NICK POTTMEYER, Nine Energy Service
Zonal isolation is essential for safe and efficient hydraulic fracturing operations. When fracturing is confined to the targeted section of the wellbore, the extraction efficiency is maximized, and environmental impacts are minimized. For these reasons, it is critical for operators to select isolation methods and tools that are effective, especially as laterals get longer and additional stages are added to isolate each targeted section of the wellbore. There is another reason to select isolation systems carefully; some have additional features derisking common well complications.
Innovations in technology are allowing operators to prepare for costly setbacks and inevitable eventualities. Operators can now select tools that will help them respond quickly to undesired events, such as tool malfunctions—like perforation guns that fail to fire—and wellbore conditions, like screen-outs.
Fig. 1. Six fundamental composite plug considerations.
PLUG SELECTION
As laterals get longer, the question of how to properly isolate the stages in each well becomes more significant. When a single well has up to 100 stages, it becomes essential to find a plug that will properly isolate each of those stages. Though it can be a daunting task to evaluate all of the features on the market, the criteria for selecting a composite frac plug can be grouped into six fundamental considerations, Fig. 1.
The first three considerations are traits of the plug that ensure it works as intended:
- Reliability: How will the plug make the journey down the well? Each plug must be reliable enough to survive the pumpdown to depth.
- Durability: How will the plug set and hold the fracture? Each plug must withstand the pressure required to isolate the section.
- Drillability: How will the plug drill out with up to 100 plugs in a wellbore? The plug must be easy to remove.
The next three considerations are not related to the initial isolation, but they are important features to avoid costly setbacks:
- Ball-in-place option: Does the plug reduce water usage?
- Ball recovery feature: Does the plug allow for easy remediation, if wireline has a misfire?
- Screen-out recovery feature: Does the plug allow for screen-out recovery?
When evaluating each of these features, operators should seek to understand how the feature works and which risks are addressed or left unaddressed by the tool. Selecting good tools that can derisk multiple situations is essential for the success of the system.
BALL IN PLACE: REDUCING WATER
Fig. 2. Saving 450 to 500 bbls of fluid on lower stages with strategic ball-in-place solutions.
Operators increasingly request the option to run with a ball in place. Over the course of up to 100 stages, it takes a tremendous amount of water and time to seat the ball, if the ball is not run in place. After the plug is pumped down the well and set, perforations are shot above it to stimulate the stage. If the perforating guns do not fire, and it is necessary to pull the toolstring out, the toolstring cannot be pumped back down, if the plug’s inside diameter (ID) is sealed with a ball. Energy below the plug may be able to flow the ball to surface. However, in depleted fields, such as the Midland basin and certain areas of the Marcellus shale, there may not be enough pressure for this to happen. If the frac ball is not recovered, the result is time- consuming, expensive and may require intervention with coiled tubing, a tractor or a workover rig.
Operators frequently desire the option to run a ball in place, because it allows for significant cost savings. If there is a ball-in-place option for a 20,000-ft lateral within a 30,000-ft measured depth (MD), this allows the operator to save 450 to 500 bbls of fluid on the lower stages, Fig. 2. As stimulation continues up the wellbore, the barrels of fluid saved gradually decrease, because the distance also decreases.
BALL RECOVERY: REDUCING UNCERTAINTY
If the plug is set and the perforating guns do not fire, a ball recovery system allows operators to re-initiate pumpdown. This option saves operators both time and money.
Some ball recovery features require flowback with wireline in the well. However, this is risky and not ideal, because there is no way to verify that the ball is recovered in the wireline tool until the toolstring is pulled out of wellbore. When the toolstring is at surface, there is no second chance for ball recovery.
If ball recovery depends on a spring-type system, there is a certain pump rate required to create enough pressure to seal the ID of the plug. A spring system holds the ball off seat until the pump rate overcomes the force of the spring. A reduced rate pushes it back off seat.
A ball recovery that depends on a frac dart only requires a bit of differential pressure to dispel the dart, providing access to pump through the ID of the plug.
SCREEN-OUT RECOVERY: SAVING TIME AND MONEY
Screen-out recovery is a recent addition to the list of recommended features, made possible by new technology. Screen-outs are one of the costliest set-backs that can occur on a well. They occur when solids, such as sand, block the flow of fluid. A screen-out is usually identified by a rapid rise in pump pressure. Screen-outs can significantly impact an operator’s schedule and lead to lower oil and gas recovery.
Screen-outs during fracturing operations are time-consuming and costly to resolve. Traditionally, operators must flow the well back to clear screen-outs, hoping to recover the frac ball to allow for the subsequent stage pumpdown. If unsuccessful, a coiled tubing clean-out may be required.
Ball recovery systems traditionally do not allow for screen-out recovery. For example, a ball recovery system dependent on a spring will not allow the well to be flushed properly. Operators cannot clean out the wellbore through the ID of the plug at an adequate rate, because the ball will reseat on the plug.
A frac dart provides the same isolation functionality as a traditional ball but allows for screen-out recovery.
CASE STUDY
This case study focuses on the Marcellus shale, in an area with surface shut-in pressure of approximately 2,500 psi, but the concepts are applicable in all basins that allow for negative differential pressure across the plug.
Challenge. The Marcellus shale can be challenging to stimulate and is prone to screen-outs. It has tight pore spaces and a complex fracture pattern that can make proppant placement challenging, increasing the risk of screen-outs.
