Well Head Equipment

Wellhead Equipment Introductions

Well Head Usages • • • •

Casing & Tubing Hanging Reservoir & Drilling Fluid Flow Control Fluid flow Rate Adjustments Well Safety

Well Head Types • Based On Bore Size • Based On Working Pressure: (PSI) • 2000 • •Based on Material Class: 3000 • AA 5000 Types: • ••Block BB • • • • • • • •

10000 CC 15000 DD 20000 EE FF HH

• • • •

Y-BLOCK I-BLOCK Sweep Bend Cross Type

.Casing Head Scheme BOP's Stack

Tubing Head Spool )Casing Head Spool(s

Casing Head Housing

Casing Head Housing These units are designed for moderate duty service where ease of operation is desired.

useful in: • •

low pressure high temperature service.

Units are available in: • •

nominal flange sizes to 13 5/8" pressures to 5000 psi.

casing head housings are available with either: • •

female threaded slip-on (weld) lower connection.

the slip-on connection housing has a 1/2" NPT test port, which allows testing of the weld integrity.

Casing Head Housing 2000 psi casing head spools and Higher pressure rated spools are provided standard with 2 1/16" studded side outlets. Other thread sizes, studded side outlet sizes or extended side outlets are also available. Flanged outlets are threaded internally for valve removal control plugs unless otherwise specified. Threaded outlets may be equipped with valve removal nipples if required.

The casing head housing may be furnished with a landing base when required. Landing bases are used to distribute suspended tubular loads over a larger surface area and reduce bearing loads on surface pipe.

Casing Head Housing Casing head spools are provided with a restricted area packoff in the lower ID profile to isolate annulus pressure and allow for transition to higher pressures in the upper connections. The lower flange connection contains a 1/2" NPT test port, which allows positive testing of annulus seals.

ID profiles of WS casing heads provide for a bit guide above the lower connection. The bit guide protects wellbore tubulars while maintaining the greatest casing access. Other bore dimensions are available if required. Profile diameters are based on API minimum restricted bore calculations for the lightest casing weight.

FIG. 1

Fig. 2

Fig. 3

CASING HANGERS

Non-Auto Casing Hangers Non-Auto casing hanger is designed for general service where control of annulus pressure in the casing head bowl is not critical. Sharp hardened inner teeth support suspended casing weight up to 60% of the pipe body yield strength. A minimum weight of only 5000 lbs, is required to initiate hanger operation. primary seal may be used in conjunction with the WS-4 casing hanger to add annulus sealing capabilities. Self energizing O-ring seals isolate pressure at the casing wall and casing head bore providing positive sealing to 5000 psi

Auto Casing Hangers

Auto casing hanger is designed for critical service and deep well completions where high casing weights place an unacceptable strain on conventional slip mechanisms. The integral sealing element is automatically energized with release of the casing weight. A tooth profile on the back of tapered slip elements help restrict radial loading and increase ultimate capacity. casing hangers are capable of supporting 80% of the pipe body yield strength. Working pressure to 15,000 psi is acceptable with adequate suspended load to fully energize seal.

Semi-Auto Casing Hangers

Semi-Auto casing hanger is designed for critical service where well control throughout completion operations is essential. The integral sealing element is automatically energized with release of the casing weight. When light casing loads or changes in operating conditions dictate the seal may be reenergized manually after removal of the BOP. This type casing hanger is capable of supporting 70% of the pipe body yield strength.

Fig. 3

Tubing Head Spools

•

Primary functions of tubing head

– – –

Suspend tubing with hanger Seal between tubing and annulus Provide access ports to annulus

• • • –

Gas-lift gas Inhibitor injection Circulating the well

Provide mounting for adapter flange or Xmas tree

Tubing Head Spools These units are designed for heavy duty and severe service conditions or where the operator anticipates other factors which may limit the effectiveness of a tapered profile. They are especially useful in high pressures or where tubing weight makes it necessary to reduce hoop stresses in the wellhead body. Units are available in nominal flange sizes of 7 1/16" and 9" with pressure ratings to 20,000 psi. tubing head spools are provided with a restricted area packoff in the lower ID profile to isolate annulus pressure and allow for transition to higher pressures in the upper connections.

.Tubing Head Spools cont secondary seal is standard for spools up to 5,000 psi and integral P seals are utilized for10,000 through 20,000 psi equipment. The lower flange connection contains a 1/2" NPT test port, which allows positive testing of annulus seals. Two 2 1/16" studded side outlets are standard on all tubing head spools. Other studded side outlet sizes, extended side outlets or threaded side outlets are available. Flanged outlets are threaded internally for valve removal control plugs unless otherwise specified. ID profiles of tubing heads provide for a guide above the lower connection. Profile diameters are based on API minimum restricted bore calculations for the lightest casing weight. This guide protects wellbore tubulars and directs the tubing string into the open bore during the running operations

Tubing Hangers Straight profiles allow for greater suspended tubular loads without exceeding hoop stress design criteria in the wellhead body. hangers are provided with WHI’s model H back pressure valve for use in well control during completion and workover operations. the feature of extended neck design to isolate wellbore fluids and protect the API ring seal from damage or corrosion. is a split wraparound mandrel used to provide annulus sealing capability for well control. Seals are mechanically energized with the tubing head lockscrews. hangers have an additional feature of two control line ports to the extended neck model. These ports are accessed through the tubing head adapter.

