Trillions of cubic feet of natural gas lie in tight gas reservoirs that 20 years ago were considered uneconomical to produce. Interest in these tight gas fields has increased substantially as new stimulation technology and gas prices improved the economics of coaxing gas out of the these “unconventional” formations.

One novel technology, coiled tubing (CT) fracture stimulation, is achieving excellent production results in previously bypassed laminated tight gas formations. By efficiently targeting specific gas-bearing layers with optimal stimulation treatments, the technique maximizes hydrocarbon production while minimizing the water production associated with traditional stimulation techniques in these fields.

Avoiding water
The phrase “tight gas” typically refers to low-permeability formations that require stimulation

The sun rises over coiled tubing and fracturing service equipment sharing a wellhead for a 12-zone OptiFrac SJ fracture stimulation near Shreveport, La. (Photos courtesy of BJ Services)
to produce at commercial flow rates and volumes. For example, the Hosston formation in northwestern Louisiana has been a production puzzle. The laminated formation contains some 2,000 ft (610 m) of gas-bearing sandstone layers averaging less than 10 ft (3 m) thick, interspersed with water-saturated layers.

Although it is known to produce gas, the Hosston’s water saturation ranges from 15 to 95%, so it also tends to produce water — a significant hindrance to gas production. Furthermore, Hosston formation water is not compatible with waters in lower formations, such as the prolific Cotton Valley formations, creating scale and other issues when production is commingled.

The trick to achieving economic and reliable production from the Hosston tight gas sands was to find a stimulation technique that could very specifically target all of the gas-producing zones without fingering into water-bearing lenses. Limited-entry stimulation techniques don’t ensure stimulation of all potentially productive zones and can result in over- or under-stimulation of key zones. One effect of over-stimulation is exceeding designed fracture height and width, resulting in incursions into water-saturated zones. On the other hand, traditional plug-and-perf techniques that might ensure complete and more targeted zonal coverage are prohibitively time-consuming in laminated formations.

As an alternative to these sub-optimal technologies, OptiFrac SJ multizone fracturing technology has been very successful in stimulating the Hosston tight gas sands. BJ Services has used this CT fracturing technology to perforate and fracture about 400 zones in more than 100 wells since January 2006.

The service uses CT to convey and operate a sand jetting tool, which cuts three perforations (120° phasing) in about 10 minutes after the sand reaches the tool ports. Sand jetting is performed by operating at less than fracturing pressure to create clean, large holes with no debris in the perforation tunnel. Jetted perforation tunnels have less damage than conventional shape-charge perforations, have low near-wellbore pressure loss and tend to initiate simple hydraulic fractures. This is particularly important in gas wells because simple fractures minimize tortuosity, a key factor both in ensuring proppant transport into the fracture and in producing gas through the newly created channel.

After perforating, the crew swaps the fluid from water/sand to pump acid and spots it at the newly made perforations. Because the CT tool is still located at the perforations, the acid will hit the perforations as soon as the frac pumping starts. After pumping the acid, the CT pulls up 500 to 1,000 ft (152.5 to 305 m) for the frac.

To achieve frac pressures and rates, the frac is pumped down the casing/CT annulus. At the end of the fracture stimulation, a sand slug is pumped to isolate the zone from the next treatment. The next zone can begin immediately after CT confirms the integrity of the plug by “tagging” and performing a pressure test. A well-coordinated crew can perforate, stimulate and plug a zone in three hours or less.

Thus, unlike limited-entry techniques, the jetted technology enables targeted stimulation of
Coiled tubing crew members rig up the OptiFrac SJ bottomhole assembly, which includes a sand jetting tool to cut clean perforations immediately before each zone’s stimulation treatment.
multiple producing zones. Most plug-and-perf operations can treat just two zones per day, but well-coordinated jetted operations can treat as many as four to five zones per day. In addition, the technique can complete many zones quickly, and cleaning out sand plugs is faster than drilling out multiple bridge plugs, thus accelerating time to sales.

Optimizing 12 zones
In late May, service company crew members performed a large coiled tubing frac service in the Frierson No. 8 well in the Caspiana field about 10 miles (16 km) south of Shreveport, La.
The operation comprised sand-jet perforating and consecutive casing/CT annulus fracturing of 12 stages in the mature well. The well was drilled in 2005 to produce from the permeable, reliable Cotton Valley formation, bypassing the Hosston sands. After 2 years, production had declined to 250 Mcf/d of gas, a fairly normal decline for the zone and enough to warrant temporarily plugging off the Cotton Valley section and re-completing the well to target the Hosston formation zones from about 6,630 to 8,200 ft (2,022 to 2,501 m).

Coordinated efforts among the service organization’s pumping services and CT crews from Kilgore, Texas, enabled sequential perforating, fracture stimulation and sand-plugging of two to four zones per day during the 4-day operation. (At the end of the second treatment day, a Python composite bridge plug was set above the fifth zone to ensure isolation of the lower zones for the following 2 days of treatments.)

Cutting each set of perforations required about 1,500 lb of sand. Stimulation treatments were designed specifically for each zone, ranging from 400 bbl of fracturing fluid and 6,700 lb of proppant for the smallest zone to 1,300 bbl of fluid and 45,000 lb of proppant for the largest. For the fracture treatments, the crews pumped Lightning 25 cross-linked guar/borate-based fluid at 15 bpm (average surface treating pressure of 2,250 psi) down the 2-in. CT by 4.5-in. casing annulus. In all, the crews pumped 8,000 bbl of fluid and 325,000 lb of 20/40 sand.

After the job, coiled tubing crews from Arcadia, La., cleaned out the sand plugs and drilled out the Python plug in about 60 minutes using 13¼4-in. CT pumping 1.75 bpm and 400 scfm nitrogen. The well was cleaned out and flowing to the tank in less than 7 hours. Flowback continued for 3 days, and the well was put on line into production.

One week after the well was washed out, about half of the fluid load had been recovered and production was 2,550 Mcf/d and 489 bw/d with 1,625 psi flowing casing pressure (FCP). After 2 months, the well was producing 2,920 Mcf/d of gas and 191 bw/d with 1,400 psi FCP from only Hosston sands. The maximum production observed in this 2-month period was 3,140 Mcf/d of gas and 489 bw/d.

This gas production far exceeds that from any offset wells, and water production is lower than experienced in other Hosston completions. To date, the well’s water production has averaged 65 bbl/MMscf, whereas other wells in the field have averaged between 95 and 160 bbl/MMscf.

Because of the results from Frierson No. 8, the service company performed a second 12-zone jet treatment in the nearby Frierson No. 10 well in July.

For this well, crews pumped 8,700 bbl of fluid and 350,000 lbs of 20/40 sand. All 12 stages were fractured and successfully sanded off without requiring any additional composite bridge plugs to be set, ultimately saving one-half day of pump time compared with the initial job. The well was also washed out with the same 2-in. CT unit that was used for the frac operation. A week later, the well was flowing to sales with approximately 32% of the frac fluid recovered.

Both wells are currently producing only from the Hosston sands, but to maximize the recovered reserves, future plans are to commingle production from the Hosston and Cotton Valley sands while continuously treating the produced water downhole to prevent the scaling problems mentioned above.