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(1)Annular BOP.

(2) Subsea Engineer’s Handbook. Section 9. Table Of Contents Section 9 Page 1. Introduction. 1. 2. Elastomer Compound Selection. 1. 3. Manufacturers. 2. 4. Typical Annular Problems. 2. 5. Shaffer Spherical Preventer. 3. 6. Hydril GL Annular Preventer. 4. 7. Hydril GX Annular Preventer. 5. 8. Cameron DL Annular Preventer. 6. 9. Annular Operation and Inspection. 7.  In-Spec Inc. 1999. Annular BOP.

(3) Subsea Engineer’s Handbook. Section 9. Annular BOP 1) Introduction Annular BOPs contain a flexible sealing element which, in the event of a kick, can rapidly close on any size tubular or tool in the wellbore. The sealing element is largely composed of a thick elastomer ring with steel fingers imbedded to give the elastomer strength when closing on wellbore pressure. This flexibility allows it to be used when initially closing in the well. After the well has been closed in and the location of tool joints determined. The pipe rams can then be closed for the remainder of the well control operations. If the pipe is off bottom the annular can be used 1st to strip the drill pipe back to bottom for killing the well. All annular preventers operate in a similar manner, the most common annular is Shaffer. Hydraulic closing pressure drives a piston upwards which forces the sealing element up and inwards to form a seal around the pipe in the hole. Various manufacturers have different operating pressures when closing on pipe, casing, and when stripping back to bottom. Consult the manual for your rig. Generally, reduced closing pressure is used when closing on casing and when stripping. Therefore, a separate regulator from the manifold regulator is used for the annular. Annular preventers should not be closed without pipe in the preventer. The additional movement of the rubber without pipe causes accelerated rubber fatigue and chunking. 2) Elastomer Compound Selection The following information is taken from the Hydril General Catalog. It is typical for selection of sealing elements compounds. Note that actual temperature ratings will slightly vary from one manufacturer to another. “Packing units for Hydril BOPs are manufactured from compounded natural rubber, nitrile rubber, or neoprene rubber. “Expected H2S and CO2 service does not affect selection of packing unit material. H2S and CO2 service will reduce the service life of rubber products, but the best overall service life is obtained by matching the packing unit material with the requirements of the specific drilling fluid. Performance of elastomeric materials can vary significantly, depending on the nature and extent of exposure to hydrogen sulfide. The operator should monitor pressure sealing integrity frequently to assure no performance degradation has occurred..  In-Spec Inc. 1999. 1. Annular BOP.

(4) Subsea Engineer’s Handbook. Section 9. “Natural Rubber is compounded for drilling with water-base drilling fluids. Natural rubber can be used at operating temperatures between -300F to 2250F (350C to 1070C). When properly applied, the compounded natural rubber packing unit will usually provide the longest service life. This all-black packing unit is identified by a serial number with a suffix "NR" “Nitrile Rubber (a synthetic compound) is for use with oil-base or oil-additive drilling fluids. It provides the best service with oil-base muds, when operated at temperatures between 300F to 1800F (-10C to 820C). The nitrile rubber packing unit is identified by a red color band and a serial number with the suffix “NBR”. “Neoprene Rubber is for low-temperature operating service and oil-base drilling fluids. It can be used at operating temperatures between –300F to +1700F (350C to 770C) Neoprene rubber provides better service with oil-base drilling fluids than natural rubber. It has better cold temperature elasticity than nitrile rubber; but it is detrimentally affected by extended high temperature applications. A neoprene packing unit should be used when natural rubber or synthetic rubber will not satisfy the operational conditions. The neoprene packing unit is identified by a green band and serial number with the suffix “CR”. “Seals for Hydril BOPs are manufactured from a special nitrile rubber material which provides long, trouble-free service in sealing against oil, gas, or water.” 3) Manufacturers There are three manufacturers of annular BOPs, Cameron, Hydril and Shaffer. The most popular annular used on subsea BOP stacks is probably the Shaffer. The major operational differences between manufactures’ equipment is the closing pressure recommended by each manufacturer. The Shaffer annular is called the Shaffer Spherical. This is due to the spherical contour of the sealing element. Hydril annulars used subsea are the Hydril GL and Hydril GX. Cameron annular BOPs used subsea are the Type DL. 4) Typical Annular Problems : • Sealing element not returning to full bore when preventer is opened • Seal leakage : either wellbore fluid leaking into the hydraulic system or, hydraulic fluid leaking out of the operating chambers.  In-Spec Inc. 1999. 2. Annular BOP.