Back Pressure & Check Valves • • •

Installed into tubing hanger to close in a well, (for tree removal) Single or double check available to release bore pressure Run through polished rod lubricator

Handling Thread

Seal

Hanger Thread

Valve Spring

Valve Stem

Secondary Seals - PACK OFF All spools are provided with a secondary seal in the lower flanged connection. This seal allows for annulus pressure control as well as the possibility of increases in pressure rating between the lower and upper connection. These seals have been designed for efficient operation and reliability at various conditions. self energizing O-ring seals maintain annulus pressure isolation. The seal can be changed to allow a range of casing sizes within the same spool. This type of seal is applicable to 5,000 psi pressure rated service.

The integral P seal incorporates a mechanically energized elastomer ring to maintain annulus pressure isolation. Anti-extrusion materials allow for higher pressure service than conventional O-rings. The seals are energized by injecting plastic packing behind the seal ring. This allows for reenergizing the seal while a spool is still in service. The floating P seal operates in the same manner as our integral P seal while allowing for interchangeability within the spool. Floating P seals provide dependable service through 15,000 psi pressure rating.

FLANGES Pack-off flanges are designed to fit over wellbore casing and provide an auxiliary seal. With the flange in place, a jump in pressure rating can be achieved in a minimum of space. The flange allows the operator to test between the flange and the annular seal in the section above or below. P.O.F. is available in all nominal flange and casing sizes. with a working pressure rating of 2,000 and 3,000 provided standard with pressure energized O-ring Flanges with pressure ratings of 5,000 to 15,000 provided standard with two integral P seals

Flanges psi are seals . psi are

Crossover flanges (Adaptor flanges) are used where a change in flange size or a decrease in flange pressure rating is required with no need for an annulus pressure seal. Flanges are typically double studded to minimize wellhead stack height and reduce cost . If required, the operator may specify a height for the flange. The units may also be provide to a specified height with through bolted flanges to achieve required spacing. WXF is available in all nominal flange size and pressure ratings

Companion flanges are available in nominal flange sizes from 2 1/16" to 5 1/8" and pressure ratings to 5,000 psi. Threaded connections are either line pipe or upset tubing of the same nominal size as the flange. Since pressure ratings are limited by the rated working pressure of the threaded connection, other thread types can be furnished on request

Blind flanges are available in nominal flange sizes from 1 13/16" to 5 1/8" and pressure ratings to 20,000 psi

Blind flanges are available in nominal flange sizes from 1 13/16" to 5 1/8" and pressure ratings to 20,000 psi. Flanges to 10,000 psi are provided standard with one 1/2" LP gage port connection. Flanges for 15,000 and 20,000 psi service are provided standard with one 9/16" auto clave gage port connection

Weld neck flanges are available in nominal flange sizes from 1 13/16" to 5 1/8" and pressure ratings to 20,000 psi

Features

Neck Seal

Handling Thread

Lock Screws

Tubing Hanger

Annular Seal BPV Profile

Tubing Spool Tubing String

Ball Valve with Adapter Packoff

Fail Close Actuator

Test Ports BPV Thread

Plastic Injection Ports Tubing Hanger

GASKET SELF SEALING RING BX

RX

Flange Ruler

X-mas tree valve

 The stem rotates  The gate moves up and down

Detailed Casing Head Schema

Detailed Casing Head Schema

Detailed Casing Head Schema

Xmas Tree Selection Well Type

Water

Oil

Gas

(Rating (psi 3000 5000 3000 5000 10000 3000 5000 10000 Tree Type

Flanged Yes No Yes No

No

No No

No

Monoblock No Yes No Yes Yes Yes Yes Yes

Detailed wellhead Schema

Detailed wellhead Schema

Detailed wellhead Schema

Multiple Completion Tree

Multiple Completions • Cases where more than one completion string installed

–Each string independently suspended –Must seal off tubing casing annulus • either independently or collectively

–Independent control of fluid flow in each string

Stage 1: Casing Head Housing Step 1: Conductor 30” 1. Install the conductor 30” in advance. 2. Cut the conductor to the required height. 3. Before installing the Casing Head Housing, confirm with the Superintendent that the top of conductor is at the right height.

Stage 1: Casing Head Housing Step 2: Surface Casing Prepare 1. Inspect casing head housing assembly (CHH( including their seal areas, to make sure they are in good condition without any damage. Repair or replace if necessary. 2. Lift base plate onto the outer circle of the 20” casing, and just lie down to the top side of 30” conductor. 3. Place the CHH onto the slide car and move it to close the conductor.

Stage 1: Casing Head Housing ( Step 3: Install Casing Head Housing (CHH 1. Lift casing head vertically and check the bottom 20” inside surface and grease injection seal, then coat grease on 20” inside bore; 2. Mark 7.2m above the drilling platform on the 20" casing and then cut it, the distance between the cutting head face of 20" casing and the cutting head face of 30" casing is 200mm; 3.

