Innovative systems enhance ability to achieve selective isolated production in horizontal wells

By Katie Mazerov, contributing editor

The harsh reality of the oil and gas industry today lies in complicated horizontal labyrinths of tight twists and angles, in multiple layers of sand and shale.

Production in this changing and challenging landscape has taken on a whole different meaning as the industry has had to find new methods for selectively isolating and extracting oil and gas from the now-commonplace complicated wells.

The conventional way to achieve selective isolation production in horizontal wells was to case, cement and perforate multiple zones to control flow and increase reservoir drainage, explained Ed Wood, product line manager wellbore isolation at Baker Oil Tools. But the process was complicated, time-consuming and costly, and required the use of explosives and multiple trips into the well. “Cement also has the potential to damage wellbore permeability,” Mr Wood said.

“In many wells, cost, health, safety and environmental concerns and the logistics of cementing and perforating led operators to use completions without isolation, meaning they could not mitigate water or gas production along the wellbore,” he explained. Often, this open-hole well was allowed to flow naturally, with the heel of the well or the most productive zone contributing most of the oil or gas, while the rest of the well remained nonproductive. This often necessitated drilling additional wells.

Now, those methods are being replaced by an array of state-of-the-art technologies designed to create selective isolation systems for horizontal wells. Key to the operation is the wellbore isolation packer, a technology that dates back to the 1960s, which isolates the production zones along the borehole. Most importantly, the packers eliminate the need for cement and, working in conjunction with sliding sleeves and inflow control devices, provide a system for selectively isolating production zones for treatment and controlling the flow of the hydrocarbons.

“The history of wellbore isolation is interesting and reflects the conservative nature of our industry,” Mr Wood explained. “In 1982, the first cement-plated packer was used for isolation in a horizontal well,” he said. “But it didn’t become a widely used technique until the mid-1990s.” During that period, directional drilling techniques were being developed along with improvements in mud programs so that holes would be more stable. “But the wellbore isolation part of it actually was available before the conservative industry was ready to accept it.”

The watershed year was 2002, when operators began questioning the viability of cement in long horizontal wells. “They began to accept the fact that there is a better way to do it, and that is, don’t cement at all,” Mr Wood said. “And that thinking is rapidly expanding.”

That year “was also the year we began running non-inflatable, hydraulic and hydrostatically set packers in the open hole,” he continued. “This simplified the operation and made it something that was more mainstream with what downhole oilfield experts were familiar with.”

“At that same time, what we call reactive element, or swell packers, began to be run. But it was another three to four years before either one of those techniques began to be accepted universally.”

Today, wellbore isolation packers can be inflated with cement, mud or water; set with hydraulic or hydrostatic pressure; mounted on expandable pipe or designed to react with well fluids. Mechanical and hydraulic tools, inflow control devices and sand screens are placed between the packers as part of the liner. Conventional or intelligent completions may be run inside the liner, and in some applications, the same intelligent well designs are run as an integral part of the liner.

As far as selective isolation technologies have developed, they are continuing to evolve with new, cost-efficient innovations that Mr Wood says can save an operator $250,000 to $1 million compared with older conventional methods. “We’ve got a lot of things coming down the pipeline,” he said.

One of the most exciting techniques, he believes, involves uniform inflow completions such as Baker Oil Tools’ EQUALIZER system. “In a long, horizontal well, this type of completion provides balanced flow along the entire length of the horizontal section, improving productivity, drainage and ultimate recovery per well,” Mr Wood explained. Another dynamic application, he noted, is Baker Oil Tools’ Frac-Point system, in which wellbore isolation packers and sleeves allow multiple zones to be fractured selectively in a continuous operation after the rig has been moved off location.  Applications like these, he pointed out, have had a positive impact on the industry’s ability to economically produce more oil and gas.

“The drilling engineer is pleased because he is saving at least $250,000 on cement and perforation,” he said. “The production engineer is happy because he can produce the well at a higher rate without water. And the owner is pleased because he is getting more recovery from the well.”

In short, what three decades ago was unfathomable is now being accomplished in ways that are increasingly productive, cost-effective, safe and efficient.

“Twenty or 30 years ago, horizontal wells were a novelty,” said Ron Hinkie, senior account representative for Easywell, a wholly owned subsidiary of Halliburton that provides technologies and products for well drilling and completion. “The technology was not there,” he said. “It was hit or miss. You did one stimulation job for a 1,000-ft section and you really never knew where the fluid was going. The weakest zone would take all the fluid.”

