Driving efficiency in cemented liner completions
Oil and gas producers have succeeded in boosting production from horizontal wells in unconventional reservoirs over the last decade. This is attributed to advances in directional drilling, longer laterals, and multi-stage stimulation techniques. Additionally, changes in completion strategy, such as tightening stage spacing, also has been beneficial. An engineering study in the Haynesville and Bossier shales shows a 22% production increase (4.5 to 5.5 Bcfg) per well, as average stage spacing between perforations dropped from 272 ft to 150 ft between 2011 and 2013. Completion designs also have trended toward higher fluid and proppant volumes.
LIMITATIONS OF PLUG-AND-PERF METHOD
The most common technique used in cemented liner completions is the plug-and-perf (PnP) method. Despite the simplicity and popularity of PnP completion operations, the method has the following drawbacks:
- Excessive completion time
- Operational risk
- Safety concerns
- Mill-out issues
- Unproductive clusters.
Excessive completion time. While PnP completions are known for being flexible and simple, they are inherently inefficient, requiring trips in and out of the well for each stage to detonate perforation charges and set bridge plugs. This process also requires more fluid, relative to sliding sleeve systems, significantly adding to costs.
Operational risk. Tripping in and out of the wellbore adds to non-productive time (NPT), and increases the likelihood of encountering problems, such as stuck wireline if a bridge plug does not release. In these situations, operators are forced to either mill out the fish or abandon the stage.
Unless the toe stage uses a hydraulically opened tool, the operator is required to run coiled tubing for the first stage to convey the perforating charge. In these cases, friction in a long lateral makes it difficult to push the BHA to sufficient depth, to begin treatment. The lower stages of the lateral are effectively lost, if the assembly does not reach the end of the well.
Also when using the PnP technique, each interval is over-displaced by the fluid used to pump the next stage of perforation guns and bridge plugs. As a result, near-well conductivity may be lost. Moreover, due to the order of operations, bridge plugs and charges are run into the well together. Plugs cannot be pressure-tested between stages, because wireline equipment is not rated to withstand high pressures. A recent study of fiber optic data from an Eagle Ford well found intra-stage communication in 71% of stages, due primarily to plug leakage.
Safety concerns. In the case where perforation charges do not detonate, additional time and safety risks are incurred. Perforation guns that do not detonate, as expected, cause a major safety issue. This is because they must be brought to the surface and diffused manually, and charges may fire unexpectedly, if there are problems with the wireline. In the U.S., from 2004 to 2014, 28 fatalities have resulted from oil and gas extraction fires or explosions.
Mill-out issues. Coiled tubing operations are required to mill out plugs at the end of a traditional PnP completion, as well as every time that a plug unintentionally pre-sets. Plug conveyance may be possible on long horizontal wells, but plug removal can be difficult. This is particularly an issue for wells with low reservoir pressure that equates to low annular velocity, making it difficult to flow plug parts back to the surface, which increases the risk of a stuck coil.
Unproductive clusters. Evenly distributing fluid and sand to each treatment zone is one of the major technical challenges of the PnP method, Fig. 1. Studies have shown that, on average, only 20% to 30% of perforation clusters contribute significantly to production. Another recent study concluded that increasing the number of perforation clusters in a stage does not increase the number of productive perforations.
Tracer diagnostics also validate the premise that the initial (heel-most) perforations in a cluster can erode quickly, due to the high-velocity flow of proppant slurry. As these perforations enlarge, the rest of the stage is not stimulated effectively. This correlates to subsequent production being lower than expected. To solve these issues, operators require a different approach.
DEVELOPING COMPLETION SOLUTIONS
Similar to how horizontal drilling and hydraulic fracturing were combined to access previously uneconomical unconventional reservoirs, combining the efficiency of ball-drop technology with the accuracy of fracture placement, in cemented liner completions, provides producers with a method that reduces completion time/costs, improves operational efficiency and increases production.
Limited-entry ball-drop evolution. Packers Plus introduced its first limited-entry ball-drop system in 2004. The initial tool design included a cutter assembly and multiple shear-activated stimulation jets. The actuation ball would land in the cutter assembly and then travel along the treatment zone, opening each jet along the way. The actuation ball would provide stage isolation inside the liner, while mechanical packers were used for annular isolation to segment the treatment zone. The system could be configured with multiple jets in-between each packer, or with one jet between each packer, creating multiple, individual entry points. The nozzles were designed to be adjusted and placed according to reservoir characteristics, thus enabling controlled injection of completion fluid along the entire length of each stage. The tool allowed operators to strategically place acid treatments for maximum benefit. The completion system was commissioned in several prolific carbonate formations.
As limited-entry ball-drop technology advanced, the cutter assembly was removed from the system, and the jet nozzles were activated directly, using an actuation ball pumped from the surface. Used for delivering both acid and proppant stimulation treatments, the versatility of limited-entry ball-drop completion technology was established. In spite of these advances, in this difficult economic environment, producers are continually seeking higher returns by applying new, updated completion technologies.
