As operators continue to drill and complete deeper and increasingly challenging wells in emerging plays, they are relying on advances in completion technology that can accommodate HP/HT ratings to perform the desired stimulation. Ongoing exploration and development in unconventional reservoirs has continued to push the technological boundaries of downhole equipment.

Not all stages are created equal in a horizontal wellbore. Formation heterogeneity along the lateral can lead to greater-than-expected differential pressures, where each isolated zone has a different breakdown pressure to initiate a fracture. Often, treatments that have not been executed as designed are due to treating pressures reaching the limitations of downhole equipment.

hpht formation image

In the Montney shale in the Western Canada Sedimentary basin, operators typically encounter underpressured zones and high fracture gradients. (Images courtesy of Packers Plus)

For example, operators working in the Montney in the Western Canada Sedimentary basin typically encounter underpressured zones and high fracture gradients. The play is estimated to contain 80 Tcf to 700 Tcf of natural gas and is made up of a varying depositional environment. Due to its rich silt and sand composition, the Montney is often referred to as a tight gas reservoir; however, the natural gas found within the formation is generated in place, a characterization more typical of shale gas reservoirs.

An underpressured zone can lead to a greater-than-expected differential pressure across an isolated interval. In this situation, a burst scenario could be encountered. This scenario occurs when a high treating pressure is required for a lower interval while an upper interval is exposed to a lower bottomhole pressure (BHP).

Downhole tools with higher pressure capabilities reduce the risk of burst and collapse scenarios often encountered in zones where these conditions exist. Additionally, some areas in the Montney have a high fracture gradient, resulting in higher breakdown pressures and thus the need for higher treating pressures to perform effective stimulation.

The trend toward increasing pumping rates, lateral lengths, and stage numbers adds to the need for high-pressure tools.

Case study in the Duvernay shale

The Duvernay is the latest emerging liquids-rich shale play in Alberta covering a surface area of approximately 100,000 sq km (38,610 sq miles). The Duvernay is best known as the source rock for the Devonian-aged Leduc Reef, Keg River, and Slave Point formations, and development in the Duvernay is currently in its infancy. It has drawn comparisons to the Eagle Ford shale in the US due to its high liquids content and similar reservoir characteristics.

The formation is composed of interbedded bituminous shales, calcareous shales, and dense argillaceous limestones. The thickness of the formation varies, ranging from 10 m to 70 m (33 ft to 231 ft) depending on the location. Approximate depths range from 2,500 m to 4,000 m (8,250 ft to 13,200 ft).

Due to the early phase of development, publically available reservoir data of the Duvernay are very limited; however, estimates in the Kaybob region have indicated a porosity range of 3% to 12% and permeability up to 0.01 mD. Sweet spots in the formation are yet to be determined but will be exposed as more wells are drilled in the area. The Duvernay was once thought to be uneconomical to produce and, consequently, was largely ignored until horizontal drilling and multistage fracturing began unlocking resource plays.

An operator targeting the Duvernay shale in the Kay-bob region completed a 25-stage well with a combination StackFrac and QuickFrac Titanium XV HP/HT system. The system was run into a wellbore with a lateral length of 1,735 m (5,725 ft), true vertical depth of 3,390 m (11,187 ft), and measured depth of 5,160 m (17,028 ft). BHP in the wellbore was 6,816.8 psi, and bottomhole temperature was 115°C (239°F).

During the slickwater fracture treatment, the surface treating pressure and pump rate reached 10,007.6 psi and 16.5 cu m/minute (582.7 cf/minute), respectively. Pump rates ranged from 8.2 cu m/minute to 16 cu m/minute (289.6 cf/minute to 565 cf/minute) during stimulation operations. An average of 98 metric tons of proppant and 1,000 cu m (34,315 cf) of slick water was used per stage to fracture the well for a total of 2,440 metric tons of prop-pant and 25,030 cu m (883,926 cf) of slick water.

Designing downhole stimulation systems

The Titanium XV system uses proven technology to enable the stimulation of challenging HP/HT wells in areas that could previously not be completed due to the limitations of downhole equipment. Continued exploration and development in deep shale formations highlight the need for innovative solutions in reservoirs that are defined by a unique set of completion challenges, including high fracture gradients and breakdown pressures, high differential pressures, and geological heterogeneity. More than 45 StackFrac Titanium XV systems have been run in tight sandstone reservoirs and shales in Canada, including in the Montney and Duvernay.

The system addresses the need for completion systems in wells where differential pressures above 10,000 psi could be encountered. These HP/HT tools are capable of withstanding differential pressures of 15,000 psi and extreme bottomhole temperatures. This was achieved through the use of an innovative metallurgical composition and premium seal technology. The Titanium XV system was developed with the same function and design as the Packers Plus StackFrac system, which uses a continuous pumping operation to effectively stimulate isolated zones along the entire length of the wellbore. Mechanical isolation is achieved with the Titanium XV RockSeal ll packer. A Titanium XV FracPort sleeve is run in between two packers to allow specific zones of the wellbore to be selectively fractured.

In addition, HP/HT tools also have been developed for the QuickFrac batch fracturing system to allow limited entry stimulation in openhole completions and for the SF Cementor stage collar for cemented-back monobores. All of these systems are modular, allowing combination systems to be run. This method maximizes the number of stages available while maintaining the largest ball-seat size possible for coiled tubing intervention.

Packers Plus developed the Titanium XV system to address these limitations with higher pressure-rated tools capable of withstanding aggressive environments. With applications in Canadian formations such as the Montney, Duvernay, Cadomin, Nikkanasin, Alberta Bakken, and Deep Foothills, the Titanium XV system can be applied to shale and sandstone formations around the world.