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Completion equipment .pptx

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Completion equipment .pptx

  1. 1. STATE UNIVERSITY OF CAMPINAS COMPLETION EQUIPMENT FRANCISCO MBATCHI
  2. 2. TREE AND TUBING HANGER The purposes of the Christmas tree are to 􏰂 Provide the primary method of closing in a well; 􏰂 Isolate the well from adjacent wells; 􏰂 Connect a flowline; 􏰂 Provide vertical access for well interventions (slickline, electricline, coiled tubing,etc.) whilst the well is live; 􏰂 Interface with the tubing hanger; 􏰂 Connect or interface the tree to the wellhead.
  3. 3. Conventional (vertical) and horizontal trees The difference between the vertical and horizontal tree is in the position of the valves. In a vertical tree, the master valves are in the vertical position and inline with the tubing, whilst in a horizontal tree, they are horizontal and away from the production/casing bore. Subsea horizontal trees therefore usually require a subsea test tree for installation activities such as clean- up flows and through-tubing interventions. This difficulty restricts the application of horizontal trees in land and platform wells.
  4. 4. Sequencing of tree installation (vertical vs. horizontal trees)
  5. 5. PLATFORM AND LAND CHRISTMAS TREES In figure, the hanger is secured with lock-down bolts and with a spool installed once the hanger has been landed and the BOP removed. Without a lock-down feature of some sort, thermal expansion or high- annular pressures may overcome tubing weight and push the tubing hanger off the seal. The landing string for the tubing hanger can be identical to the tubing. Alternatively and more commonly, slightly larger tubing can be used to allow the deployment of tubing hanger plugs that cannot fit inside the tubing.
  6. 6. The tubing hanger usually incorporates a profile for the setting of plugs or back pressure valves. These isolation devices are drillpipe, rod or wireline set. The figure shows a platform well with the tubing hanger evident. An isolation plug is inside the hanger. Any debris falling onto the plug when the BOP is removed can easily be scooped out by hand or jetted clean. PLATFORM AND LAND CHRISTMAS TREES
  7. 7. Any debris falling onto the plug when the BOP is removed can easily be scooped out by hand or jetted clean. Note the four control lines protruding through the tubing hanger in Figure. Three of these control lines (currently capped) are for operating sliding sleeves. The fourth (with temporary test line) connects to the downhole safety valve. Control lines (and gauges) can screw onto the base of the tubing hanger with a further connection on the top. The configuration shown in Figure has the control lines continuous through the tubing hanger with a single connection between the control line and the tubing hanger. PLATFORM AND LAND CHRISTMAS TREES
  8. 8. PLATFORM AND LAND CHRISTMAS TREES Christmas tree with dual flowlines (for increased flow capacity). The tree contains two manual master valves. There are both manual and hydraulic wing valves on each side. Many land wells use separate spools for each valve. This makes valve replacement easier, but increases the size (and weight) of the tree.
  9. 9. SUBSEA CHRISTMAS TREES The horizontal subsea tree requires a single-bore riser. Annulus fluids can be bled off through a concentric port in the tubing hanger and then through an annular master valve on the side of the tree. No plugs are required on the annulus flow path. Horizontal subsea tree with tubing hanger Horizontal subsea tree
  10. 10. SUBSEA CHRISTMAS TREES The tubing head seals to the wellhead, making it easier to fix problems with this seal, rather than pulling an entire tree back to surface. The tubing head then provides the orientation mechanism for the tree. A further improvement is an ROV-operable annulus isolation valve. This avoids having to run a dual-bore running string/riser as plugs are no longer required on the annulus side. The drawing also shows a modified tree cap that can be run by an ROV. The tree cap is modified for the enhanced horizontal tree and now sits inside the tree. The isolation plug above the tubing hanger has been replaced with a second plug inside the tubing hanger. This improves debris resistance and simplifies operations.
  11. 11. SUBSURFACE SAFETY VALVES Subsurface safety valves are fail-safe valves that are designed to prevent an uncontrolled release of hydrocarbons from the well if something catastrophic occurs at surface. Events that could lead to the required closure of a downhole safety valve include:  A major platform incident such as an explosion or hurricane that could cripple a Christmas tree. An impact with the tree, for example, a heavy truck colliding with a land well, a dropped BOP or a submarine colliding with a subsea tree.  Loss of integrity of the tree through structural failure, corrosion, fatigue, improper use, incorrect design or installation or poor maintenance.  Terrorist or act of war, for example, invasion and deliberate torching of Kuwaiti wells.
  12. 12. HYDRAULIC CONSIDERATIONS Most modern completions use tubing retrievable safety valves, except where conditions and rates are benign. These valves are more reliable than wireline retrievable versions, provide fewer restrictions and do not need to be pulled for every well intervention. A typical configuration of a tubing retrievable downhole safety valve is shown in Figure. Tubing retrievable downhole safety valve
