Adding a secondary barrier against gas migration in deepwater environments

Basil Joseph, Mark Knebel, Ammar Munshi and Chuck Pleasants

August 1, 2014

Secondary mechanical pressure barriers could help ease regulatory bodies’ concerns around effective zonal isolation in wells. 

The Cytadel ZX packer can be activated by dropping a magnetic signal carrier from the surface. A no-go signal can also be dropped to switch off the activation timer if needed. Images from Bakers Hughes. 

A good cement job is the primary barrier for effective zonal isolation in wells, and is the prevalent method to protect the wellbore from the unwanted and dangerous influxes of formation fluids, solids, and gases.

In deepwater wells, cement’s ability to reliably contain reservoir pressures is threatened by fluid losses to the formation during cementing operations that is impacted by higher pressures and temperatures, extended laterals, and unstable formations. An inferior or compromised cement job presents serious safety risks to the drilling rig, rig personnel, and the environment.

Enhanced reliability

Adding a secondary mechanical pressure barrier above the uppermost hydrocarbon zone will help increase reliability and safety, especially offshore. The additional barrier could prevent unintended and uncontrolled flow of reservoir fluids to the surface in the event of a compromised cement barrier, and help boost production rates, by eliminating flow that would otherwise be lost to the annulus.

Baker Hughes has developed an electronically actuated packer with industry-proven seal technology qualified to API 11D1 V0 acceptance criterion. The Cytadel ZX electronically-actuated packer is designed to provide a gas-tight annular seal for the life of the well—from wellbore construction through plug and abandonment operations. The system, which is typically installed as part of a long-string casing string, helps reduce HSE risks by curtailing issues associated with both annular casing pressure (ACP) and sustained casing pressure (SCP). ACP is the result of trapped fluid in or between the tubing and casing strings, which allows pressure to build as the fluid heats up during production operations. SCP is pressure that continues to build, even after being bled off at the surface. The packer’s V0-rated seal prevents pressure from traveling to upper casing strings, which provides an additional level of safety assurance, particularly for those wells where bleed-off at the wellhead is not possible.

Fundamental components

The packer system comprises three design features. First, it has a solid-body mandrel with no flow paths through the body, to maintain pressure integrity and eliminate the potential for hydrocarbon communication between the casing and annulus. This enhances system reliability and prevents inadvertent activation of the packer during the trip downhole or during cementing operations. The second design feature is a seal based on the Baker Hughes’ ZX technology. This zero extrusion gap seal has been V0-qualified up to 15,000 psi (1034 bar) differential at up to 400°F (204°C).

These seals have been employed on liner top packers for years to provide a pressure barrier above the liner hanger, with more than 40,000 runs to date and 99.5% reliability. The third feature is a modular electronic trigger mechanism, which is activated in one trip and eliminates the need for pressure or pipe manipulation to set the packer. The force required to set the packer is generated from either hydrostatic pressure in the wellbore, or from a pre-charged nitrogen spring contained within the packer.

The Cytadel ZX electronically-actuated packer is designed to provide a gas-tight annular seal for the life of the well—from wellbore construction through plug and abandonment operations. Image from Baker Hughes. 

Applications in shallow depths

This system is comprised of a surface-mounted acoustic signal generator and a downhole packer. It employs an acoustic trigger to set the packer. The signal generation system on the surface consists of an electronic unit that controls a pneumatic-hammer attached to the casing string. This system generates an acoustic pattern which travels along the casing until it reaches the electronic module within the downhole packer.

The electronic module incorporates accelerometers and a microprocessor, which together differentiate the incoming signal from any others that may be generated during normal operations. When the trigger signal is received, a valve opens and stored pressure energy is allowed to act against a piston, setting the packer seal in the casing. The electronics module is powered by a battery pack and is can operate in 35-300°F (2-149°C) temperatures. The electronics and battery technology in the shallow-set system have been optimized for temperatures down to 14°F (-10°C) on the rig floor.

In the event that the surface control unit becomes inoperable or some other condition arises that prevents the acoustic signal from being detected downhole, a contingency preprogrammed timer sequence may be used to set the packer.

Deeper well depths

The deep-set system employs a magnetic trigger to set the packer, comprising a surface-deployed special “follow” casing wiper plug (CWP) and a downhole annular casing packer. The setting sequence is activated by a magnetic field generated by the CWP as it traverses a multitude of Hall Effect sensors in the packer’s electronic module. The signature prevents inadvertent activation of the packer. After activation, the setting force is generated by well hydrostatic pressure acting upon atmospheric pistons mounted outside the mandrel.

