The FracGuard pumpdown composite plug, designed especially for horizontal and extended-reach applications, can be run on standard wireline in situations where e-coil or conventional coiled tubing previously would have been required. Pump pressure pushes the plug on wireline through horizontal sections, carrying the plug and the setting tools to the target or setting depth. (Image courtesy of Weatherford)

In the 1990s, drilling and completing wells in the unconventional East Texas reservoir was an exacting process. To succeed, operators needed a better understanding of the rock and its production potential. At the time, coring land wells was relatively rare, but the need for additional data drove the move toward coring. Additional analysis was needed particularly in unconventional plays like the Barnett Shale in Texas ? a low-permeability formation (less than 1 mD) and one of the largest unconventional gas plays in the country ? and theWamsutter field, a 1,700-sq-mile (4,400-sq-km) tight-gas sands province in Wyoming.

The industry was using seismic and logging, tracers, microseismic mapping, and modeling to understand these reservoirs. One core completed by OMNI Laboratories, Weatherford’s Integrated Laboratory Services group, was for the owner of an East Texas tight sand reservoir. The core was taken to more fully understand apparent discrepancies between log calculated porosities and completion results; the wells were not consistently performing to expectations.

The answer lay in measurements of free and bound water in the formation. In the tight East Texas sands, a 3% porosity variance between logs and core was plenty of difference to raise questions, said Henderson Watkins, OMNI’s director of technical market development. “While logs don’t discern a difference, core analysis measures this directly and routinely.” And that particular information made a big difference ? a fact many operators were starting to realize.

The East Texas well was cored to determine the depositional environment and to feed simulators that modeled reserves in place. Specifically, direct porosity measurements were being made at reservoir conditions, and log calculated porosities were being re-calculated. In other areas, operators were using core analysis to understand potential formation damage, improve fluids selection and treatment procedures, better locate wells, and build more accurate frac models.

Early efforts prove valuable

The capabilities needed to offset the extreme costs of deepwater efforts were helping overcome the marginal economics of tight sands and shales. “Everyone was coming to the realization that routine was no longer routine,” explained Camille Lupton, director of business management and development for OMNI.

The emphasis on the non-routine defined a process by which unconventional resources were becoming an everyday affair. Some of the early efforts were fundamental and reflect the dawn of a new service perspective.

Securing the pristine core

Much of today’s efforts go toward calibrating indirect measurements, such as logging and seismic, with direct measurements from core samples. “It’s a fine-tuning process that is changing the face of traditional coring services,” Watkins said, and it takes many forms.

For instance, in pursuit of the “pristine core,” he explained, there is plenty of diversity about how to best handle the rock samples.

Experts are not in close agreement on many issues, such as drying rock for reservoir evaluation. Permeability and porosity have regional characteristics, and the appropriate analysis methods can take divergent paths.

Similarly, a variety of log analysis methods align cores with indirect measurements. “Calibrated logs are a moving target,” Watkins said, “and expert opinions vary greatly in tight gas and shale reservoirs.”

According to Watkins, building better asset simulators based on direct core measurements is one key result of the ongoing effort to better understand the reservoir. The next significant steps in coring will come from developing a practical approach to populating an asset simulator with complementary capabilities.

Developing tools to access tight gas

While core samples have helped increase understanding of the reservoir, innovative tools have improved efficiency and reduce costs.

In recent years, operators have changed fracturing fluids, modified the type and placement of the proppant, and incorporated novel perforating techniques to develop shale gas plays across the United States. In the Barnett Shale, for example, initial stimulation efforts consisted of enormous hydraulic fracture treatments using massive quantities of cross linked fluids and sand proppant. Over time, these methods have evolved into simpler fracture treatments ? consisting of slick water with less proppant ? that better sustain production performance.

Along with improving well productivity, operators also have had to find innovative ways to increase operational efficiency and reduce completion costs of their shale gas exploitation activities. Some operators in the US shale gas markets asked Weatherford for a cost-effective means of setting pressure barriers in conjunction with their perforating operations in horizontal and directional well bores. Previous methods, which included the use of e-coil tubing, jointed pipe and downhole tractors, were proving to be too expensive and time consuming.

Pumpdown plug saves time, money

Weatherford’s FracGuard pumpdown composite plug was developed as a result of operators’ need for improved operational efficiency and cost-effectiveness. Developed for the fracture stimulation of multiple zones, the plug was designed especially for horizontal and extended-reach applications. It was also designed with the medium- to high-pressure clear-water fracturing applications in mind, which operators have been using increasingly in their shale gas fields.

This composite plug was designed with a drag-reducing capability that allows it to be run on standard wireline in situations where e-coil or conventional CT previously would have been required. Pump pressure pushes the plug on wireline through horizontal sections, carrying the plug and the setting tools to the target or setting depth.

“The plug’s wiper design allows operators to pump at rates and volumes much lower than are possible with other existing plugs,” said John McKeachnie, US general manager for Weatherford’s completion systems group. “Plug-setting at a specified depth requires about half of the pumped fluid previously needed.”

The wiper system creates a pressure increase across the front of the plug; so low pump rates can readily carry the assembly into horizontal sections. In addition, the pumpdown plug’s patent-pending roller system reduces run-in friction on wireline in both vertical and horizontal well bores. When the composite plug is run on CT in horizontal sections, the roller system also allows for standoff for the plug to reduce friction forces and thus limit potential damage. “The plug has been run successfully on coiled tubing in horizontal applications at deviations up to 110 degrees,” McKeachnie said.

This roller-wiper combination of the FracGuard plug permits single-trip plugging and perforating by configuring the pumpdown assembly with the perforating guns above the setting tool. This way, the plug can be set, and one or more zones can be perforated in the same trip, which enhances operational efficiency and reduces the amount of rig time required. Using this plug rather than a conventional composite can save rig time by as many as two to three days per well, McKeachnie said.

Another feature of the new plug is jet ports that sit above and below the wiper ring. The ports aid in running the plug past sand bridges and other debris that settles in horizontal sections, reducing the likelihood of premature plug-setting and sticking.

Designed for efficiency

In one application, an operator wanted to install a pressure barrier after a high-pressure fracture treatment had left residual sand in a well’s horizontal section. The plug was run to 13,200 ft (4,023 m) measured depth, where it encountered the sand barrier. Pump pressure applied to the annulus achieved a flow rate of 3 bbl/minute. The design of the pumpdown plug allowed pressure to build above it and be directed through a series of ports that created jetting action below it. The jet ports washed away the debris ahead of the plug and created fluid bypass, which accelerated tripping into the hole.

Removing the new plug usually requires only a quick mill-out with conventional milling or drilling tools on coiled tubing or jointed pipe. “In this case, seven successful trips were made on coil to install the plugs and perforate in the same well bore,” McKeachnie said, noting that all of the plugs were removed in one trip using a coil-operated drilling motor over an average time span of 30 minutes each.