perforated pup joint function free sample

We are Supplier and Exporter of Perforated Pup Joints in UAE. It is usually installed between the bottom of two nipples of a completion. It allows unrestricted fluid or gas flow, which increases the accuracy and reliability of acquired downhole production data.

We supply all sizes, grades, and thread profiles to meet custom requirements. The perforated pup joints are sometimes also known as the perforated production tube. All our products have passed the ISO certification and API certifications. Our products are tested numerous times under technical guidance and are made from the best quality material.

In wells flowing large volumes, a restriction in the tubing such as a gauge hanger, could cause false pressure readings. Vibrations due to flow could also cause extensive damage to delicate gauges, therefore a perforated pup joint (approx. 10ft length) set above the bomb hanger nipple would allow flow to pass unrestricted over the gauges and hanger, thus giving a more accurate pressure/temperature recording within the

In most completions, the length of tubing available at surface is not enough for proper wellhead installation and operation. Pup joints and varying lengths of tubing are used to adjust the production string length as close as possible to the desired value. Then, the adjustable union or joint is installed, rotationally adjusted, and locked to the desired makeup length. In dual completions, the tool can be used to adjust the length of the short string.

The adjustable, telescoping action of the union or joint allows it to be set and locked at any desired position within its adjustment length while maintaining pressure integrity in the tubing string. Once the tool is in place, the desired amount of tension, weight, and rotational torque can be applied through it to the tubing.

Flow iron pup joints from Cameron deliver maximum total life cycle cost savings, even in the oil and gas industry’s most demanding applications. For all of your flow iron requirements, from high-stage-count hydraulic fracturing to cementing, well testing, and even abrasive flowback, you can count on Cameron for high reliability and low cost.

These J55, L80, N80Q & P110 pup joints are manufactured from seamless Grade J-55, L80 N80Q and P110 mechanical tubing. The API 5CT tubing pup joint is mainly used to adjust the height of the tubing strings. It is also used to adjust the depth of down-hole tools.

The rig assist unit was installed on top of the rig’s Bops. A landing joint was lowered into the stack and screwed into the tubing hanger. The snubbing Bops were tested using the rig pump to 35mpa

Once the BHA was at surface, the last joint of 73mm tubing with the Fill/Flow sub below it was stopped in the stack. This placed the 3m pup joint below the fill/flow sub across the lower stripping rams

Note that the inside of this last joint was pressurized because of the holes in the fill/flow sub. The plug in the “F” profile on top of the joint was controlling the well pressure from flowing out the tubing

The lower stripping rams were closed and the stack bled off above the rams The pressure inside the joint also vented during this procedure. The firing head of the perforating gun was sealed and now controlled the ID side of the string

The joint was gently snubbed up until the fill/flow sub was above the snubbing unit annular element. The operator continued to raise the tubing until the lower connection of the 3m pup joint engaged the bottom side of the stripping rams. The rams were locked and the chamber between the stripping rams and annular was re-equalized

Figure 7. Example of variable choke valve with a unibolt (or wellhead) design. To help  illustrate the flow path and quality of the steel, a section of the device has been removed. If you look closely, you can see where the two union joint halves meet; it contains a seal ring like the ones you would see on a wellhead section, and/or a Christmas tree. This allows the seal to withstand high pressures of up to several thousand pounds.(Cooper Cameron Valves)

n: 1. a material used in a cylinder on rotating shafts of an engine or pump in the stuffing box of a valve, or between flange joints to maintain a leak proof seal. 2. the specially fabricated filling in packed fractionation columns and absorbers.

n: 1. a well completion method in which the producing zone or zones are cased through, cemented, and perforated to allow fluid flow into the wellbore. 2. a well completed by this method.

n: a special type of nuclear log that measures the depth of each casing collar. Knowing the depth of the collars makes it easy to determine the exact depth of the formation to be perforated by correlating casing-collar depth with formation depth.

v: 1. to use the drawworks to lift the bit (or other tool) off bottom by raising the drill stem. 2. to use an air hoist to lift a tool, a joint of drill pipe, or other piece of equipment.