Polish and clean the head face of 30“, 20” casing separately and make sure they are on the horizontal level, and then polish the head face of 20“ casing to make sure there is not defect on outer 10mm 30 DEG chamfer angle;

4. Polish the outer surface 20" with the emery cloth and grater and then check it to make sure it is smooth and there is not any neck defect;

Stage 1: Casing Head Housing .Step 3: Install Casing Head Housing (CHH( Cont 5. Lift the casing head vertically, check the bottom of the 20" inner bore and make sure there is not any defect and clean it with water then make it dry; 6. Lift casing head on the top of 20" casing. As per requirement to put casing head in alignment with gate valve then land off slowly; 7.

Weld the bottom of the casing head housing with 9-5/8" casing, warm-up in advance, after welding keep the surface chilling for 1 hour to make sure the welding is secure and reliable.

8. With cementing of surface casing ready, slack off the weight of surface casing string.

Stage 1: Casing Head Housing (Step 4: Clean the Casing Head Housing (CHH 1. Clean out inside the CHH with water hose or clean-out tool. 2. Shut off water and inspect if any dirties remained inside. If necessary, clean again. 3. Clean top flange surface and ring groove of CHH.

Stage 2: TEST PLUG / COMB. TOOL & WEAR BUSHING Step 1: BOP Test 1. Clean the ring grooves of the flanges of CHH, riser adapter (if required(, drilling spools. 2. Take right ring gaskets and apply a light coat of grease to them. 3. Apply a coat of grease to the ring grooves and place the ring gaskets into the grooves. 4. Install drilling spool and BOP stack onto top of CHH. make up the bolts and nuts. 5. Inspect the connection threads and O-rings of test plug. Replace defected ones. 1. Apply a light coat of oil to O-rings. 2. Run down one stand of three drill pipes and at a comfortable level lock the final one into Kelly bushing slips of Rotary Table.

Stage 2: TEST PLUG / COMB. TOOL & WEAR BUSHING Step 1: BOP Test 8. Make up one drill pipe 4-1/2” IF to the top box of test plug and lift the test plug. 9. Make up bottom box of the test plug to the top of drill pipe that locked in the Kelly bushing slips. 10. Remove the Kelly bushing slips to lift the test plug. 11. Lower the test plug through the BOP stack and drilling spool and seat it in CHH. 12. Slack off the block hook to release the test plug sitting in CHH. 13. Open one side outlet valve, close BOP pipe rams and increase water pressure to the required pressure rating for test. 14. Hold the test pressure at the rating for a period as required by the Superintendent. Any leakage will be read from a pressure drop of the gauge and/or test fluid witnessed out of the side valve of CHH.

Stage 2: TEST PLUG / COMB. TOOL & WEAR BUSHING . Step 2: Run down Wear Bushing 1.

With pressure test qualified, open the BOP rams to lift the test plug and drill pipes.

2.

Remove the drill pipe from the test plug.

3.

Divert the test plug and make up again the drill pipe to the test plug /combination tool for running down wear bushing.

4.

Lift the combination tool and make the ears of combination tool into the groove of wear bushing, rotate the combination tool 1/4 turn clockwise to gear into wear bushing.

5.

Check O-rings of wear bushing and replace defected ones.

6.

Apply a light coat of grease to O-rings.

7.

Lift combination tool / wear bushing, lower them through the BOP stack and seat in CHH.

8.

Rotate the combination tool 1/4 counter-clockwise to release it from wear bushing and lift the combination tool.

9.

Run down drill bit and drill the next section as required.

Stage 3: SLIP CASING HANGER Step 1: BOP Test 1. Clean the ring grooves of the flanges of CHH, riser adapter (if required(, drilling spools. 2. Take right ring gaskets and apply a light coat of grease to them. 3. Apply a coat of grease to the ring grooves and place the ring gaskets into the grooves. 4. Install drilling spool and BOP stack onto top of CHH. And make up the bolts and nuts. 5. Inspect the connection threads and O-rings of test plug. Replace defected ones. 6. Apply a light coat of oil to O-rings. 7. Run down one stand of three drill pipes and at a comfortable level lock the final one into Kelly bushing slips of Rotary Table. 8. Make up one drill pipe 4-1/2” IF to the top box of test plug and lift the test plug.

Stage 3: SLIP CASING HANGER Step 1: BOP Test 9. Make up bottom box of the test plug to the top of drill pipe that locked in the Kelly bushing slips. 10. Remove the Kelly bushing slips to lift the test plug. 11. Lower the test plug through the BOP stack and drilling spool and seat it in CHH. 12. Slack off the block hook to release the test plug sitting in CHH. 13. Open one side outlet valve, close BOP pipe rams and increase water pressure to the required pressure rating for test. 14. Hold the test pressure at the rating for a period as required by the Superintendent. Any leakage will be read from a pressure drop of the gauge and/or test fluid witnessed out of the side valve of CHH.

Stage 3: SLIP CASING HANGER Step 2: Run down Wear Bushing. 1. With pressure test qualified, open the BOP rams to lift the test plug and drill pipes. 2. Remove the drill pipe from the test plug. 3. Divert the test plug and make up again the drill pipe to the test plug/combination tool for running down wear bushing. 4. Lift the combination tool and make the ears of combination tool into the groove of wear bushing, rotate the combination tool 1/4 turn clockwise to gear into wear bushing. 5. Check O-rings of wear bushing and replace defected ones. 6. Apply a light coat of grease to O-rings. 7. Lift combination tool / wear bushing, lower them through the BOP stack and seat in CHH. 8. Rotate the combination tool 1/4 counter-clockwise to release it from wear 9. Run down drill bit and drill the next section as required.