(5) Subsea Engineer’s Handbook. Section 9. 5) Shaffer Spherical Preventer. Recommended Closing Pressure for the Shaffer Spherical Closing on static Drillpipe 7” diameter or less. 1,500 psi closing pressure. Closing on Casing larger than 7” diameter. Reduced closing pressure. Stripping pipe. Reduce closing pressure until a slight leak is observed1. 1. Many people would not want to see the preventer “leaking”. In this case closing pressure can be increased just enough to stop the leak. This will ensure that the minimum amount of closing force is used and the minimum amount of wear on the sealing element is experienced.  In-Spec Inc. 1999. 3. Annular BOP.

(6) Subsea Engineer’s Handbook. Section 9. 6) Hydril GL Annular Preventer. Average Closing Pressure (psi) To Establish Seal Off in GL BOPs for Standard Surface Installation* (Secondary Chamber to Opening Chamber) Pipe O.D. (Inches). 7” 5’ 3-1/2” Full Closure. 13-5/8” Well Pressure (psi). TYPE GL BLOWOUT PREVENTER SIZE 16-3/4” 18-3/4” Well Presssre (psi) Well Pressure (psi). 2000. 3500. 5000. 2000. 3500. 5000. 2000. 900 900 1200. 950 1000 1200. 1100 1100 1200. 700 725 800. 825 850 925. 950 1000 1050. 700 800 1000. 1400. 1500. 1400. 1500. 1500. 1500. 1500. 3500. 825 900 1050 1500. 5000. 950 1000 1100 1500. For optional surface hookup secondary chamber to closing chamber) multiply pressure shown above by X GL 5,000 psi 13-5/8” 16-3/4” 18-3/4” 21-1/4” X 0 71 0.68 069 0.66 X = ratio of closing chamber area to the sum of the closing chamber plus secondary chamber areas. This factor is used to adjust closing pressures for secondary chamber to closing chamber hookup.  In-Spec Inc. 1999. 4. Annular BOP.

(7) Subsea Engineer’s Handbook. Section 9. 7) Hydril GX Annular Preventer.  In-Spec Inc. 1999. 5. Annular BOP.

(8) Subsea Engineer’s Handbook. Section 9. 8) Cameron DL Annular Preventer.  In-Spec Inc. 1999. 6. Annular BOP.

(9) Subsea Engineer’s Handbook. Section 9. 9) Annular Operation And Inspection Points a) All Annulars in general • Always close on drill pipe. • Follow recommended manufactures procedures for use and testing. • Visually inspect closure on drill pipe and look for defects. • Verify annular element returning open to full bore. Drift wellbore with a tool such as a wearbushing, if you are not sure of a full open bore. • Visually inspect wellbore for “key seating”. • Always bleed wellbore test pressures before opening the annular element. • Internal leak from the well bore into the hydraulic operating system during testing will be a visible leak at the pod regulator or at the pod valve. • Annually test hydraulic operating chambers for leaks or when ever hydraulic leaks are suspected. A leak past the piston seals will be seen at the preventer’s opposite hydraulic port. • During low pressure testing a rising wellbore test pressure would indicate an operating chamber2 leak into the well bore. • During an annular wellbore testing, a pressure drop could occur do to the element settling out. Allow time and top up test pressures as required. i) Shaffer Annular • Closing on drill pipe 7” diameter or smaller, use 1,500 psi hyd. operating pressure. • Closing on casing, use Shaffer chart to avoid crimping the casing. • Stripping Operations, use min. closing pressure to hold preventer close. • Maxim operating pressure is 1,500 psi. for Open and Close functions. ii) Hydril GL Annular • Secondary Close port on a GL5000 Annular may be connected to the Close or Open port. Use correct plumbing and operating pressures (Hydril Annular Chart) for the installations. • Hydraulic operating chambers are rated to 3,000 psi. • When secondary Close port is hooked up to Close port, be aware that a lower Close pressure is used when operating on surface. • Consult the Hydril Annular chart for the correct Close operating pressure when closing with well bore pressure. • Closing pressures recommended by Hydril are “recommendations”. A preventer may require more closing pressure to achieve a seal than the recommendation. 2. If the lower annular was being wellbore pressure tested the lower annular closing chamber could be leaking. If the upper annular was being tested it could be the upper annular closing chamber or the lower annular opening chamber leaking hydraulic fluid into the wellbore.  In-Spec Inc. 1999. 7. Annular BOP.

(10) Subsea Engineer’s Handbook. Section 9. iii) Hydril GX Annular • 1,500 psi is the normal hydraulic operating pressure. • Consult the Hydril Annular chart for the correct surge bottle precharge pressure. iv) Cameron Model “D” and “DL” Annular • Operating chambers are rated to 3,000 psi. • Weep holes are above flange and in outside wall of the body. • Check the weep holes for leakage during hydraulic and wellbore pressure tests. • The DL hydraulic operating chamber can be pressure tested with the packer removed and the lock ring installed.3. 3. The “L” in “DL” refers to the addition of the locking ring. Older examples of this preventer were called the “D” and did not have the locking ring feature.  In-Spec Inc. 1999. 8. Annular BOP.

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