Halliburton’s Delta Stim Completion Service, which provides selective isolation techniques for completing cased wells in a continuous operation, is the culmination of 15 years of technological advances at Halliburton that include composite bridge and frac plugs that could isolate different zones inside casing, improvements in horizontal drilling and pump-down plugs, which facilitated multi-zone stimulation in horizontal wells. Halliburton is utilizing the Delta Stim system primarily in the United States, in shale-rich areas such as the Barnett Shale. Most customers today still use composite plugs, Mr Hinkie said.

The Delta Stim Completion System – which is considered a “step-change” for the industry, Mr Hinkie said – has two components: a sliding valve, the Delta Stim sleeve, and Easywell’s Swellpacker Isolation System. The technology allows an operator to selectively access several zones in a single cased wellbore with the ability to close off one or more zones. “This system was the next logical step in multi-zone, horizontal completions: an annulus isolation package, Swellpackers and the sliding sleeve for stimulation,” he said. The Delta Stim Completion System is available for 4 ½ – and 5 ½-in. casings.

The Swellpacker, an elastomer or layer of rubber bonded to the outside of the casing, swells when combined with fluid, until it forms a seal against the hole. The Swellpacker can swell up to double its size to seal the annulus around the pipe to isolate the production zones. The process takes two to three days to achieve initial swelling, and about seven days to achieve maximum differential pressure. The Swellpackers are placed every 300-500 ft outside the casing, the placement determined by the customer.

The Delta Stim sleeves are placed between the Swellpackers to open or stimulate specific sections, eliminating the need to perforate the casing. The system has three types of activated sleeve depending on customer needs:

• Hydraulically activated, which is opened simply by applying pressure to the casing from the surface. It shears the pins and moves a sleeve down to uncover ports and allow access to the formation. “This is used for the toe, or farthest-out point, of the operation so we can start pumping balls to operate other sleeves,” Mr Hinkie explained.

• Ball-activated, where phenolic or plastic balls in different sizes are dropped from the surface down the casing to land on appropriately sized baffles in the Delta Stim sleeves to operate or open each sleeve at the appropriate time. This technique allows for continuous stimulation.

• Mechanical shift, where a hydraulically operated shifting tool is run in the well on coiled tubing or jointed pipe to selectively open or close each Delta Stim sleeve.

“With the Delta Stim Completion, we go to a location one time, we do the frac in five or six stages continuously,” he explained. “We never shut the pumps down, and we can complete the entire operation in a 16-hr period. We can stimulate up to 11 zones continuously in anywhere from a 6-in. hole to 8 ¾-in. hole, internal diameter. The operation is faster, involves fewer personnel, is safer because it keeps our employees and equipment from traveling back and forth every day, and leaves a smaller energy footprint,” he said.

“The main thrust for Delta Stim completions is to improve the cycle path,” he continued. “Fifteen years ago, if you drilled a well and needed to stimulate it, you might be there a month to a month-and-a-half. “We’re at the point now where, as soon as we drill, we move the rig off, and in seven days we’re selling gas. We’re allowing the customer to get his product to market a lot quicker.”

Schlumberger is achieving lower cost and greater efficiency with its StageFRAC Multistage Fracturing and Completion Service in open-hole wells that require fracturing. The system utilizes external casing packers, a hydraulic activated frac port and a series of sleeves to selectively open zones.

“We wanted to get the benefit of an open-hole completion with a combination of multiple fractures, without increasing cost, time and risk,” said Jason Swaren, project manager for contact fracturing and completion services. “Since the first well was completed in 2002, more than 1,200 wells have been completed utilizing the technology,” he added. “Operations have ranged from cost-sensitive shale reservoirs in North America to high-profile offshore environments in West Africa to prolific carbonate reservoirs in the Middle East, to name a few. Sizes range from 2 7/8-in.to 7-in. casing in a variety of open-hole sizes.”

Schlumberger StageFRAC Video

The StageFRAC system employs external casing packers to segment the open-hole lateral into stages. The hydraulic-activated frac port is placed at the lowest stage of the well. “When you pressure up, it shifts a sleeve in the hydraulic frac port and you have an open path from the casing to the open hole,” Mr Swaren explained. Subsequent stages are controlled by shifting a series of sleeves inside the casing.

