed, and the deflate mechanism was disabled to produce the inflatable velocity set (jet) packer. This packer, when used with a back-pressure valve, can be inflated without check valves or pipe manipulation.
Field testing
After extensive laboratory testing, the first run of the new packers was performed in a well in Thailand using a 2.215-in. OD velocity set monobore system in 27/8-in. tubing. The monobore packers were run on coiled tubing to about 12,000 ft (3,660 m) set in blank pipe at 4,000 psi differential as a preliminary test before any stimulation was performed, and the test was successful. Pressure was released at the surface, but the packers did not unseat because the double flapper valve closed and maintained the setting pressure on the packers. A set-down unloader was run in the downhole assembly for this situation, but all attempts to open it failed. Finally, due to the high bottomhole temperature, expansion of the trapped fluid resulted in the pressure exceeding the shear-out plug setting of 5,600 psi, and the straddle tools unset.
This problem highlighted the need to develop a new style of set-down unloader that would be pressure- and volume-balanced. With such a design, stroking down on the unloader to open it in a closed-chamber system would not be a problem. The new unloader was developed and lab-tested before the next coiled tubing job with the monobore system.
The second run was done in Wyoming on threaded and coupled tubing in a horizontal well using a 3½-in. OD velocity set monobore system in 4½-in. tubing. The straddle tool system was set 10 times while in the hole, and the tools worked as designed throughout the operation.
The third run was done in Wyoming on coiled tubing in a horizontal well, using a 3½-in. OD velocity set monobore system in 4½-in. tubing with the new pressure- and volume-balanced unloader. The velocity set straddle tools were set in a horizontal section in blank pipe. The new set-down unloader was functioned to release the tools, and it performed as designed.
The fourth run was done in Trinidad for a major operator using a 21/8-in. OD velocity set monobore system in 27/8-in. tubing. Because the pressure- and volume-balanced unloader was not ready for this size of tool, a weep hole was drilled in the body of the double flapper valve below the bottom flapper. The downhole assembly also incorporated a hydrostatic valve to keep the acid from running out of the bottom of the coiled tubing. The straddle tool, which was spaced with the two packing elements 30 ft (9 m) apart, was set and released 22 times on a single run in the hole and functioned as designed throughout the operation.
On the fifth run, the inflatable velocity set (jet) straddle packer was run for a major operator in Trinidad. The 21/8-in. OD packer assembly with the injection sub using two 1/8-in. diameter nozzles was run to a depth of more than 4,000 ft (1,220 m) in a combination 4½-in. and 5½-in. tubing string. Fluids were pumped at 0.8 bbl/min to inflate the packers and begin treatment. The maximum differential pressure applied across the inflatable elements during treatment was less than 2,000 psi. The treatment included a HCl preflush, HCl/HF treatment and an acid afterflush for a total volume of about 200 bbl/zone. The packers were released, moved uphole and reset five times. Upon retrieval, the tools were laid down and inspected. The top element was found to be ruptured in the lower quadrant, and the operators believe this occurred during the last pressure cycle since failure before the last set would have prevented inflation. Oversize gauge rings capable of passing the minimum restriction above and below the elements were identified as a method to reduce the wear on the elements when moving between zones.
Acknowledgements
The authors thank Weatherford International Inc. for the opportunity to publish this article, first published as SPE 683354, "Formation Treating with Coiled-Tubing-Conveyed Straddle Tools."

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