-Flow commingled at maximum practical rate and run PLT to determine the contribution of the second perforated interval, the origin of the water, and flowing and static pressures.

18.Close the No. 2 Pipe Rams around the Slick Joint below the SSTT and with the tubing open, pressure test the annulus to 13.8 MPa (2,000 psi). Bleed the annulus pressure back to 1500 psi and monitor the pressure continuously during testing. Note that the Omni valve will cycle to position No. 7, well test position.

2.Rig up to cement and pump a cement volume sufficient to cover the perforated interval to 50 metres above the top packer (50 sacks of cement). Displace the cement as a balanced plug and pull the tubing to well above the calculated cement top, close rams and reverse out the tubing volume. Squeeze away a maximum of 0.1 m3 (0.6 bbl). Circulate and work pipe.

1.Apply 2,000 psi to Annulus to open PCT. Monitor annulus pressure over 15 minutes to test pipe rams around SSTT slick joint. Cycle PCT to "lock open" position by pressuring up ad releasing pressure in the annulus.

l)Apply 2,000 psi to Annulus to open PCT. Monitor annulus pressure over 15 minutes to test pipe rams around SSTT slick Joint. Cycle PCT to "lock open" position by pressuring up and releasing pressure in the annulus.

The second function of the Tool is to provide a repeatable bypass while entering or pulling a seal assembly through the packer seal bore. This feature also allows a Pressure Test to be made against the PCT once landed out in the wellhead and packer with no risk of applied pressure activating TCP guns prematurely.

•The BOPs will remain in place. With the string landed off, a slick joint (incorporates controlline and prevents it from being crushed by the rams) will be located opposite the pipe rams and a shearable joint opposite the shear rams.

16.Continue running the tubing as per diagram until the bottom of the locator seal assembly is 2 m above the packer. This results in the long flow riser joint sticking up ca. 2 m above the rotary table.

•Upper slick joint: with the string landed, the upper slick joint is located opposite the 5" #3 pipe rams (a 31/2" pup joint is then be located opposite the #2 shear rams).

17.Make up the test tree with the two riser joints to the string. (Top of test tree ca. 10 m above derrick floor). Tree to be hung off in slings to avoid buckling the shear joint. Rig up kill and flow lines flexible hoses.

Pick up string until lower slick joint is located opposite 5" #3 pipe rams. Close pipe rams on lower slick joint. Circulate well over the choke until no hydrocarbons are returned.

The Drilling Supervisor is in overall charge and coordinates and monitors the operations and should keep himself fully informed of the progress of the test at all times. He must be advised by the Wellsite Operations Engineer (WSOE) before the well is perforated and by the Well Services Supervisor (WSS) before the well is opened up and at any time a potentially hazardous situation may occur. He in turn will inform the WSOE and WSS of any activity or occurrence which could affect the production operations.

Should circumstances arise which may require a deviation from the test programme, the DS and WSOE will advise Base. The Rig Superintendent, Operations Engineer and Completions Supervisor will discuss the problem and jointly agree on the necessary remedial action. On no occasion may rig personnel deviate from the programme unless an emergency arises or prior agreement from base has been obtained in the manner described above.

In one embodiment of the present invention, a packer is located below the submersible pump. The packer may be a straddle type packer, wherein the straddle packer has a pup joint in between that allows fluid from the outside to enter the pup joint. The pup joint that allows fluid from the outside to enter the pup joint may be a perforated or slotted pup joint situated in between the straddle packer.

An alternate apparatus of the present invention may have one packer and further comprise a pup joint that allows fluid from the outside to enter the pup joint and a swab cup or flow restrictor assembly below the pup joint.

