PosiTest Retrievable Packer
The PosiTest retrievable compression packer is a fullbore, cased-hole, retrievable compression-set packer with a large internal bypass. The packer is designed to withstand high flow rates, elevated temperatures, and high pressures when the appropriate amount of weight is applied to the packer. The sealing elements effectively isolate annulus fluids from the perforated interval.
PosiTest Long-Stroke Packer
The PosiTest long-stroke packer is similar to the standard PosiTest retrievable compression packer except that it is set by string reciprocation instead of string rotation. The long-stroke packer can be easily redressed between operations or converted quickly to run in another casing weight.
Hydraulic Hold-Down
The hydraulic hold-down complements both the PosiTest retrievable compression packer and the PosiTest long-stroke packer. It prevents upward movement as a result of hydraulic forces acting below the packer during stimulation or when a firing head is being activated. This combination functions similarly to the PosiTrieve downhole packer with hold-down section; all hydraulic hold-down modules can be used with the PosiTest long-stroke packer.
Applications
The PosiTest packer has two applications:
- Drillstem testing
- Tubing-conveyed perforating
PCT Pressure Controlled Tester Valve
The PCT Pressure Controlled Tester valve, operated by annulus pressure, is the downhole valve used to control formation flows and shut-ins for applications that do not use the IRIS Intelligent Remote Implementation System. The PCT valve must be run in conjunction with either the hydrostatic reference tool or the PORT Pressure Operated Reference Tool, either of which traps a reference pressure inside the PCT valve.
The two distinct sections of the PCT valve are the ball valve seal section and the hydromechanical operator section.
The versatility of the PCT valve can be enhanced by installing a hold-open (HOOP) module that holds the ball open when the annulus pressure is bled off. The HOOP module allows wireline to be run through the ball or circulation through the ball valve when the packer is not set.
Operating pressures for the PCT valve vary with depth but are usually between 6.95 and 10.34 kPa [1,000 and 1,500 psi] applied annulus pressure.
The two distinct sections of the PCT valve are the ball valve seal section and the hydromechanical operator section.
The versatility of the PCT valve can be enhanced by installing a hold-open (HOOP) module that holds the ball open when the annulus pressure is bled off. The HOOP module allows wireline to be run through the ball or circulation through the ball valve when the packer is not set.
Operating pressures for the PCT valve vary with depth but are usually between 6.95 and 10.34 kPa [1,000 and 1,500 psi] applied annulus pressure.
Pump-Through Flapper Safety Valve
The pump-through flapper safety valve (PFSV) provides a reliable means for obtaining downhole shut-in and minimizing wellbore storage during final pressure buildup. It also has the ability to pump into the formation, irrespective of tubing or annulus pressure integrity above the valve.
The PFSV is a fully opening downhole safety valve. It is open when run in the hole and closed permanently when annulus pressure rises above the rupture disk rating. The operator mandrel is biased to internal pressure and locked in the open position to prevent premature closure. Upon bursting the rupture disk, hydrostatic pressure is applied to the operator mandrel, which moves up against an atmospheric chamber, uncovering the spring-loaded flapper. Pumping down the tubing lifts the flapper off its seat and permits killing the well.
The PFSV is a fully opening downhole safety valve. It is open when run in the hole and closed permanently when annulus pressure rises above the rupture disk rating. The operator mandrel is biased to internal pressure and locked in the open position to prevent premature closure. Upon bursting the rupture disk, hydrostatic pressure is applied to the operator mandrel, which moves up against an atmospheric chamber, uncovering the spring-loaded flapper. Pumping down the tubing lifts the flapper off its seat and permits killing the well.
Safety Joint
The safety joint (SJB) allows quick release of the test string if the string below the packer becomes stuck. The tool has a coarse thread to carry the string load and allow easy disengagement and re-engagement. The SJB is typically positioned on top of the packer and made up to the same torque as the other tools in the string. It is disengaged by left-hand torque. The shear pins in the tool maintain a consistent breakout torque regardless of wear and tear on the tool. The breakout torque is controlled to 950 ft.lbf by a shear pin. An adjusting ring keeps the right-hand torque from acting on the shear pin. The joint can be engaged by applying weight and rotating it slowly to the right. After disengagement, the retrieved pin is easily screwed back into a downhole box section with a suitable fishing assembly for retrieval of the stuck stringSCAR Inline Independent Reservoir Fluid Sampling
SCAR inline independent reservoir fluid sampling delivers contaminant-free fluid samples from deep within the formation. SCAR sampling is a complete approach, engineered to capture reservoir fluid samples more safely and reliably.
Eliminate sample contamination
SCAR sampling captures fluid samples individually or sequentially, directly within the flow stream. This collection method eliminates the possibility of contaminants and junk in each sample caused by dead volumes.
More reliable, safer sampling
Single large nitrogen charges can compromise the safety of operations and the integrity of every sample. SCAR samplers have small, independent gas charges to ensure each individual sample remains at or above reservoir pressure. Non-reactive sample chambers also ensure trace elements are retained.
Faster wellsite handling
To meet your specific test requirements, the SCAR system offers a broad range of sizes, ratings, and activation options. Its shorter length allows faster handling at the well site.
Single-Ball Safety Valve
The single-ball safety valve (SBSV) is a fully open downhole safety valve that is run in the open position and closes permanently when the disk is ruptured. The operator mandrel is balanced to internal pressure, and is locked in the open position to prevent premature closure.
Upon rupturing the disk, hydrostatic pressure is applied to the operator mandrel, which closes the valve.