Stage 3: SLIP CASING HANGER Step 1: Retrieve Wear Bushing 1. Drill the section to required depth. 2. Make up drill pipe to combination tool and lower it through BOP stack. 3. According the marks, when the combination tool in the CHH, slowly lower the combination tool till it seems to be supported by wear bushing. 4. Rotate the combination tool clockwise until the drill pipe drops approximately 4.5”. This indicates the lift ears of combination tool geared into the slots of wear bushing. 5. Slack off all weight to make sure the combination tool is seated down and rotate the combination tool clockwise 1/4 turn to engage the lift ears of combination tool fully into the slots of wear bushing. 6. Check to ensure all tie down screws have been retracted. 7. Slowly lift the combination tool and wear bushing through BOP stack. 8. Release the wear bushing with combination tool.

Stage 3: SLIP CASING HANGER Step 2: Slip Casing Hanger Clean out CHH. 1.Make up drill pipe to clean-out tool 2.Run the clean-out tool through BOP stack into CHH 3.Jet a high-pressure water to clean the bowl of CHH.

Stage 3: SLIP CASING HANGER Step 2: Slip Casing Hanger Prepare Before running Slip Casing Hanger.. 1.Mark on the casing circle on the basis of the top head face of the casing head housing, lift up the casing about 200mm above the marking.. 2.Clean and inspect surface of casing circle and surface of casing head housing inner bore, make sure that there is not any defect, then coat the butter on the inner bore. 3.Fold the two board on the casing, and then put it on the top head face of casing head housing. 4.Clean the casing hanger which have been removable in advanced, put it on the Ha Fu board and fasten the Ha Fu studs symmetrically. 5.Tight down the slip properly, lift the casing appropriately, ensure it is in the same with the casing head housing, and then remove the Ha Fu board. 6.Slowly put down the casing hanger, meanwhile pay attention to the change of the hook, when the hanging load is reduced to 0, fix the hook and hang the casing to wait for the cementing of the casing.

Stage 3: SLIP CASING HANGER Step 2: Slip Casing Hanger Prepare Before running Slip Casing Hanger.. 7.When the casing is cementing, slowly low down the hook, If the casing hanger is seated on the shoulder successfully, remove the elevator and BOP. 8.Mark on the 150mm of the casing above the basis of head face of casing head housing. 9.Cut down the casing with gas cutting, then polish the top head face of the casing head housing with manual rasping machine, ensure the corner is 30°×10 chamfer. 10.Clean and inspect the ring groove and ring gasket of casing head top head face, ensure that there is not any defect then coated the butter on the ring groove, clean the ring gasket then put it into the ring groove. 11.Top up the hydraulic oil in the cavity of casing head housing, which is helpful for the as below pressure testing job, mean wile coat the butter on the surface of casing.

Stage 1: Casing Head Spool Step 1: Install Casing Head Spool (CHS) 1. Remove Drilling Spool and BOP Stack. 2. Clean top flange of CHH and check the flange face and ring gasket groove to make sure no damage. Repair or replace CHH if serious damage found. 3. Lift the CHH on the slide cart. 4. Move the slide cart close to CHH and lift CHS about 1 meter above CHH. 5. Clean and check CHH especially its flange faces and ring grooves against defects. Take a new correct ring gasket and check against defects. 6. Apply a light coat of oil to the ring gasket and grooves of CHS and CHH. Place the ring gasket into the ring groove of top flange of CHH.

Stage 1: Casing Head Spool Step 1: Install Casing Head Spool (CHS) 7. Align four or more studs with nuts in the stud holes of bottom flange of CHS. 8. Lower CHS slowly at a speed of no more than 1m/min while keep the bottom flange of CHS horizontally and make sure the studs going through the stud holes of top flange of CHH. 9. Make up all the studs and nuts to connect CHS to CHH.

Stage 1: Casing Head Spool Step 2: Pressure Test Grease Injection 1.Check the test pump, high hoses and fitting to make sure they are in good condition. Fill the sleeve with grease. 2.Un-screw the blanking plugs of upper injection port and its corresponding vent port of bottom flange of CHS. 3.Make up the injection nipple to the upper injection port. 4.Use the test pump to inject grease until the grease comes out of the corresponding vent port, make up the blanking plug into the vent port.

Stage 1: Casing Head Spool Step 2: Pressure Test Grease Injection 5.Inject grease to increase the injection pressure to maximum pressure rating or 80% of the casing collapse pressure, or as per required by the Superintendent, whichever is less. 6.With the pressure stabilized, hold the pressure at the duration of 15 minutes or as per instructions by the Superintendent. 7.With the pressure test approved by the Superintendent, remove the pump and fittings and make up the blank plug into the injection port. 8.Repeat above step 2.5.1.2 to 2.5.1.7 to finish grease injection into lower injection port.

