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It is necessary to consider a range of Tubular Mounted accessories which are both worthwhile and in cases compulsory for incorporation into the completion string design as a future contingency. Below are some of the more prevalent instances where one of these components will be required.

1. Downhole Tubing Detachment – In the event of Tubing failure, it will become necessary to pull the completion from the well to effect replacement of certain completion componen This detachment can be obtained by installing a removable locator device which seals with the rest of the tubing string to be left in the well during normal conditions but which can be pulled as required. In such cases a means of hydraulic isolation of the tubing below the point of detachment is required. Examples of this are a packer seal system that allows the tubing above the packer to be disconnected and retrieved, or a downhole hanger system that suspends the tubing in the well beneath the wellhead. Completion components that require frequent replacement will be located above such devices.
2. Tubing Stresses – During the normal cycle of well operations, the tubing string can expand or contract due to variations in both subsurface pressure and temperatur The tubing string is normally landed off in the wellhead and in contact downhole with the casing through the packer. Considering this, if the amount of movement were severe, it would give rise to damage to the packer, wellhead or the tubing itself. A moving seal system can be installed which would allow expansion and/or contraction of the tubing without mechanical failure or disengagement. Various systems are available; however, they all feature a concentric sleeve approach where seals are located in the concentric annulus and one of these sleeves is stationary.
3. Ability to suspend P & T Monitoring Equipment – It is commonly required to monitor the bottom-hole pressure during production tests and, in such cases, there will be a requirement to run and install a pressure or temperature gauge at a specific location in the This is most commonly accommodated by the installation of a Landing Nipple in the completion string. Its location is normally as deep in the well as possible.
4. Wireline Re-Entry Guide – It will be necessary, in most wells, to conduct wireline or coiled tubing operations below the bottom of the tubing string, or across the perforated interv In such cases, whilst pulling the tool string, a Wireline Re-Entry Guide is installed to aid in guiding the tools back into the lower end of the tail pipe of the tubing string.

PTP offers a range of Tubular Equipment and Accessories as solutions to the above mentioned requirements, for tubing sizes ranging from 2-3/8” through to 7.000”.

In the majority of completions, a specific piece of equipment is installed to allow the opening and subsequent closure of a circulation port between tubing and annulus in a production environment.This can be provided by installing one or more of the following devices; Sliding Sleeve (SSD), Side Pocket Mandrel (SPM) or a Ported Nipple to supplement the downhole SSSV and also provide isolation if the well is hydraulically dead and the SSSV is to be removed. Thus, the provision of this isolation is normally provided deep within the wellbore either just above or just below the packer.

The isolation can be provided by lowering a plug down the inside of the tubing string until it lands and locks into a nipple at a predetermined depth which has been incorporated into the design of the completion string.

PTP have the capability to supply industry proven flow control equipment to allow control of your well through intervention methods.

In a flowing well there is enough energy stored in the reservoir to flow the well to the surface, this energy is furnished by a combination of reservoir pressure and formation gas. Under some reservoir conditions, for example, if the differential pressure is not sufficient enough to drive the production fluid to surface and maintain production at an economic level, it becomes necessary to install artificial lift. Gas Lift is the process of injecting high pressure gas into the production tubing to boost the reservoir energy and lighten the hydrostatic head. This artificial lift is achieved by either the expansion of injected gas in the well, reducing the fluid gradient, the displacement of fluid by compressed gas, or a combination of one or more of these. There are two recognized types of artificial lift, ‘Continuous Flow’, most common in wells with high fluid levels but insufficient gas pressure and/or volume to flow naturally; and ‘Intermittent Flow’, in wells with low productivity wells where the injection of gas on an intermittent basis is used to drive a build-up of liquid in the wellbore to surface. The Gas Lift installation may also be used when produced fluids contain corrosive components such as CO2, or have high pour points with attendant flowing pressure loss problems. In such cases, it may be necessary to introduce specific chemicals into the flow string at a location deep within the well to provide maximum benefit and counteract the impact of these characteristics.PTP provides complete Gas Lift and Chemical Injection Systems tailored to specific requirements.