pup joint schlumberger free sample

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.

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Expansion joints are used to compensate for tubing movement that occurs due to changes in temperature, pressure, or both during normal well operations after the packer has been set. The joints maintain the pressure integrity of the tubing while allowing the string to safely expand and contract. We offer you a range of products with multiple stroke lengths for single- and dual-string completions, standard conditions, H2S and CO2 service, and temperatures higher than 300 degF [149 degC]. The stroke length is selected by calculating the change in tubing length based on the maximum temperature differential expected.

Expansion joints are also available for applications where an extreme change of length is expected in the production tubing or where a tubing separation device is required to enable tubing retrieval without removing the packer. Alternatively, a polished bore receptacle (PBR) and seal assembly can be used. Before separation of the joint, a blanking plug may be installed to block the flow from the formation. Specialized retrieving heads are available for retrieving the expansion joints and the tools connected below them. A special tool enables retrieval of the PBR and attached packer stinger after the tubing string and PBR seal assembly have been removed from the well.

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.

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.

As an example, it is necessary to perform a wet connect operation in some completions. Such an operation connects a cable or control line (e.g., fiber optic, electrical, hydraulic) contained in an upper string to a cable of same type contained in a lower string that is already part of the permanent completion in the well. Completing the wet connect requires weight to be set down onto the upper string to ensure that the connection is properly made. Likewise, the production string, or final string, that is left in the hole contains pup joints and a tubing hanger. It is necessary to have the right amount of pipe between the tubing hanger and the wet connect so that the appropriate set-down weight can be applied to make up the wet connection with the tubing hanger landed onto the wellhead.

Obtaining the proper space-out is often not difficult when the wellhead lies only a few hundred feet below the rig floor. In such cases, using the wet connect example for illustration purposes, a service string with the wet connect at its lowest point is lowered into the well in a first run into the well, and the wet connection is made with the appropriate set-down weight. With the wet connection completed, the pipe is marked on the rig floor and the service string is pulled from the well. The marking on the pipe enables space-out calculations and some sections of the service string can be replaced with pup joints and the tubing hanger assembly as appropriate. The modified production string is run in the hole in a second run into the well and the tubing hanger lands on the wellhead ensuring that an appropriate set-down weight is set onto the wet connect. This procedure also applies to the case of the two stage completion.

In one embodiment of the present invention, a first completion assembly, the lower completion 14, is placed in the well. As discussed above, the lower completion 14 comprises, for example, a packer and packer extensions (e.g., circulating housing, safety shear joint, screens, intelligent completions devices, etc.) as well as a control line 30 (e.g., fiber optic, electrical). As shown in FIG. 2, the lower completion 14 also comprises a lower wet connect assembly 42 at its upper end. The schematic of FIG. 2 shows only the top portion of the lower completion 14. The lower wet connect 42 is used to make up the connection to an upper wet connect assembly 44 of the connection 40.

The lower completion 14 is generally run at the bottom of a service string, which is pulled from the hole when the necessary operations (e.g., setting the packer, gravel packing, etc.) have been performed. In one embodiment of the present invention, the typical service string is replaced with a dummy production string 46 that is very similar to (1) the final production string, (2) the upper completion 12 which contains the tubing hanger and (3) the upper wet connect assembly 44. However, in the dummy service string 46, the completion jewelry (e.g., intelligent completion devices, valves, nipples, tubing hanger, wet connect) is replaced by pup joints having substantially the same length as the completion jewelry. In some embodiments the pup joints also have other characteristics, such as diameter, wall thickness, materials, and the like, that are the same as the replaced completion jewelry.

Some of the key players profiled in the study are Schlumberger Limited (United States),Halliburton Inc. (United States),Weatherford International Plc (Switzerland),Expro Group (United Kingdom),TechnipFMC plc (United Kingdom),Baker Hughes, a GE company (United States),SGS SA (Switzerland),China Oileld Services Limited (COSL) (China),Oil States International, Inc. (United States),TETRA Technologies , Inc. (United States

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