By combining RFID technology with premium packer performance and exceptional safety valve reliability, gas-lift wells can be operated with the highest safety standards for the life of the well, in the latest advancements in Annular Safety Valves (ASVs).
DANILO IGLESIAS, CHRISTOPHER MUNRO and VIRGILIO PORTO, Weatherford
Identifying possible ways to reduce time and costs is a constant in every oil and gas operation. New technologies and methodologies are created, tested and adopted to reduce risk, improve rig time and limit nonproductive time (NPT) and, when traditional tools no longer are sufficient, new technologies are invented.
Annular safety valves (ASV) are one such innovative technology. They are used in completion strings and isolate gas in the lower annulus. Comprising a (top-to-bottom) setting module, control line splice subs, production packer, annulus mounted flapper safety valve and secondary control line splice sub, the full system delivers. ASVs protect personnel and equipment on the surface from unplanned gas release in the same manner that downhole safety valves do in the tubing.
Reliability is a key factor when considering ASVs, and they must be able to withstand high axial loading of the casing, Fig. 1. The maximum setting depth is typically 2,000 ft (609 m), but, with adjustment to the spring design, deeper installations are possible. In the event of a catastrophic scenario, ASVs have to be able to maintain the gas barrier, as well as withstand the parting load of a tubing string above.
THE THREE CONVENTIONAL SETTING OPTIONS
When it comes to setting an ASV, three conventional methods exist: dedicated setting line to the surface, applied tubing pressure or a mechanically shifted sleeve, Fig. 2.
The oldest method is the simplest: an operator runs a dedicated control line through the tubing hanger to the setting port on the ASV. Pressure is applied down the control line and sets the ASV packer. As there is no dedicated setting module, overall length is reduced; however, it does mean an additional penetration of the tubing hanger is required.
The applied tubing pressure method eliminates the dedicated setting line to the surface. Instead, operators configure the ASV to have direct communication from the tubing to the setting chamber, pinning the ASV to a pre-determined start to set the pressure. In this case, the ASV is set by applying tubing pressure. Like the dedicated line option, this method is interventionless, and the overall assembly length can be shortened. Yet, hazards still exist. The ASV’s setting chamber is sensitive to tubing pressure, and the ASV will set before other barriers have been tested. If operators find a problem with the barrier test, both the ASV and the production packer must be released prior to pulling the completion. The time and effort required to perform both actions increases significantly.
The final conventional approach to setting an ASV is the mechanical sliding sleeve. Here, the sleeve isolates the setting chamber until the completion has landed at the designated location. After testing of the packer and tubing are conducted, and the wireline is readied, a standard shifting tool opens the sleeve in the ASV. Communication is established to the setting chamber via a control line, connecting the setting sub and the packer. The best aspect of this option is that the setting chamber is isolated and protected from tubing pressure until shifted open. The downside is that intervention is necessary, and operators must incur the associated costs of housing a wireline crew until the usual rig-up time. Another disadvantage stems from the drill pipe ID, which is too small to enable a shifting tool to be run, thus requiring a workover riser.
PRESSURE-PULSE-ACTIVATED TECHNOLOGY DELIVERS A NEW METHOD
The pressure-pulse-activated communication sub combines the best of the conventional options while mitigating their challenges. Like the mechanical shifting sleeve, when the pressure-pulse-activated (PPA) hydraulic communication sub is closed, it is isolated from the tubing pressure. An operator establishes a closed system in one of three ways: a plug in the tailpipe of the upper completion, a plug in the lower completion or a remote-activated barrier valve.
When it is time to shift the sub open, field personnel send frequency-modulated pressure cycles via radio-frequency-identification (RFID) tags. These cycles establish the proper rate of change at the precise time, eliminating the requirement to reach certain pressure profiles within a well and, more importantly, making the activation of the sub independent from every other hydraulic tool in the wellbore. This method also adds a degree of flexibility, enabling an operator to run multiple tools into the well and coordinate activation to different timing profiles.
Operators can choose between two designs to operate the remotely activated PPA sub: single shot or multi-cycle. The single-shot option features an antenna, an electronics component, a poppet valve and a sleeve. The antenna and electronics wirelessly establish communication on the surface during the setup and test phase, and, when downhole, they wait for the correct pressure pulse sequence to trigger the poppet valve. This action enables the sleeve to open, exposing the ASV setting chamber to tubing pressure via a control line from the packer setting chamber to the sub.
The single-shot method presents some significant advantages. Operators can test the completion to full pressure, prior to setting the ASV packer. There is an option to activate, using a timer on the tool to shift the sleeve. Like the conventional options, no dedicated setting line to the surface is required, and activation is interventionless. Also, should circumstances dictate, a mechanical override exists to shift open the sleeve, using a wireline shifting tool.
CHALLENGES WITH SUBSEA APPLICATIONS
No matter which conventional method an operator chooses, the challenges associated with subsea bring additional risks not encountered with land-based or fixed platforms. When using a dedicated setting line in a subsea environment, field personnel cannot pressure-test the terminations, due to the risk of setting the ASV. Additionally, operators must incur the increased risk of well fluid ingress into the control line and up through the tubing hanger to the rig floor or seabed. The high cost of NPT—whether to rig up a wireline unit or troubleshoot an issue—gives many offshore operators pause. Yet when the new pressure pulse-activated communication sub is evaluated in the context of subsea operations, the advantages of the technology can contribute significantly to lowering well costs and risks.