Stage 1: Casing Head Spool Step 2: Pressure Test Pressure Test 1.Remove the grease sleeve from the high-pressure hose line and fill the pump with light hydraulic oil. 2.Un-screw the blanking plug of the test port between the two injection seals and remove the check valve. 3.Make up the high-pressure nipple to the test port. 4.Hand-pump the oil to increase the pressure to maximum pressure rating or 80% of the casing collapse pressure, or as per required by the Superintendent, whichever is less.

Stage 1: Casing Head Spool Step 2: Pressure Test Pressure Test 5.Hold the pressure at the duration of 15 minutes or as per instructions by the Superintendent. No pressure drop read from the pump pressure gauge will be qualified. 6.With a satisfactory test achieved, open the check valve of hand pump to release pressure, and remove the fittings. Make up the check valve and blanking plug into the test port. 7.Un-screw the blanking plug of the test port between the lower injection seal, ring gasket and body seal of slip casing hanger, and remove its check valve. 8.Make up the nipple to the test port.

Stage 1: Casing Head Spool Step 2: Pressure Test Pressure Test 9.Hand-pump the oil to increase the pressure to maximum pressure rating or 80% of the casing collapse pressure, or as per required by the Superintendent, whichever is less. 10.With a satisfactory test achieved, open the check valve of hand pump to release pressure, and remove the fittings. Make up the check valve and blanking plug into the test port. 11.Install drilling spool and BOP stack onto CHS 12.Repeat above Part 1- Stage 2 for BOP test and running down

Stage 1: Casing Head Spool PLUG TESTER RUNNING SCHEM.

Stage 1: Casing Head Spool PLUG TESTER RUNNING SCHEM.

Stage 1: Casing Head Spool WEAR BUSHING RUNNING SCHEM.

Stage 1: Casing Head Spool WEAR BUSHING RUNNING SCHEM.

Stage 1: Casing Head Spool WEAR BUSHING RUNNING SCHEM.

Stage 1: Casing Head Spool WEAR BUSHING RUNNING SCHEM.

Stage 1: Casing Head Spool CLEAN OUT SCHEM.

Stage 2: SLIP CASING HANGER 1. Repeat the procedures of above Part 1 - Stage 3 Running Slip Casing Hanger

Stage 1: Tubing head Spool Refer from Figure 27 to 30. 1. Install THS with the same procedure as installing CHS. 2. Pressure Test with the same procedure as above Part 2 Stage 2 Pressure Test.

Stage 2: TUBING HANGER Step 1: Prepare before running tubing hanger Inspect the Tubing Hanger and Pup Joint to verify: •bore is clean and free of debris •threads are clean and undamaged •metal seals are clean and undamaged •Seal area inside THS is clean and undamaged

Make up BPV inside the Tubing Hanger. • Check BPV and running tool. • Make up BPV to running tool. • Install BPV into Tubing Hanger. • Release the running tool from BPV and retrieve the running tool.

Stage 2: TUBING HANGER Step 2: Run down Tubing Hanger. 1. Run the tubing string to designed depth. 2. Lock the last stand of tubing by Kelly bushing slips at a comfortable level in the rotary table for installation of Tubing Hanger. 3. Orient the tubing hanger with the body MX metal seal downward and make up the landing tubing to top box end of Tubing Hanger. 4. Apply a light coat of oil to the seals of Tubing Hanger including metal-to-metal seals. 5. Suspend the hanger with the pup joint at about 1 meter above the final stand of tubing string. 6. Lower the tubing hanger to make pup joint just contact the top end of final tubing.

Stage 2: TUBING HANGER Step 2: Run down Tubing Hanger. 7. Make up the pup joint to the top end of final stand of tubing string. 8. Slightly lift the whole tubing string to remove the Kelly bushing slips. 9. Carefully run down the tubing hanger / tubing string through the BOP stack and into THS. 10. Launch the Tubing Hanger onto the shoulder in THS and slack off all 11. Make tie down screws to hold tubing hanger and energize MX body metal seal.

Stage 1: CHRISTMAS TREE

Stage 1: CHRISTMAS TREE Step 1: Install Christmas Tree 1.

Lift the Christmas Tree assembly and check to confirm:

 bore is clean and free of debris.  Seal area in tubing head adapter is clean and undamaged.  Ring grooves and threads are clean and undamaged.  All valves are fully open  Use leveling rule or instrument to verify the bottom flange is horizontal.  Clean and apply a light coat of oil to ring gasket, ring grooves.  Place the ring gasket into the ring groove of top flange of THS.

Stage 1: CHRISTMAS TREE Step 1: Install Christmas Tree 2. Run down Christmas Tree assembly at a speed of no more than 1 m/min. 3.

With the adapter bottom flange approaching the extended neck of Tubing hanger, place four or more studs with nuts in cross alignment into the stud holes of top flange of THS to make sure the tubing head adapter in alignment with the THS.

4.

Launch the Christmas tree assembly onto THS.

5.

Make up the studs and nuts in an alternating cross pattern to connect Christmas tree with THS.

