Ball-drop activated sliding-sleeve system used to fractures zones that were previously inaccessible with coiled tubing or wireline
By Reza Rastegar, Tom Koløy, Mohammed Munawar and Stephen Forrester, National Oilwell Varco
Multistage completions using sliding sleeves that allow one-stage, multi-clustered implementation with variable or consistent nozzle sizes were introduced for acidizing completions in the North Sea in the late 2000s. As the practice evolved, it became clear that North American shale projects would be more difficult. Although drilling and completion of extended horizontal wells remained more economical than drilling new wells for further access to the pay zone, there were challenges with perforating the extended section. Open-hole completion had been practiced as a solution but was not ideal for use in shale. Injected fluid took the path of least resistance to the formation, rarely covering the entire payzone accurately or efficiently.
Technological advances and improvements to completion techniques, however, ultimately yielded better stimulation of the entire horizontal interval, leading to the rise of multistage fracturing as the completion method of choice for North American shale projects. In other regions, however, companies are also increasingly adopting the completion systems and methodologies that are enabling the high performance seen in North American shale.
National Oilwell Varco’s (NOV) i-Frac ball-drop activated sliding-sleeve system is one such system. Recognizing its potential, an operator in Saudi Arabia recently implemented the system in a major project where typical wireline and coiled-tubing operations were insufficient.
Sliding sleeve system
The ball-drop activated multistage fracturing sleeve was designed for cemented horizontal completions. The system is installed as an integrated part of the lower completion string, with seat and activating ball sizes increasing sequentially from toe to heel in the horizontal section.
Two valve types, flex and fixed, interact differently with the ball. The ball activates the flex valve and passes through it but cannot pass through a fixed valve after activating it. One ball shifts and passes through all the flexible-seat valves, then shifts and stops in a fixed-seat valve downstream of the stage and isolates it from the previous one below. Flow is diverted through each valve’s ports in the stage and to the formation. The seats are millable, and the balls are dissolvable. Once the balls dissolve, the path of flow from all zones to the wellbore is reestablished.
Generally, friction and hydrodynamic pressure do not vary significantly between plug-and-perforation and sliding-sleeve completions. As such, the number of valves that can be installed in each stage depends on the maximum allowable differential pressure and maximum available surface pump horsepower to achieve the target treatment flow rate.
The maximum differential pressure of the ball and seat usually outweighs the maximum allowable differential pressure of the treatment, and the activation ball has a different class of increments depending on the pressure it undergoes. Typical increment classes are 1/6, 1/8, 1/10, 1/12 and 1/16 in., with seats varying in diameter from 2 to 4 ½ in., depending on the size of the casing. Additionally, a variable number of stages can be completed with the system, based on casing size, with several fracturing valves in each stage.
The system has seen widespread implementation in North America, Russia, New Zealand and the Middle East, with installation in the Bakken Shale dating as early as 2010. To date, more than 10,000 stages have been completed with the system. A well that previously took an average of 45 days to acidize in the North Sea, for example, was stimulated in 1.5 days with the system, and in South Texas, completion time was reduced by 50% by using the system instead of traditional plug-and-perforation techniques.
The physics of completion
Several key engineering points have to be considered for completions using the system. These include the following:
Limited entry pressure
Limited entry is a critical concept when designing stages with multiple sleeves and exit points. As fluid exits the casing through the nozzles, it always takes the simplest path to the formation, meaning that a lack of pressure drop across the nozzles will cause the fluid to exit through the single point where the resistance to the formation is lowest. This results in only one initiated fracture as opposed to multiple fractures in the stage. Choking back the nozzle orifices creates a pressure loss across each nozzle, causing fluid to flow through all exit points as opposed to one; when fluid travels through the exit points, it creates the least amount of pressure loss versus only traveling through one nozzle.
Fluid pressure loss due to venture effect is not unfavorable when completing with the system. In fact, in scenarios where multiple valves are installed in one stage, it is better that there is a limited entry pressure buildup to ensure that all discharge nozzles are actively injecting fluid into the formation. Limited entry pressure buildup can be achieved by changing the quantity or size of the nozzles, although the size cannot be less than eight times that of the largest size of proppant that will be used in treatment.