Additionally, the ASV flapper design is based on Weatherford’s existing tubing-retrievable safety valve—providing years of reliability and performance to ensure a robust barrier, whether in the annulus or tubing. Having a flapper design, compared to a sleeve or poppet, offers advantages in terms of debris tolerance, gas flow area and, most importantly, reliability in shutting-in an unplanned gas release immediately, Fig. 3. Further benefits are available, particularly in subsea wells, through the ability to shut in gas below the ASV during any routine pressure tests at the subsea tree or FPSO, minimizing production downtime.
CASE STUDIES
The following two case studies demonstrate the flexibility and operational optimization available with an ASV system.
Case study #1: Norway. An operator on the Norwegian Continental Shelf chose to install a pressure pulse-activated ASV in a new oil producer. The water depth from the semisubmersible rig was approximately 1,148 ft (350 m). The upper completion consisted of a stinger assembly, a production packer, a gas-lift mandrel, a gauge carrier, the ASV and a downhole safety valve. The 5 ½-in tubing ran from the muleshoe to the 9 ⅝ x 5 ½-in ASV. The installation depth of the ASV was 1,680 ft (512 m). From there, 7-in tubing was run to the tubing hanger.
The lower completion included 5 ½-in inflow control device (ICD) sand screens, swellable packers, a disappearing plug and a screen hanger. The disappearing plug had a conventional ratcheting mechanism that was set up to react to pressure pulses and relied on specific pressure thresholds to activate. The operator customized the system with a predetermined number of cycles before activation. To prevent interference with the disappearing plug, the pressure cycles for the ASV were programmed at a lower pressure threshold.
During the extensive collaboration, the two engineering teams developed a plan for the duration of the pressure-pulse sequence, but the operator requested a change. The offshore crew reprogrammed the ASV to activate via a shorter sequence, with the idea of reducing the time required to send a pulse. Reprogramming an ASV is a simple, routine operation accomplished wirelessly, merely by inserting a probe into the ID of the tool and then connecting wirelessly to a laptop. This same configuration powers up the ASV and enables field personnel to perform function tests before being tripped into the wellbore.
Field personnel landed the completion via drill pipe, set the production packer and performed a pressure test of the production packer, to verify the gas-lift valve and tubing integrity. The downhole safety valve was closed, and a successful inflow test was performed to establish a baseline and reset the ASV. With the baseline pressure at a stable 400 psi for 10 min., a pressure pulse was sent from the cement unit, easily achieving sufficient pressure buildup and bleed-off rate. Twenty-seven minutes after the first pressure buildup, the electronics in the ASV triggered the poppet valve, and the sleeve opened. Additional pressure was applied to the string, and the ASV was set successfully. After another successful inflow test of the ASV, the well was transitioned to the production team.
Case study #2: Azerbaijan. Building on the success in the North Sea, an operator with a well in the Caspian Sea chose to deploy the ASV. The operator needed a system that not only could deliver operational simplicity and flexibility but could also provide wellbore integrity. The objectives included the installation of an upper completion system in conjunction with a downhole pressure gauge, a subsurface safety valve, and an ASV. Ideally, any proposed solution should reduce costs and time by eliminating the requirement for wireline and the associated pressure control equipment setup. A high level of safety for field personnel was essential, as well as guaranteeing well integrity during gas-lift operations and reducing overall rig time.
The operator was especially interested in the gas-lift aspect of the ASV, which allows safe gas-lift operations with a system that is fully tested during the installation and could be further tested before, during or after any gas-lift operations.
Field personnel ran the completion to the setting depth and pressure-tested the completion string without setting the ASV packer. Applied pressure pulses were sent to the tubing, to remotely open the ASV packer setting chamber at 5,000 psi (34.4 MPa), Fig. 4. After a successful in-flow test of the packer with 1,700 psi (11.7 MPa), the well was handed over to production.
The streamlined operation reduced rig time by approximately 36 hrs per completion. The optimized completion design reduced the number of specialized personnel needed for the installation and setting of the upper completion. The ASV chassis enabled multiple control lines’ feedthrough to accommodate several essential completion systems, including tubing-retrievable subsurface safety valves, downhole pressure gauges and distributed temperature sensing equipment. The simple and efficient operational procedures allow a high volume of installations, and the system is fully recoverable in its entirety for any workover operations.
CONCLUSION
Inclusion of an ASV system in a gas-lift well, whether through design choice or regulatory compliance, offers many benefits to the operator. By combining RFID technology with premium packer performance and exceptional safety valve reliability, gas-lift wells can be operated with the highest safety standards for the life of the well. WO
DANILO IGLESIAS is the Global Product Line manager for completions at Weatherford. Over the last 20 years, Mr. Iglesias has held several positions within the oil and gas industry—from field operations and business management to sales and strategic roles—though he has always focused on completions. For the past four years at Weatherford, he has overseen portfolio management and completions business development.
CHRISTOPHER MUNRO is the Global Product Line champion for core completions at Weatherford. For the past 10 years at Weatherford, he’s been part of the global completions team, focusing on RFID technology, annular safety valve and isolation ball valve implementation and deployment, and portfolio management around the world.
VIRGILIO PORTO is the vice president of Completions at WFRD, where he leads the strategic development and execution of completion solutions. With over 20 years of experience in the industry, Mr. Porto has a proven track record of driving innovation and operational excellence in the well completions space.