Stage 1: CHRISTMAS TREE Step 2: Pressure Test to Tubing Hanger seals Grease Injection to the seal of Tubing Hanger 1.Check the test pump, grease sleeve, high-pressure hoses and fitting to make sure they are in good order. Fill the sleeve with grease. 2.Un-screw the blanking plugs of injection port and its corresponding vent port of bottom flange of Tubing Head Adapter. 3.Make up the injection nipple to the injection port. 4.Use the test pump to inject grease until the grease comes out of the corresponding vent port, make up the blanking plug into the vent port. 5.Inject grease to increase the injection pressure to maximum pressure rating or 80% of the tubing collapse pressure, or as per required by the Superintendent, whichever is less. 6.With the pressure stabilized, hold the pressure at the duration of 15 minutes or as per required by the Superintendent. 7.With the pressure stabilized, remove the pump and fittings and make up the blank plug into the injection port.

Stage 1: CHRISTMAS TREE Step 2: Pressure Test to Tubing Hanger seals Pressure Test to Injection Seals of Tubing Hanger 1.Remove the grease sleeve from the high-pressure hose line and fill the hand pump with light hydraulic oil. 2.Un-screw the blanking plug of the test port between the injection seal, ring gasket and body seal of Tubing Hanger and remove the check valve thereof. 3.Make up the high-pressure nipple to the test port. 4.Hand-pump the oil to increase the pressure to maximum pressure rating or 80% of the tubing collapse pressure, or as per required by the Superintendent, whichever is less. 5.Hold the pressure at the duration of 15 minutes or as per instructions by the Superintendent. No pressure drop will be qualified. 6.With a satisfactory test achieved, open the check valve of hand pump to release pressure, and remove the fittings. 7.Make up the check valve and blanking plug into the test port.

Stage 1: CHRISTMAS TREE Step 3: Pressure Test for X-mas Tree 1. Close the wing gate valves & open the master valves & swab valves of Christmas Tree 2. Connect clean water supply to Tree cap union. 3. Increase the pressure to maximum pressure rating or 80% of the tubing collapse pressure, or as per required by the Superintendent, whichever is less. 4. Hold the pressure for 15 minutes or as required by the Superintendent. No pressure drop will qualify MS metal seal. 5. With a satisfactory test is achieved, discharge the water supply pump, remove the water supply line from Tree cap. 6. Make up BPV running tool to the tree cap to retrieve the BPV. 7. Make up Tree cap union.

Conventional Wellheads API 6 A

Agenda 1.

API 6 A

2.

Wellhead

3. Control Lines 4.

Wear bushing & Running Tool

5.

BPV & VR Plugs

6.

Gaskets

7.

Ball Valve with Adapter

8.

Block Tree

9.

Conventional & Compact Wellheads

10. Feedback – Discussion

API 6 A – ISO 10423 API 6A : •Wellhead •Christmas Tree Equipment This specification includes detailed requirements: •tubular suspension equipment •valves and fittings used at the location of oil and gas wells Specification 6A pressure rating from 2000 to 20,000 psi maximum rated working pressures

API 6A APPLICABLE EQUIPMENT API 6A Applicable Equipment Casing and Tubing Valves and Chokes Hangers

Wellhead Equipment

Connectors and Fittings

casing head housings

cross-over connectors

mandrel hangers

single valves

weld neck connections actuators

casing head spools

tubing head adaptors

slip hangers

multiple valves

blind connectors

tubing head spools

top connectors

 

actuated valves

threaded connectors

cross-over spools

tees and crosses

valves prepared for actuators

multi-stage head housings fluid sampling devices and spools

check valves

 

chokes

 

adaptor and spacer spools

Loose Connectors 1

adaptor and spacer connections bull plugs

surface and underwater   safety valves and actuators

back-pressure valves

valves removal plugs

Other Equipment

hubs presure boundary penetrations ring gaskets

running and testing tools (in Annex H) wear bushings (in Annex H)

Charpy V-Notch test • Quantitative Results: •

The quantitative result of the impact tests the energy needed to fracture a material and can be used to measure the toughness of the material and the yield strength. Charpy V Notch Impact Requirements (10 mm x 10 mm)

Temperature Temp Class

Test Temp °C (°F)

Minimum Average Impact Value Traverse Direction J (ft lb) PSL 1 PSL 2 PSL 3 and PSL 4

K

-60 (-75)

20 (15)

20 (15)

20 (15)

L N P R S T U V

-46 (-50) -46 (-50) -29 (-20) -18 (0) -18 (0) -18 (0) -18 (0) -18 (0)

20 (15) 20 (15)

20 (15) 20 (15) 20 (15)

20 (15) 20 (15) 20 (15) 20 (15) 20 (15) 20 (15) 20 (15) 20 (15)

-

-

• Qualitative Results: •

can be used to determine the ductility of a material. If the material breaks on a flat plane, the fracture was brittle, and if the material breaks with jagged edges or shear lips, then the fracture was ductile.

