Quest for the most efficient field-frack network

Since the beginning of the unconventional resources boom, there have been two primary methods used for completing hydraulically fractured wells—plug and perf (PNP) and openhole completions.

PNP has been the most widely used method for multistage completions while openhole, which uses swellable packers and ball-drop sliding sleeves, became an alternative more recently.

Tens of thousands of unconventional wells have now been completed using these two methods, which have proven especially effective in the early production life of the wells.

However, as the unconventional segment matures, operators are seeking the means to address the wells’ steep declines in production. Analytical tools and techniques are improving, and operators are realizing that production can be significantly improved with drilling and completion programs designed for maximum reservoir connectivity. This has given rise to the concept of an “efficient field-frack network,” which combines optimum well spacing with consistent stage spacing.

FIGURE 1. This illustration demonstrates an ideal frack network for a single section of a lease with consistent frack spacing and frack volumes. (Source: NCS Energy Services)

Efficiency for all wells

The field-frack network concept is a starting point for optimized field development because it takes the inconsistency and unpredictability out of the frack-delivery mechanism regardless of formation type, proppant type, pumping program and other variables. Whatever the completion design, it must be delivered precisely and predictably, or a significant percentage of the reservoir will remain unstimulated. Figure 1 illustrates an ideal frack network for a single lease section with four evenly spaced wells, each having frack stages of equal volume. Such a network ensures maximum reservoir coverage. The goal is to repeat this pattern across the entire lease acreage.

Unfortunately, it is not possible to achieve either consistent stage spacing or uniform frack volume when using PNP, the limitations of which are well known and documented. To minimize stimulation cost and time, PNP attempts to stimulate multiple perforation clusters simultaneously, but with frack fluids being bullheaded down the casing, there is no practical way to predict or control which clusters actually fracture, how big each fracture is and how proppant is distributed. Variable frack gradients along lateral sections (Figure 2) ensure that all fracks are not equal.

Studies using radioactive tracers have revealed that many clusters are not stimulated at all, while others receive varying amounts of treatment. A comprehensive study of production logs from a number of unconventional reservoirs reinforces that finding, concluding that about a third of all perforation clusters do not contribute to production. Yet another study indicated that a higher ratio of fluid enters the first perforation cluster, while a higher concentration of proppant enters the lower perforations.

When multiple parallel wellbores are completed using PNP, the effect of the inconsistent frack pattern is multiplied, with gaping areas of the formation unreached by the stimulation, as illustrated in Figure 3. Although it has been the go-to workhorse for many years, PNP simply cannot deliver the predictability and control needed to optimize reservoir connectivity.

FIGURE 2. Variable breakdown pressures are recorded across a lateral in an Eagle Ford well. (Source: NCS Energy Services)

With openhole packers and ball-drop sleeves, frack ports are typically located halfway between the packers, suggesting consistent spacing between fractures. But again, because of variable breakdown pressures, the fractures can initiate anywhere between the packers or even at a packer where the formation already is stressed. There might be a single large fracture, or there might be multiple small fractures; there simply is no way to predict or control the fracture location and volume.

Adding to the uncertainty is another shortcoming of openhole packers: interstage communication during stimulation that can deplete the energy being applied to the target stage. In a number of openhole completions, recorded downhole pressures have revealed that interstage communication is quite common. In one project involving 13 openhole completions, recorded downhole pressure measurements confirmed interstage communication in 80 of 185 (43%) of the stages.

CT method delivers

The Multistage Unlimited completion system (Figure 4) from NCS Energy Services combines cemented casing sleeves and a coiled tubing-deployed (CT-deployed) tool assembly to deliver predictable frack spacing and volume.

The casing sleeves match the specifications of the host casing string and are inserted in the casing string at the desired stage spacing. All sleeves for a given well are identical and therefore can be installed in any order. Unlike conventional ball-drop sleeves, these sleeves are full-drift at all times, so they permit normal cementing operations. The fracture-isolation assembly comprises a casing-sleeve locator, a resettable isolation bridge plug and a sand-jet perforating sub that can be used to add stages in blank casing.

FIGURE 3. Inconsistent frack spacing and frack volumes leave much of the reservoir unstimulated. (Source: NCS Energy Services)

During stimulation, the fracture-isolation assembly is run on CT to locate the lowest casing sleeve. The isolation bridge plug is then set inside the casing sleeve, where it grips and seals inside the inner sleeve. An increase in wellbore pressure from the surface forces the bridge plug assembly and inner sleeve down, opening six large frack ports at the top of the outer sleeve. Fluid and proppant are then pumped down the CT/casing annulus into the formation, while the CT serves as a dead string to provide real-time frack-zone pressure. Next, a pull on the CT can unset the bridge plug, and the assembly can be moved up to locate the next sleeve. This sequence is repeated until all stages have been stimulated. Then the frack-isolation assembly is pulled from the well, leaving an open, production-ready wellbore.

With cement sealing the annulus, fractures initiate only at the frack-sleeve ports, maintaining the designed stage spacing. Single-point injection allows the amount of proppant for each fracture to be controlled so propped volume can be consistent for all stages. Premature screenouts can be avoided by monitoring actual frack-zone pressure in real time via the CT dead string. By observing the formation’s pressure response, the pump rate and sand loading can be adjusted on the fly to ensure a fully propped fracture. With the circulation capability at hand, sand loading can be aggressive because excess proppant is easily circulated out before moving on to the next stage.

FIGURE 4. The Multistage Unlimited frack-isolation assembly deployed on CT isolates the target stage and shifts the cemented casing sleeve. The frack is pumped down the CT/casing annulus. (Source: NCS Energy Services)

More stages, greater control

Since being introduced in early 2011, more than 46,000 cemented casing sleeves have been run through the Multistage Unlimited system. The technology has enabled operators to increase the number of stages while controlling spacing and propped volume—for example, 92 sleeves in a single Eagle Ford well, 86 sleeves in a Bakken well and 53 sleeves in a Permian Basin well. The system also has been used to complete multiple wells with 3.2-km (2-mile) laterals. In the Permian’s Bone Spring Formation in West Texas, the system has boosted production by more than 100% compared to equivalent PNP completions, while in the Bakken it has increased production 73% compared to openhole completions.

References available on request.