  13. 13. HYDRAULIC CONSIDERATIONS Some older designs use ball valves instead of flappers, but the simplicity of flapper systems means that ball valve designs are now rare (they are still used in deployment valves where being able to pressure test from above is useful). Almost all flapper valves are pump through which is useful if the valve fails and a hydraulic kill is required. A wireline retrievable downhole safety valve is shown in Figure.
  14. 14. HYDRAULIC CONSIDERATIONS Hydraulic pressure from the control line acts on a piston. This piston is then connected to the flow tube. Figure shows the detail of a single rod piston with the cylinder removed. This piston has ‘T’ seals and a stop seal. The point of connection to the flow tube is on the right-hand side of the photo. Hydraulic pressure comes from a combination of applied surface pressure and hydrostatic pressure of the control line (or annulus) fluid. If the valve is positioned too deep, the hydrostatic pressure can maintain the valve open even when all surface pressure has been bled off. The maximum fail close setting depth (Dmax) is given by Eq.
  15. 15. PACKERS Packers provide a structural purpose (anchor the tubing to casing) and a sealing purpose. They are used in a variety of applications: 􏰂 Isolate the annulus to provide sufficient barriers or casing corrosion prevention (production packer). 􏰂 Isolate different production zones for zonal isolation (e.g. downhole flow control wells). 􏰂 Isolate gravel and sand (gravel pack packer and sump packer). 􏰂 Provide an annular seal in conjunction with an ASV. 􏰂 Provide a repair or isolation capability (e.g. straddle packers).
  16. 16. PRODUCTION PACKER TAILPIPES This design allows a plug to be set below the packer for contingent tophole workovers. If the deep-set plug cannot be retrieved at the end of the workover (e.g. debris on top of the plug), the tailpipe can be punched. All components should be spaced out to aid in wireline depth control and provide contingencies. The fluted centraliser is designed to no-go on the top of the liner, without damaging either. For platform and land wells this aids in space-out. For subsea applications (especially deepwater), the centraliser is often shearable with several joints of flush joint tubing above – over a which it can travel. This provides positive indication of the tailpipe position without requiring either undue accuracy or pulling back the tubing.
  17. 17. LANDING NIPPLES, LOCKS AND SLEEVES A number of proprietary systems are available for the locking and sealing of wireline (occasionally coiled tubing) deployed tools into the completion. The applications include:  Plugs for pressure testing, isolation and well suspension (e.g. removal of the BOP). 􏰂 Check valves (standing valves) for pressure testing. 􏰂 Deployment of memory (or wireless telemetry) gauges for pressure build-up (PBU) analysis. 􏰂 Being able to move sliding sleeves [sliding side doors (SSDs)]. 􏰂 Deployment of downhole chokes. 􏰂 Landing of siphon or velocity strings. 􏰂 Positioning of storm chokes or the inset of a wireline retrievable valve.
  18. 18. LANDING NIPPLES, LOCKS AND SLEEVES There are two methods of landing such devices:  Running a lock into a nipple profile pre-installed in the completion. Attached to the lock will be a blanking plug, standing valve, gauge, etc. 􏰂 Using a wireline (slickline or electricline) deployed packer ( bridge plug ) that can be set anywhere in the tubing. Attached to the packer is a plug, standing valve, gauge, etc.
  19. 19. The position of the seal bore, profile and no-go varies between different suppliers, thus making most locks non-interchangeable. The primary purpose of the no-go is for positive depth control. In some locks, downward forces (e.g. during a pressure test from above) are taken through the no-go; but with a well- designed modern lock mechanism this is not necessary. Where the load is taken on the locking dogs, pressure should not be used to help the lock into the nipple profile – the no-go is for location only and is not load bearing. Having a no-go requires that nipple profiles progressively reduce in internal diameter with increasing depth. This can be restrictive to tools that are run through the upper completion and into the reservoir completion (e.g. for zonal isolation). However, these reducing diameters have the advantage that seals do not need to be ‘tapped’ through seal bores on their way to deeper locations. LANDING NIPPLES, LOCKS AND SLEEVES
  20. 20. Figure. Potential nipple locations
  21. 21. REFERENCES Aasen, J. A. and Aadnøy, B. S., 2002. Buckling Models Revisited. SPE 77245. Adams, A. J., Moore, P. W., Prideco, G., et al., 2001. On the Calibration of Design Collapse Strengths for Quenched and Tempered Pipe. OTC 13048. API Bulletin 5C2, 1999. Bulletin on Performance Properties of Casing, Tubing, and Drill Pipe, 21st ed. American Petroleum Institute, Washington, USA. API Bulletin 5C3, 1994, with supplement 1999. Bulletin on Formulas and Calculations for Casing, Tubing, Drill Pipe, and Line Pipe Properties. 6th ed. American Petroleum Institute, Washington, USA. API RP 37, 1980. Recommended Practice Proof – Test Procedures for Evaluation of High-Pressure Casing and
  22. 22. Thank you for your kind attention

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