Temperature & Pressure Class Temperature Classification

(min) K L N P R S T U V X1 Y1

°C

(max)

-60 82 -46 82 -46 60 -29 82 room temperature -18 60 -18 82 -18 121 2 121 -18 180 -18 345

Operating Range (min) °F

(max)

-75 180 -50 180 -50 140 -20 180 room temperature 0 140 0 180 0 250 35 250 0 350 0 650

Reference Annex G for details of design and temperature rating of equipment for use at elevated temperatures. Note: Annex G is not intended as a material selection guide for high temperature use. Some alloys are embrittled after repeated or prolonged exposure to elevated temperatures. Care should be used in selection of alloys for these ratings. If plated or coated materials are used at temperatures greater than 180° C (350° F), cracking potential can be increased. 1

API Pressure Rating in MPa 13.8 20.7 34.5 69 103.5 138

API Pressure Rating in PSI 2,000 3,000 5,000 10,000 15,000 20,000

Material Class and Min Material .Req Material Class AA - General Service BB - General Service CC - General Service DD - Sour Service a EE - Sour Service a FF - Sour Service a HH - Sour Service a ZZ - Sour Service

Minimum Material Requirements Pressure-Controlling Parts, Stems & Mandrel Body, Bonnet, End & Outlet Connections Hangers Carbon or Low-alloy Steel Carbon or Low-alloy Steel Carbon or Low-alloy Steel Stainless Steel Stainless Steel Stainless Steel Carbon or Low-alloy Steel b Carbon or Low-alloy Steel b Carbon or Low alloy Steel b Stainless Steel b Stainless Steel Stainless Steel b CRAs bcd CRAs bcd User Defined User Defined

a As defined by NACE MR0175/ISO 15156 in compliance with NACE MR0175/ISO 15156. b In compliance with NACE MR0175/ISO 15156. c CRA required on retained fluid wetted surfaces only. CRA cladding of low alloy or stainless steel is permitted. d CRA as defined in Clause 3 of this International Standard. NACE MR0175/ISO 15156 definition of CRA does not apply.

Material Classes DD, EE, FF and HH require compliance to NACE MR0175 (ISO 15156) and responsibility for the choice rests with the purchaser. Examples of Designations Class FF-1.5 means: a) material class FF b) rated at 1.5 psia

Wellhead Data Sheet

Material Selection 0 to <0.05 psia

0.05 to 0.5 psia

>0.5 and <1.5 psia1

>1.5 psia1

0 to <7 psia

AA Non-Sour Non-Corrosive

DD-0.5 or EE-0.5 Sour Non-Corrosive

DD-1.5 or EE-1.52 Sour Non-Corrosive

DD-NL or EE-NL3 Sour Non-Corrosive

7 psia to 30 psia

BB Non-Sour Slightly Corrosive

EE-0.5 Sour Slightly Corrosive

2 EE-1.5 Sour Slightly Corros

EE-NL3 Sour Slightly Corrosive

>30 psia to <200 psia

CC Non-Sour Moderately to Highly Corrosive

FF-0.5 Sour Moderately to Highly Corrosive

FF-1.52 Sour Moderately to Highly Corrosive

FF-NL3 Sour Moderately to Highly Corrosive

CC or HH Non-Sour Highly Corrosive

FF-0.5 or HH-0.5 Sour Highly Corrosive

FF-1.5 or HH-1.5 Sour Highly Corrosive

FF-NL or HH-NL Sour Highly Corrosive

200 psia and up

Corrosion resistant alloys may be needed

It is recommended that Corrosion Resistant Alloys be considered beginning at CO2 partial pressures of 200 psia. Consult with engineering for material selection . Additional factors should be considered.

Material Selection  

 

H2S BELOW .05 psia non-NACE based on equipment working pressure

H2S .05 to 0.5 psia NACE sour service based on equipment working pressure

API service: API service:

AA

Non-Corrosive

CO2 BELOW 7 psia based on flowing pressure

BB

based on flowing pressure

CO2 7 to 30 psia &

API service:

CC

. Adpt, Tee, Tree Cap: AA

CO2 above 30 psia H2S below 0.05 psia

general API material requirements for this material class SS bodies & bonnets, SS internal parts SS tubing hanger mandrels & stems WG Products Wellhead, Tbg Head: N/A unless unless exposed to well flow Adpt, Tee, Tree Cap: CC Valves (all): CC Tbg Hgr: CC (17-4 SS)

H2S 0.05 to 0.5 psia

general API material requirements for this material class low alloy NACE bodies & bonnets, SS NACE internal parts SS tubing hanger mandrels & stems

WG Products

API service:

DD-NL

WG Products Wellhead, Tbg Head: EE-NL Adpt, Tee, Tree Cap: EE-NL Valves (all): EE-0,5 w/ 17-4 SS stem Tbg Hgr: FF-0,5 (17-4 SS) Customer has the option to specify materials for ZZ Material Class

API service:

WG Products Wellhead, Tbg Head: EE-NL Adpt, Tee, Tree Cap: EE-NL Valves (all) chk w/ eng - trims vary by model & working pressure Tbg Hgr: DD-NL (low alloy 80 ksi max) *use HH-NL (Inconel) tbg hanger if >80 ksi req'd Customer has the option to specify materials for ZZ Material Class

EE-NL

API service:

CO2 7 to 30 psia & H2S above 0.5 psia

general API material requirements for this material class low alloy NACE bodies & bonnets, SS NACE internal parts CRA NACE tubing hanger mandrels & stems WG Products Wellhead, Tbg Head: EE-NL Adpt, Tee, Tree Cap: EE-NL Valves (all): EE-NL w/ Inconel stem Tbg Hgr: HH-NL (Inconel) Customer has the option to specify materials for ZZ Material Class