As the Marcellus fields mature, the reservoir pressure is decreasing, making it more challenging to flow back the frac ball and recover from a screen-out. Lateral lengths also continue to increase, adding to the difficulty of recovering the ball, with toe stages being the most difficult.
In September 2024, a Marcellus operator in Armstrong County, Pa., needed a way to reduce the time and cost impacts of screen-outs. The operator specifically wanted to reduce downtime in a complex, horizontal well that had already experienced screen-outs. The operator was using a traditional plug and ball but heard that other operators achieved successful recoveries from screen-outs by using a frac dart.
Tool selection. The operator selected a composite plug and frac dart feature.
Composite plug. The frac dart feature was deployed with a proprietary Scorpion composite frac plug, which is made from thermo set, molded composite and filament-wound fiberglass (no metallic material). The Scorpion was chosen for its reliability; it has a run history of over 420,000 units. The plug’s durability during pumpdown and holding capabilities during fracturing had been tested in some of the longest, most challenging laterals ever completed. Additionally, it allowed for 10-min. mill-outs and had excellent drillability, with 144 plugs drilled out with a single bit. The differential pressure across this plug is rated at 10K; in the Marcellus, the differential ranges between 3K to 8K, depending on the area and location in the wellbore.
Frac dart. The proprietary frac dart selected for this case study had been engineered specifically for installation within the Scorpion plug and eliminated the need to pump down a ball from surface.
- The frac dart had a ball recovery feature. If perforation guns fail to fire, the operator could open the well at surface, to create negative differential pressure across the plug, which would push the dart out of the plug. The frac dart does not reseat, so the operator could pump through, reperforate and drop a ball for isolation.
- The frac dart had a screen-out recovery feature. After a plug was set, the fracturing would begin when water and sand were pumped into the perforations above the plug. If a screen-out occurred, the frac dart could be expelled, the well flushed, and the operator could further stimulate the current stage or move on to the next stage.
Implementation. After experiencing multiple screen-outs that required coil tubing clean-out during fracturing operations in the Marcellus with a different plug system, the operator decided to implement the Scorpion plug and frac dart to test the ball recovery and screen-out features. The selected well had a measured depth of approximately 20,800 ft, with a lateral section of approximately 14,000 ft. After setting the plug with a frac dart on one of the early stages of this well, the operator experienced another screen-out that left 12,000 lbs of sand in the wellbore. The operator flowed back to successfully unseat the frac dart from the plug. An injection test ensured the wellbore was clear, a ball was dropped to regain isolation, and the operator resumed fracturing operations in one hour without issue.
Results. The frac dart expedited screen-out recovery, allowing the operator to resume fracturing without significant delays. By having the frac dart in place, the operator was able to forgo the usual need for coiled tubing.
The operator noted that the composite plug and frac dart worked as expected:
“[The frac dart] came unseated after a brief flowback. We were able to quickly bring rate back up to 15 bpm, to move sand, since it hadn’t settled out, and then brought rate up to 40 bpm to ensure a clean hole. The entire process took an hour. At our current depth, to do our normal flowback and injection process, it would have taken at least 12 hrs, assuming it would go as planned. It probably saved us close to $36,000 between injection cost, diesel, and daily pad cost.
The efficiency gains and budgetary difference from screen-out recovery were significant, so the operator chose to use the same plug and frac dart on 100% of their stage completions moving forward.
Fig. 3. Pressure data from a screen-out with frac dart recovery.
SCREEN-OUT AND BALL RECOVERY IN PRACTICE
Another operator in the Marcellus experienced close to a dozen screen-outs over multiple pads that demonstrated the efficiency gains from the plug and dart system. Figure 3 shows pressure data from one such screen-out.
The green line represents frac treating pressure, and the orange line represents the treating rate of barrels per minute. The well pressured out shortly after 0.1 ppg hit bottom, so the operator flowed the dart off seat and pumped an injection test before pumping back down and re-perorating that stage. The time scale on the bottom of the figure shows that the whole process, from screen-out to completing the injection test, occurred in about an hour. This represents a marked improvement from the traditional method of flowing a ball back, which is a 3–4-hr process, at best.
CONCLUSION
As operators face increasing demands for efficiency, it is essential that tools and technologies also become increasingly efficient. It is no longer enough for a plug to simply provide isolation; the plug must also continue to provide efficiency in a multitude of situations and setbacks. Operators with the forethought to examine evolving technology for efficiencies in challenging situations will save time and money in the long run.
Question each specific completion tool and question the system, as a whole. Ask:
- Is your plug multipurpose?
- Does your plug provide ball in place, ball recovery and screen out recovery features?
NICK POTTMEYER serves as the president of Completion Tools at Nine Energy Service. Prior to serving in this position, he served as senior vice president of Completion Tools for Nine. Before joining Nine, Mr. Pottmeyer spent the last decade supervising, bidding, locating vendors and generally managing all aspects of completion for hundreds of wells at Chesapeake Energy. During his career, he has worked as a roustabout, field engineer, drilling and completion foreman, production engineer, drilling engineer and completion superintendent for major energy companies, in projects that range from deepwater platforms to traditional wells to horizontal wells in a host of challenging fields and formations. Mr. Pottmeyer earned a bachelor’s degree in petroleum engineering from Marietta College in Marietta, Ohio.
Related Articles
FROM THE ARCHIVE
