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.
This graph shows the total injection of all stages that passed through the i-Frac units in each stage of the record well in Saudi Arabia.
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.
Case history
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.
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