After the first stage is fracture stimulated, a ball is dropped behind the fluid and lands on a seat inside the frac port for the second stage. The balls get progressively larger and serve to isolate previous stages and allow the frac port sleeve to be shifted open.

“Typically, these operations take a day or less to pump, providing greater efficiency compared to conventional services,” he said. “The system lowers chances for screen out because you’re getting on the preferred fracture plane. No tools are required to be run into the well, lowering intervention risks. Once pumping is finished, the well can be immediately flowed back and put on production. The balls can flow out of the well with production into a ball catcher at surface.

“The StageFRAC service allows the open-hole reservoir to be broken down into discrete stages,” he continued. “The fracture treatment can be customized for each compartment, maximizing reservoir contact and reservoir drainage per wellbore. The ability to close sleeves and isolate stages can be managed to prolong the life of the well to maximize hydrocarbon recovery.”

The StageFRAC service has been validated through the use of micro-seismic fracture monitoring systems such as the StimMAP LIVE hydraulic fracturing diagnostics service,” Mr Swaren added. As the fracture stimulation propagates and the reservoir cracks, sound waves are released through the formation. The StimMAP LIVE service is able to measure these sound waves and triangulate where the sound originated in real time. In this way, the frac propagation is mapped, and treatment changes can be incorporated based on the real-time mapping.

Expandable selective isolation technologies also have been developed for open-hole reservoir applications. In 1997, Weatherford International Ltd introduced expandable slotted tubular systems to the industry, which can be used in sanding and non-sanding environments. “These systems are unique in that they can be compliantly expanded to the wellbore, giving wellbore support and eliminating the annulus,” explained Ron Fordyce, commercial director, expandable completions. “The resulting large internal diameter (ID) serves to reduce friction loss and hence pressure drop leading to increased PI, particularly in long horizontal wells.”

The vast majority of the 550 installations to date in various hole sizes have used Expandable Sand Screens (ESS) for compliant sand control. “In addition to the benefits of the large ID, significantly lower skins are evident compared to gravel packs and stand-alone sand screen completions,” Mr Fordyce noted.

“In multi-zone open-hole applications, however, the requirement for effective zonal isolation is paramount, something the industry has struggled to achieve in the past,” he continued. To that end, Weatherford and a major international operator developed and recently introduced an Expandable Reservoir Completion (ERC) system for use in 8 ½-in. hole, which has been installed in more than 20 commercial wells to date.

“The goal was to develop a modular reservoir completion system which would yield the productivity of open hole, while giving the functionality of cased hole in multi-zone applications,” Mr Fordyce said. “With that in mind, the system hinges around a robust open-hole isolation device which will effectively compartmentalize the wellbore through the reservoir section. This is applicable in both production and injection wells.”

The design brief of the ERC system included open-hole sealing devices that could withstand high differential pressure and a large bore that would afford the real estate to allow the inclusion of an inner string. “The inner string would incorporate conventional cased hole packers and large-bore hydraulic valves for independent zonal flow control and isolation, and components for real-time monitoring of well/reservoir performance and management,” Mr Fordyce said. “As a result, all system components have a base ID equivalent to 7-in., 29 ppf casing with premium non-expanded connections.”

The Expandable Zonal Isolation (EZI) device is comprised of several elastomer sealing units bonded to 7-in. pipe. As the pipe is expanded by a compliant rotary expansion tool, the elastomer elements are energized onto the wellbore. The resultant seal can withstand 3,000 psi differential pressure. “This mechanical sealing process is instant; as such it does not rely on well fluids and contact time like swell type packers, which comparatively have less differential sealing capability,” he said. “Conventional 7-in. casing (blank pipe) can be inserted between zonal isolation devices to blank off shale sections between production or injection zones.”

When sand control is required, the 7-in. ESS system can be used across the zones of interest; whereas in consolidated sands or carbonates, Expandable Slotted Liner (ECL) can be deployed. “Both of these systems eliminate problematic annulus cross-flow,” Mr Fordyce explained. “The entire system, suspended on a 7 in.-by-9 5/8-in. hanger-packer is deployed and expanded on a single trip, thereby eliminating significant time, cost and HSE risk.

“With the high differential sealing capacity of the zonal isolation device and one-trip installation, the ERC system challenges the traditional cased and perforated market, particularly in long horizontal wells requiring compartmentalizing, where high-cost cementing and perforating operations can be problematic, risky and damaging to the formation, resulting in impaired productivity,” he said.

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