Multistage hydraulic fracture stimulation of long horizontal wells has become a standard completion process for modern unconventional gas reservoirs. A number of techniques can be used to isolate segments of the well bore for treatment, but technology and economics constrain the number of segments that conventional plug-and-perf or frac sleeve systems can isolate effectively.

To eliminate those constraints and maximize fracture growth control, sandjet perforating and sand plugs can be used in horizontal wells to isolate segments as short as 50 ft (15 m). These technologies recently were used to effectively isolate and stimulate 43 distinct stages in a horizontal Barnett shale well.

Multistage completions
Advances in directional drilling technology have significantly improved the economics of shale exploitation by enabling

Coiled tubing-assisted multizone stimulation of smaller zones adds precision to fracture height control. (Images courtesy
of BJ Services Co.)

the creation of horizontal well bores through long segments of gas-bearing shale. These long wells must be perforated and stimulated to connect the well bore to as much reservoir rock as is technically and economically feasible. This requires multistage completion technologies to isolate segments of the well bore for fracture stimulation.

Conventional multistage completion technologies include composite bridge plugs or frac plugs in cased, cemented wells on wireline with perforating guns, or ball-drop frac sleeve completion systems most typically used in openhole wells. Economics and technical considerations limit the number of stages that bridge plugs and frac sleeves can isolate.

In the case of bridge or frac plugs, a typical stage segment comprises 300 to 600 ft (91 to 182 m) of well bore with as many as six perforation clusters. Fracture treatments are presumed to divide equally among the perforations, but without positive diversion treatments are likely to overtreat some clusters and undertreat others. Overtreating can, in the worst case, cause undesirable fracture height growth that breaches nearby water zones such as the Ellenberger in the Barnett shale.

Surface treating pressures and proppant totals per stage demonstrate the heterogeneity of the Barnett shale well.

Frac sleeve systems can isolate more than 20 stages (limited by ball size increments), and each stage typically covers 100 ft (30 m) of a horizontal well bore. Because the systems create no perforations, fracture initiation is uncontrolled. Stimulation treatments are designed with the assumption that a single fracture will initiate somewhere in the isolated interval.

For better control of fracture initiation, extension, and well bore-to-reservoir connectivity, the completion operation must isolate more, smaller stage segments without significantly affecting well economics.

Sand plugs work horizontally
BJ Services has used sand plugs to isolate treatment intervals in vertical wells for several hundred projects. The typical OptiFrac SJ service uses coiled tubing (CT) with a specialized sand-jetting tool to perforate the casing and pumps an engineered fracture treatment down the casing/CT annulus, ending with a concentrated sand slug that settles, due to gravity, into a plug with adequate consolidation to isolate the just-completed stage. This process is repeated, moving uphole, for additional stages. CT is used to clean out the sand after all stages are completed.

Isolation with sand plugs can be faster and more cost-effective than conventional pump-down plugs and frac sleeve systems. In addition to eliminating physical hardware (which can be damaged or malfunction downhole), the process replaces post-stimulation milling of plugs or ball-seats with an engineered sand cleanout. In addition, the years of experience have allowed the industry to optimize depth control for perforations; maximize tool lifetimes; integrate multiple service lines; and optimize post-job clean-outs for accurate, rapid, and seamless operations.

Gravity effects and sloughing limited the efficiency of the sand plug technique to vertical wells until LitePlug composite sand plug technology was developed using a patented ultra-lightweight proppant and proppant flowback additive to stabilize the sand plug in cased-hole horizontal completions. The technology has been used to stimulate hundreds of stages, with typical completions featuring eight or nine stages at 300-ft zone spacing.

As with the vertical version of the sand plug technique, each fracturing stage begins with perforating the casing. In wells where acid is required to reduce formation breakdown pressures, acid is pumped down the CT and spotted in front of the perforations.

Fracture treatment can be pumped down the casing/CT annulus while a low rate of clean fluid maintains pressure inside the CT and keeps the bottomhole assembly (BHA) free of obstructions.

Before the fracturing treatment is flushed, sand concentration is ramped up, and the proppant enhancement additive is added to form the isolating plug, which is pumped downhole and displaced to the perforations. The result is a controlled screenout. The sand plug does not create a complete barrier like a plug but rather a diverting mechanism with minimal pressure losses. A leak-off test verifies the isolation, and the sequence can be repeated for subsequent stages.

The 43-stage operation succeeds
The operator of a well in the Barnett shale west of Fort Worth, Texas, saw the horizontal sand plug technology as an opportunity to experiment with completion strategy. For the well’s 2,900-ft (884-m) horizontal section, a conventional completion would have targeted eight to 20 intervals with large fracture stimulation treatments. Instead, the operator wanted to minimize interval spacing and pump smaller, more efficient, and highly targeted stimulation treatments to avoid breaching a nearby water zone.

The smaller single-zone treatments reduced the surface pressure (hydraulic horsepower) requirements, allowing work to proceed with a smaller equipment footprint, reduced operational noise, and less impact on local roads.

Initial perforation spacing was a uniform distance of 80 ft (24 m). With increased field experience and positive results from the LitePlug technology, perforation spacing was reduced to between 50 and 60 ft (15 and 18 m). Ultimately, the record-setting operation completed 43 intervals in 17 days of daylight-only operations.

The stimulation process also was optimized during the job. The time required to circulate perforating sand out of the well was dropped from an initial 90 minutes to fully remove the sand to 40 minutes of circulation that safely redistributed the sand uphole from perforations on the low side of the well bore. The fracture treatment’s pad ramp-up rates were modified to gradually re-entrain the sand and decrease the chance of a premature screenout.

Fracture response was monitored for each stage. At early indications of an unplanned screenout, the main treatment stage was shortened to go straight to ramping up density for the plug stage. (In a conventional fracture procedure, the proppant would have been cut and the slurry changed to flush.)

This approach increased the chances of successfully displacing the sand plug to the required depth. The extended operation also verified the longevity of the sand-jetting nozzle technology and other BHA components. In all, the operation used six perforating nozzles, each replaced due to operational convenience rather than engineering tolerances. Four nozzles completed nine to 10 cuts each, demonstrating the erosion resistance of the engineered nozzle design. The job also used three nozzle carrier tools, which were subjected to external erosion from nearly 4 million lb (1.8 million kg) of proppant pumped at 10 to 18 bbl/min during fracture stimulation operations.