The apparatus has at least one sensor located inside the joint below the packer or located inside the joint above the pup joint in between the straddle packer that allows fluid to enter. The sensors are selected from a group of sensors that measure pressure, temperature, flowrate, spectroscopy, viscosity, H2S concentration, CO2 concentration, bubble count, a dielectric property, gas/oil ratio, water/gas ratio, water/oil ratio and gamma ray radiation.

FIG. 3 depicts an exemplary embodiment of the present invention, wherein an example of a coiled tubing bottomhole assembly for the current invention is shown. The bottomhole assembly is lowered into the wellbore and positioned in place in front of the formation to be studied by coiled tubing 30. The submersible pump cable 31 is lowered along with the coiled tubing 30 to provide power to the submersible pump 32 and to allow communication between the sensors housed in the bottomhole assembly and the surface processing unit. The sensors may be housed above, below or in the submersible pump. In the example shown in FIG. 3, the sensors 38 are housed in a pup joint above the joint 35 that is designed to allow fluid to enter the system. Joint 35 is designed to allow fluid to enter the system and it is often called a perforated or slotted pup joint. In the present example embodiment shown in FIG. 3, a safety valve 33 is deployed below the pump, the safety valve can be closed if needed to restrict fluid from entering the coiled tubing. This is a common safety practice within the industry. Below the safety valve 33, an emergency release sub 39 is depicted. A shear activated release sub is commonly used. Its function is to release the assembly situated above the emergency release sub 39, should the operation need to do so (for example a stuck packer 34), from the assembly situated below the emergency release sub 39 hence freeing the coiled tubing 30 to be retrieved to surface. Also shown in FIG. 3 is a packer 34 to isolate the open formation 36 to be tested, the packer 34 can be replaced by a swab cup or seal cup assembly. Below packer 34 are a series of joints, the number and length of joints will depend on the length of the open formation to be tested plus a predetermined extra length of joints to provide a safety margin. Among these joints is a joint that allows fluid to enter the bottomhole assembly. To straddle the formation 36 to be tested, a swab cup or seal cup assembly 37, as shown in FIG. 3, can be used; alternatively a second packer (i.e. a straddle packer, not shown) can be used replacing the shown swab cup assembly.

A person of ordinary skill in the art will recognize the use and functionality of surface pressure control equipment as a device or group of devices designed to contain fluid under pressure inside a wellbore while related equipment is moved in or out of the wellbore. Accordingly a person of ordinary skill in the art will recognize the use and functionality of a coiled tubing safety valve and a emergency release sub. The first is a device to restrict fluid from entering the coiled tubing and the second device is used to release the assembly situated above the emergency release sub should the operation need to do so from the assembly situated below the emergency release sub.

While the invention is described through the above exemplary embodiments, it will be understood by those of ordinary skill in the art that modification to and variation of the illustrated embodiments may be made without departing from the inventive concepts herein disclosed. It would be possible, for instance, to use a battery operated pump and a wireless communication system to start the test; a fluid sample chamber may be lowered into the wellbore; seal cups or swab cup assemblies can be used instead of packer or straddle packer; the position of the sensors, emergency release sub, packers, pup joints, safety valves, etc can vary in it relative position to each other and the amount thereof used in the string as described in the above exemplary embodiments. Accordingly, the invention should not be viewed as limited except by the scope of the appended claims.

Perforated Production Tubes are joints of tubing with machined holes along four lines 90o apart along the length of the tube. Perforated Production Tubes are usually installed between the bottom two nipples of a completion. With this tool, downhole recording devices, such as temperature and pressure gauges, can be installed in the lower nipple profile to acquire flowing pressure and temperature measurements. The upper nipple provides a point to plug the tubing below a packer. This facilitates packer setting or workover operations. The Perforated Production Tube, sometimes called a Ported or Perforated Pup Joint, allows for unrestricted flow of fluid or gas. The use of this tool enhances the accuracy and reliability of acquired downhole production data, which otherwise would be distorted due to flow restrictions. The Perforated Production Tube comes standard with 200% flow area of the production string it is connected to.