The combination of the large differential pressure (hydrostatic to atmospheric) and the 21-cm2 [3 3/4-in2] operator mandrel area yields more than enough force to cut 5.6-mm [7/32-in] wireline cable, even in shallow wells. The operator mandrel locks in the closed position and prevents the tool from reopening until it is retrieved at the surface. The lock can be reset without disassembling the tool, which enables functional testing before running in the hole.
Kits are available to convert the SBSV to a pump-through safety valve (PTSV) or a pipe tester valve (PTV).
Upon rupturing the disk, hydrostatic pressure is applied to the operator mandrel, which closes the valve.
The combination of the large differential pressure (hydrostatic to atmospheric) and the 21-cm2 [3 3/4-in2] operator mandrel area yields more than enough force to cut 5.6-mm [7/32-in] wireline cable, even in shallow wells. The operator mandrel locks in the closed position and prevents the tool from reopening until it is retrieved at the surface. The lock can be reset without disassembling the tool, which enables functional testing before running in the hole.
Kits are available to convert the SBSV to a pump-through safety valve (PTSV) or a pipe tester valve (PTV).
Single-Shot Reversing Valve
The single-shot reversing valve (SHRV) operates by applying annulus pressure to burst a rupture disk. Once actuated, the reversing ports are locked open. The SHRV is typically opened at the completion of the drillstem test (DST) to reverse out fluids produced during the test.
A ratchet keeps the valve in the closed position until the disc is ruptured. When the rupture disk bursts, hydrostatic pressure is applied to the operator mandrel, moving it up against the atmospheric-pressured chamber. This results in uncovering eight large circulating ports for efficient well-killing operations. Once annulus pressure pushes the mandrel up, the same ratchet locks the mandrel in place to keep the tool open. The SHRV-H is part of the 88.9-mm [3.5-in] large-bore IRIS Intelligent Remote Implementation System.
The SHRV-J is part of the ultrahighpressure J-string developed for use in wells with bottomhole temperatures greater than 218 degC [425 degF]. New seal technology has enabled successful qualification testing of the J-string tools up to 260 degC [500 degF] at the maximum rated pressure.
A ratchet keeps the valve in the closed position until the disc is ruptured. When the rupture disk bursts, hydrostatic pressure is applied to the operator mandrel, moving it up against the atmospheric-pressured chamber. This results in uncovering eight large circulating ports for efficient well-killing operations. Once annulus pressure pushes the mandrel up, the same ratchet locks the mandrel in place to keep the tool open. The SHRV-H is part of the 88.9-mm [3.5-in] large-bore IRIS Intelligent Remote Implementation System.
The SHRV-J is part of the ultrahighpressure J-string developed for use in wells with bottomhole temperatures greater than 218 degC [425 degF]. New seal technology has enabled successful qualification testing of the J-string tools up to 260 degC [500 degF] at the maximum rated pressure.
Slip Joint
The slip joint (SLPJ) is an expansion/contraction compensating tool. It accommodates any changes in string length caused by temperature and pressure during a drillstem test.
The SLPJ has two distinct parts: an outer housing and a moving inner mandrel. Its rugged design incorporates three main sections. At the top is a splined moving mandrel that allows torque to be transmitted through the tool. Below this are two pressure chambers, one open to tubing pressure and the other open to annulus pressure. The tool is hydraulically balanced and insensitive to applied tubing pressures. The dynamic seals in the balance chambers are dependable chevron V-seals.
Testing SLPJs have a stroke of 5 ft; the total number of SLPJs required depends on well conditions and the type of operation. For a standard test at 10,000 ft, the use of three SLPJs is normal. For tests for which injection or stimulation is planned, the associated cooling can cause a large amount of string contraction, and four or five SLPJs may be required to compensate for string movement during operations.
A special clamp securely joining the mandrel and the housing of the SLPJ is added for safety considerations for when the tool is handled at the surface.
SLPJs make it easier to space out the tubing-conveyed perforating guns when testing is done from a semisubmersible.
The SLPJ has two distinct parts: an outer housing and a moving inner mandrel. Its rugged design incorporates three main sections. At the top is a splined moving mandrel that allows torque to be transmitted through the tool. Below this are two pressure chambers, one open to tubing pressure and the other open to annulus pressure. The tool is hydraulically balanced and insensitive to applied tubing pressures. The dynamic seals in the balance chambers are dependable chevron V-seals.
Testing SLPJs have a stroke of 5 ft; the total number of SLPJs required depends on well conditions and the type of operation. For a standard test at 10,000 ft, the use of three SLPJs is normal. For tests for which injection or stimulation is planned, the associated cooling can cause a large amount of string contraction, and four or five SLPJs may be required to compensate for string movement during operations.
A special clamp securely joining the mandrel and the housing of the SLPJ is added for safety considerations for when the tool is handled at the surface.
SLPJs make it easier to space out the tubing-conveyed perforating guns when testing is done from a semisubmersible.
Tubing-Fill Test Valve
The tubing-fill test valve (TFTV) enables filling and testing of the tubing while running in the hole.
As the string is lowered into the hole, fluid enters the tubing through the TFTV bypass ports. The fluid creates a differential pressure that causes the flapper to open and then fills the tubing.
The tubing can be tested at any depth by pressuring-up on the tubing string against the flapper valve. When the test string is at depth, annulus pressure is applied to rupture a disk, causing the flapper to lock fully open. Once the flapper is open, the tool has fullbore access.
As the string is lowered into the hole, fluid enters the tubing through the TFTV bypass ports. The fluid creates a differential pressure that causes the flapper to open and then fills the tubing.
The tubing can be tested at any depth by pressuring-up on the tubing string against the flapper valve. When the test string is at depth, annulus pressure is applied to rupture a disk, causing the flapper to lock fully open. Once the flapper is open, the tool has fullbore access.
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