The degree of limited entry may vary between formations and, broadly, the specific needs of individual operators. For completion with the system, though, a limited entry pressure of 500 to 1,000 psi is advised, as such a level is generally sufficient to divert fluid through all of the sleeves in a given stage and initiate a separate fracture at each sleeve.
As differential pressure increases, the chance of successfully diverting fluid to all of the sleeves and creating separate fractures also rises. Despite this, there are several additional considerations:
• Maximum allowed treating pressure – The operator might be unable to reach the desired treating range for a stage if the stage is designed with a very high limited entry effect.
• Mechanical failure – The mechanical strength and integrity of the fracturing ball may be jeopardized if the limited entry effect is too high.
• Screenout – As pressure loss increases across the nozzles, the fracturing fluid has less pressure and energy to transport fluid and proppant into the formation, leading to a higher possibility of a screenout.
Pressure change through seats and discharge coefficients of seat and nozzles
As a stream of fluid passes through an orifice, it loses pressure. High velocity assists with fluid stream turbulency, which facilitates carrying proppants and reduces the risk of both proppant bridging and premature settlement. Discharge coefficients of 0.8 and 0.95 are chosen for the seats and nozzles, respectively, based on their design. The discharge coefficient of 0.8 for the nozzle is based on the nozzle’s geometry.
Shear pressure of activation for seats
Pins are sheared and the valve is shifted open when hydrostatic pressure, with the landing of a ball on a seat, is transferred to force. There is differential pressure across all seats in the well at a target flow rate. If the differential pressure across a seat at the maximum allowable flow rate exceeds the shear pressure rate of that seat, flow can prematurely shift the valve without the need for a ball. This means that the minimum shear rate of a seat should be more than the differential pressure across that seat at the maximum allowable flow rate of the remaining stages.
Hydraulics of treatment
Pressure is lost when fluid is pumped through a tubular. Following this principle, pressure is also lost when fluid is pumped through a fracture and into the formation. It is critical that the ball hold this pressure. If excessive formational pressure loss is expected, a higher-grade fracturing ball should be used to avoid failure. Using knowledge of wellbore hydraulics allows estimations of the treating pressure, which is important when recommending completion string design. Failure to properly estimate treating pressure may result in not being able to treat the well as per the design.
Tubing-conveyed perforation guns have traditionally been necessary to gain access to the formation at the toe of a horizontal well for stimulation purposes. Although this perforating method often requires complicated operations and capital-intensive setup, NOV’s Burst Port System (BPS) technology can more cost-effectively achieve the same result without tubing.
The BPS uses pressure-activated ports to create a conduit from the wellbore to the formation face, and BPS collars contain built-in nozzles covered by burst disks designed to open at a predetermined pressure. An atmospheric chamber behind the burst disks on the formation side allows the BPS to activate at absolute, rather than differential, pressure.
BPS collars are run as part of the production casing, typically cemented in place, and activated by pressurizing the wellbore at surface. Multiple collars can be installed throughout the toe section with predetermined spacing, resulting in the stimulation equivalent of multiple perforation clusters across the interval. To ensure all BPS ports are open, bio balls are pumped from the surface to shut off the open ports in the collar, allowing for a subsequent pressure increase to rupture the remaining ports in all collars in the toe stage.
The i-Frac and BPS technologies were recently chosen by an operator to be used, for the first time, in the longest long-string horizontal well ever completed in Saudi Arabia. The extended-reach well was cemented, completed and hydraulically fractured in zones that were previously inaccessible by coiled tubing or wireline. The well was drilled to land at approximately 10,825-ft (3,300-m) true vertical depth, with the formation bottomhole temperature at approximately 280°F (138°C) and bottomhole pressure at 7,500 psi.