The packer is similar in design to the one used in shallow-well applications, with the exception of hydrostatic setting pistons, replacing the compressed nitrogen module. After the onboard electronics receives confirmation of the correct magnetic signature, a trigger valve opens to allow hydrostatically charged well fluid into an atmospheric chamber to initiate the setting sequence. Using hydrostatic setting pistons is a field-proven alternative for greater well depth applications, where sufficient bottom-hole pressure is available to generate the required setting forces.

As with the shallow-well system, different triggering methods exist for the deeper well model:

Using the follow CWP that activates the setting sequence after a preprogrammed amount of time has elapsed to allow for completion of cementing operations.

Using a drop bar that employs the same magnetic signal carrier as employed on the follow CWP.

A contingency preprogrammed timer sequence allowing the packer to set if the follow CWP or drop bar is not detected.

The electronics module is powered by a battery pack with the same time limitations as the shallow-set tool battery. The deep well module can operate in two temperature ranges, 100-300°F (38-149°C) and 250-392°F (121-200°C). In higher temperature uses, a low-temperature battery initially powers the electronics at the surface, which becomes nonfunctional once its temperature threshold is reached downhole, before which a high-temperature lithium battery activates.

The packer seal used in both systems has the same proven, gas-tight, metal-backed, zero-extrusion gap design. The setting force drives the seal up a cone ramp, causing it to expand and conform to the casing internal diameter. The element’s external tooth profile eliminates any extrusion gap, trapping the setting force between the teeth and preventing cold flow of the elastomeric cover.

Field results

The annular casing packer can be deployed as a secondary pressure barrier for conventional and unconventional oil and gas wells, offshore and on. Its first field application was unique in terms of the size required: an 18-5/8in. long string packer that is set in 24in. casing. To date, three systems have been successfully installed in offshore Sakhalin Island, Russia, wells, the first at 150m (492ft) and the second at 370m (1200 ft). The operator performed a 10 bar (150 psi) backside pressure test on the first well, and a 15 bar (218 psi) test on the second well, for 30 minutes, to confirm the seal was successfully set. The operator continues to monitor pressure in the annulus of both wells, confirming that no buildup has occurred since system deployment. The first well is now on-line and producing 280MMscf/day. These wells were excellent candidates for field trials, as fluid loss to the formation during cementing operations is an on-going issue.

The company has also developed conventionally sized systems, including 5-1/2in. x 9-5/8in. and 9-7/8in. x 13-3/8in.

As government regulations and industry standards continue to evolve, a more intense focus will be placed on reducing annular flow prior to, during, and after completion of primary cement jobs. The long string completion systems that contain a secondary mechanical pressure barrier, i.e., annular casing packer, above the uppermost hydrocarbon zone should help to alleviate the concerns as outlined by BOEM/BSEE.





Basil Joseph
is an engineering manager for Wellbore Integrity at Baker Hughes. Joseph started his career in the in the automotive industry, simulating the macrodynamics of powertrain systems. He joined the oil and gas sector in 2006 as a project engineer. He holds a MSME [Master of Science in Mechanical engineering] from Michigan State University. 




Mark
Knebel is the product line manager of Wellbore Integrity and Specialty Products at Baker Hughes. He is responsible for the marketing and new product development of technologies for annular isolation, multilaterals, and solid expandables. He has had a 30 year career at Baker Hughes and earned a degree in Mechanical Engineering from Texas A&M University. 

 




Ammar
Munshi is a design engineer for Baker Hughes. He works in new product development within the completions and production product lines, and has been at the company for six years. Munshi trained and led the operations team in Sakhalin for the first successful field trial of the Cytadel ZX packer. He gradu- ated from Texas A&M University with a Mechanical Engineering degree.

 




Chuck
Pleasants is technology director for the Baker Hughes’ Wellbore Construction product line. He has held various manage- ment roles over his 16 year career at the company, including technology manager for the Wellbore Intervention product line and manager of the Packer Customer Product Development group. Pleasants has 36 years’ oil and gas industry experience. He holds a BSME degree from Texas A&M University Kingsville. He serves on the SPE 19LH task force to develop a liner hanger industry standard.