(Tech Connections Column, April 2007, American Oil and Gas Reporter)

For many completions it is all about how to “effectively” stimulate separate intervals in minimum cost and time. Different providers offer different solutions. A PTTC hydraulic fracturing workshop in San Antonio revealed field results of two technology solutions: Halliburton’s CobraMaxTM process, and BJ Services/Marathon/The Expro Group’s ExCapeTM process. To understand why these solutions are attractive in certain situations, one must build a mental picture of how they work. They are quite different in approach.

Bill Melton with Halliburton described its CobraMax process. Perforation and fracture-initiation fluids are pumped down coiled tubing. Once the perforations are cut and fractures opened, the regular proppant-laden frac fluid is pumped down the annulus. The pumping rate on the coiled tubing is reduced and the coiled tubing is then used to monitor bottom-hole pressure. Isolation between zones is accomplished by setting high proppant-concentration sand plugs at the tail end of each fracturing treatment, similar to a near well-bore screen-out. Once the desired bridging has taken place, the plug can be pressure tested by injection down the coiled tubing. The cutting tool is pulled up hole. Pumping through the coiled tubing then ceases and excess proppant is reverse-circulated out, and the perforating/ fracturing sequence for the next interval is repeated.

This process has been employed in more than 25 South Texas wells in the past 18 months. The largest treatment was eight stages, and treatments average four stages. Typically, two stages a day are accomplished. The majority of stages have been completely placed. Isolation with sand plugs has been achieved in 95 percent of the jobs on the first try.

There have been some lessons learned. One should maximize circulation rate and duration in wells with intermediate deviation and low annular velocities prior to beginning injection. Screen-outs delay the process, but are not destructive to timing. One must adapt to changing well conditions and customer requests. The best multiple zone candidates are wells with high screen-out risk. It’s also favorable if wells are in mature or well known areas where formation pressure and behavior are better understood.

A Halliburton brochure notes that, considering all costs with conventional perforating and fracturing, the process typically makes sense when there are four or more zones. That same brochure reports results on an 18-well field test in California’s Lost Hills area. Eight wells were completed conventionally and 10 were completed using either CobraJetTM (uses a mechanical packer for downhole isolation) or CobraMax services. CobraMax was 38 percent better than conventional plug and perf techniques. Although treatment costs were slightly higher, the cost per barrel of oil equivalent was significantly lower.

The ExCape completion process is another alternative. This process was developed and patented by Marathon and is provided through a technical alliance of Marathon, The Expro Group and BJ Services. The system is composed of external perforating guns, a control line and isolation valves, all of which are run into an open hole with the casing prior to the primary cement job. The system is placed in position by lining up the open-hole gamma ray log with radioactive markers located on each gun module. Once cemented in place, each gun may be detonated in succession using a control line from the surface. After detonation occurs, a sliding sleeve is actuated, allowing an integral isolation flapper valve to fall into place. Latch-down or flow-through isolation valves may be used.

James Rodgerson with BJ Services summarized field experience. ExCape has been used in 78 wells to install 798 modules. There were 27 modules in one application. Overall, the process has exhibited a 97 percent mechanical success rate while 98 percent of fractures have been pumped without screen-out. Twentythree of the 78 applications have been in horizontal completions, representing 230 modules. Of the 230 modules, 201 detonated and 17 are pending. There were 15 modules in one lateral. Compared with the overall sample, the mechanical success rate in horizontal wells dropped slightly to 94 percent.

Specific results were noted in a South Texas horizontal well and a Barnett Shale horizontal project. In the South Texas completion, eight stages were completed in nine hours. The time to first sales was only eight hours, and 50 percent of load was recovered in just five days. The initial potential test was fivefold better than the best offset and eight times better than the average offset.

In the Barnett Shale horizontal project, the process was used in four wells and involved 42 modules, ranging from six to 13 modules per lateral. There was a 98 percent mechanical success rate and no screen-outs occurred. In comparing AFE costs for a three-stage conventional versus a nine-stage ExCape completion, the latter resulted in a $138,000 potential cost savings. Favorable results led to plans to use the process in 12 additional wells.