Prior to installation, stakeholders were briefed on system operation, requirements and design considerations, with particular focus placed on cementing operations due to the unique nature of the project. Components in the cemented ball-drop system included cement protection features, which allow regular cement slurry to be pumped down the casing without contaminating the moving parts. Additionally, a special wiper dart allowed the long-string casing to be sufficiently wiped, and cement simulations verified that the casing, with sleeves and accessories, would not increase pressure during cementing and cause issues with equivalent circulating density.
After design reviews, risk review sessions were held to solidify expectations and determine the procedures necessary to ensure smooth installation. Backup plans were developed to deal with potential failures, and lessons learned from North American shale projects were incorporated during planning.
Key discussion points included how to optimally reach total depth (TD); optimal cementing procedures; maximum allowable overdisplacement during the cement job before shutting down the pumps; contingency plans to deal with a wet shoe or a wiper dart unable to hold pressure; pre-hydraulic fracturing cleanout procedures; and a detailed fracturing program. Simulations of the completion string were done to evaluate the deployment and expected torque.
Installation of the shoetrack and cementable ball-drop operated sleeve equipment was done, followed by running the rest of the long-string casing. Bottom was tagged softly with the long string to confirm TD, then the space-out was done and casing hanger landed. The rig-up for the cement job started after a period of circulating and conditioning the wellbore. Spacer and cement was pumped and displaced at rates up to 8 bbl/min while monitoring the circulation pressure to ensure the burst pressure of the toe subs were not exceeded.
Once the required volume of cement was pumped, the pumps were shut in and the wiper dart launched manually down the cementing manifold on top of the casing. Lines were connected and pumping commenced, with the wiper dart landing slightly early versus the calculated volume; this is often observed when doing manual launching. Pressure was applied to lock the dart in place in the landing collar and thereafter bled off to check for inflow, confirming that the shoetrack was successfully holding. After some time, the casing was pressure-tested to the predetermined test pressure. In the end, the installation of the long-string completion with cemented sleeves was a success.
For hydraulic fracturing, the stages are detailed as follows:
The BPS activated at 11,437-psi surface pressure and an average injection rate of 16 bbl/min was established to secure travel of the ball from the surface to the i-Frac valves in the following stage. At an average rate of 16 bbl/min, 512-psi pressure was exhausted on friction.
The first stage consisted of three flex valves and one seat. A 3 ¾-in. ball activated all three valves to land on the seat, with pressure dropping from 10,300 to 8,700 psi on activation of the first valve, when the formation broke. Pressure drawdown is caused by the transition from a charged section of rock to a new section, which is disconnected from the treated part of the formation. Sufficient spacing and stage isolation were achieved, and treatment continued after the screenout. Once isolation from the toe stage occurred, formation break-through and a steady treatment rate were achieved.
The second stage consisted of three flex valves and one seat. A 3 ⅞-in. ball activated all three valves to land on the seat. The ball landed on the first valve at 8,850 psi and, after activating all valves, the formation broke at 8,950 psi. Pressure of 4,600 was exhausted on overcoming the friction, mostly in the formation, and the valves successfully activated and discharged fluid to the formation through the nozzles.
The third stage consisted of three flex valves and one seat. The 4-in. ball landed on the first valve at 11,500 psi and, after activating all the valves, the formation broke at 9,250 psi.
Using innovative technologies such as the i-Frac and BPS systems allows operators to realize greater performance when completing challenging shale projects. Further, experience gained from multistage fracturing performed with the systems will enable operators to improve success rates and increase efficiencies. Future developments with the technologies will be focused on achieving constant ID size and the ability to operate at even higher pressures, allowing operators to complete more stages at longer lengths in more difficult drilling conditions. DC
i-Frac and BPS are trademarks of National Oilwell Varco.
This article is based on SPE/IADC 189419, “Multistage Completion and Hydraulic Fracturing of the Extended Zones of the Longest Long-String Horizontal Well in Saudi Arabia Enabled by Adopting Completion Technology and Experience from North American Shale,” presented at the 2018 SPE/IADC Middle East Drilling Technology Conference and Exhibition, 29–31 January, Abu Dhabi, UAE.