QuickFRAC cemented liner completion system. The company recently launched a pilot program in the southern U.S. to design and test a new multi-stage completion system called QuickFRAC (QF). The QF system aims to expand on the efficiencies created by ball-drop technology, when combined with the accuracy of limited-entry fracture placement in cemented liner completions, Fig. 2. The main focus of the new technology is to stimulate a high number of entry points in one treatment, remove the risk of wireline and coiled tubing runs, and eliminate the need to mill out tools/plugs prior to flow-back.
QF utilizes multiple sleeves during treatment and is triggered by using a single actuation ball. The entry point of each sleeve is reinforced to prevent erosion, and can be designed so that each sleeve has its own back-pressure. QF can be used to selectively stimulate the reservoir independently at each sleeve, providing multiple entry points in a stage. Using proprietary squeeze technology, the sleeves are designed to accommodate a high number of entry points in each stage. Additional efficiencies are realized by pairing the QF system with degradable ball technology. This enables operators to further reduce operational risk and eliminate mill-out requirements.
QuickPORT IV sleeve. A new QuickPORT IV sleeve (QP) is a simplified mechanical assembly with approximately 40% fewer components than earlier sleeve designs. The new QP sleeves are reinforced with tungsten carbide flow ports to prevent issues associated with perforation erosion, which helps facilitate fluid distribution to multiple entry points. Pumping rates can be achieved to place fractures in the proper predetermined positions to achieve optimal fracture length. In this design, stages are not over-displaced, increasing near-wellbore conductivity.
Premium liner hanger packer. The liner hanger packer uses premium sealing technology to pack-off the annulus and secure the completion liner in intermediate casing, Fig. 3. Along with conventional hanger slips, the new-style hanging system uses a seal and hold-down slips that can withstand differential pressures up to 10,000 psi. The tool’s capabilities include:
- A balanced piston prevents pre-setting during run-in
- The ability to rotate, push/pull without early release of the setting tool
- A bonded element design allows for higher circulation rates and liner run-in speeds without damaging the element
- It provides reaming capabilities by handling a high level of torque
- Built-in redundancies of a float nut and secondary release option ensure reliable operations.
Testable toe sleeve. The hydraulically activated initiation sleeve (Fig. 4) enables multiple pressure tests up to maximum casing pressure before opening the sleeve for stimulation. Capabilities include:
- Pressure testing independent of stimulation operations, without time constraints
- Full compliance with North American casing integrity test requirements
- A redundancy feature that ensures full sleeve opening
- Adjustable activation and opening shear
- Ports that provide a flow area greater than the liner.
Application engineering function. To ensure a system solution that is optimized for a specific job, an engineering team calculates pump rates, friction factors and pressure drop, in addition to torque and drag for each completion. The comprehensive analysis, combined with the team’s technical expertise, ensures a successful QF installation and effective reservoir stimulation.
The first QuickFRAC cemented completion system was installed as the first stage at the toe end in a 12,000-ft, MD, Mississippian well in Oklahoma. It also included five QuickPORT sleeves spaced approximately 45 ft apart, in addition to a hydraulically activated toe sleeve. The toe stage was activated for a diagnostic fracture injection test, two weeks before the rest of the wellbore was stimulated. Once pumping procedures were initiated, the five sleeves were opened with one degradable actuation ball followed by a slickwater treatment pumped at 100 bbl/min. The entire completion operation for the stage was finished in approximately 2 hr less than a typical completion using a PnP method. In addition to eliminating the need to run a perforating gun, the degradable ball technology reduced mill-out time prior to flow-back.
Case study 2. The second case study documents the benefits of a QF completion installed in the Meramec formation, in a cemented wellbore in central Oklahoma’s STACK play. The 12,000-ft, MD, well was equipped with a hydraulically activated toe sleeve and 15 QPs spaced approximately 50 ft apart at the toe end of the well.
Each of the five sleeves, in the three-stage operation, were opened with a single, degradable actuation ball, Fig. 5. The stimulation treatment was pumped, as planned, at a rate of 100 bbl/min., Fig. 6. The continuous pumping operation enabled the operator to transition between each stage in just 10 to 15 min., rather than incurring hours of non-productive time between stages, typical in a PnP completion.
INCREASING STIMULATION EFFICIENCY
A variety of completion techniques have been used to fracture horizontal wells. Plug-and-perf treatments have been applied for many decades, but these high-cost, time-consuming operations expose producers to undue risk and operational challenges. Limited-entry ball-drop completions have proven to be a cost-effective solution to stimulate horizontal wells and reduce risk.
The QuickFRAC system has been run in more than 100 wells in numerous unconventional reservoirs, and reduced completion time by improving operational efficiency, while eliminating the risk of CT and wireline service runs. The completion system also solves perforation erosion issues.
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