CO2 above 30 psia

FF-0,5

CO2 below 7 psia & H2S above 0.5 psia

general API material requirements for this material class low alloy NACE bodies & bonnets, low alloy NACE internal parts low alloy NACE tubing hanger mandrels & stems *SS can be used for internal parts EXCEPT tubing hanger mandrels & stems

CO2 7 to 30 psia &

EE-0,5

H2S below 0.05 psia

Valves (all): BB Tbg Hgr: CC (17-4 SS)

API service:

Moderately to Highly Corrosive

WG Products Wellhead, Tbg Head: EE-NL Adpt, Tee, Tree Cap: EE-NL Valves 5M & below: DD-NL Valves 10M & up: EE-0,5 w/ 17-4 SS stem Tbg Hgr: DD-NL (low alloy 80 ksi max) *use FF-0,5 (17-4 SS) tbg hanger if >80 ksi req'd Customer has the option to specify materials for ZZ Material Class

general API material requirements for this material class alloy bodies & bonnets, SS internal parts SS tubing hanger mandrels & stems Wellhead, Tbg Head: AA

H2S 0.05 to 0.5 psia

general API material requirements for this material class low alloy NACE bodies & bonnets, low alloy NACE internal parts low alloy NACE tubing hanger mandrels & stems *SS can be used for internal parts, tubing hanger mandrels, or stems

WG Products Wellhead, Tbg Head: AA Adpt, Tee, Tree Cap: AA Valves 5M & below: AA Valves 10M & up: BB w/ 17-4 SS stem Tbg Hgr: AA (low alloy 110 ksi)

API service:

CO2 7 to 30 psia

H2S below 0.05 psia

general API material requirements for this material class alloy bodies & bonnets, alloy internal parts alloy tubing hanger mandrels & stems

Slightly Corrosive

CO2 below 7 psia &

DD-0,5

CO2 below 7 psia &

H2S above .5 psia NACE sour service based on equipment working pressure The latest edition of NACE MR0175 is referenced by API 6A 19th edition (effective 2-1-05) for sour service, and does not allow 17-4 SS for tubing hanger mandrels or stems above 0.5 psia H2S partial pressure unless the customer supplies or approves material specifications per section 4.2.3.3 to build ZZ trim equipment for a specific application. The manufacturer cannot rate ZZ equipment for a specific H 2S partial pressure.

API service:

H2S 0.05 to 0.5 psia

FF-NL

CO2 above 30 psia

H2S above 0.5 psia

general API material requirements for this material class SS NACE bodies & bonnets, SS NACE internal parts SS NACE tubing hanger mandrels & stems

general API material requirements for this material class SS NACE bodies & bonnets, SS NACE internal parts CRA NACE tubing hanger mandrels & stems

WG Products Wellhead, Tbg Head: N/A unless exposed to well flow Adpt, Tee, Tree Cap: FF-NL (any fittings are inconel) Valves (all): FF-0,5 w/ 17-4 SS stem Tbg Hgr: FF-0,5 (17-4 SS) Customer has the option to specify materials for ZZ Material Class

WG Products Wellhead, Tbg Head: N/A unless exposed to well flow Adpt, Tee, Tree Cap: FF-NL (any fittings are inconel) Valves (all): FF-NL w/ inconel stem Tbg Hgr: HH-NL (Inconel) Customer has the option to specify materials for ZZ Material Class

CO2 ABOVE 30 psia based on flowing pressure

Temperature

For CO2 partial pressures above 200 psia, recommended considering additional factors that influence the effect of CO2, are including: pH Sand production Types and relative amounts of produced hydrocarbons H2S level Chloride ion concentration Water production and composition consult with engineering to determine if HH-NL should be recommended for some or all components in your assembly API service:

general API material requirements for this material class

HH-NL

CO2 200 psia + H2S above 0.5 psia Needed Products Wellhead, Tbg Head: use EE-NL unless exposed to well flow CRA NACE (inconel clad) bodies & bonnets, CRA NACE internal parts inconel) CRA NACE tubing hanger mandrels & stems Valves (all): HH-NL Tbg Hgr: HH-NL

Adpt, Tee, Tree Cap: HH-NL

(any fittings are

PSL Definition API Specification 6A (ISO 10423) recommends product specification levels (PSLs) for equipment with quality control requirements for various service conditions. PSLs apply to primary equipment: •tubing heads •tubing hangers, hanger couplings •tubing head adapters •lower master valves All other wellhead parts are classified as secondary. The PSL for secondary equipment may be the same or less than the PSL for primary equipment.

Quality Control Due to PSL  

PSL-1

PSL-2

PSL-3

PSL-3G

PSL-4

Drift Test

Yes

Yes

Yes

Yes

Yes

Hydrostatic Test

Yes

Yes

Gas Test

_

_

–

Yes

Yes

Assembly Traceability

_

_

Yes

Yes

Yes

Serialization

_

Yes

Yes

Yes

Yes

Yes, Extended Yes, Extended

Yes, Extended

Quality Control Due to PSL  

PSL-1

PSL-2

PSL-3

PSL-4

Tensile Testing

Yes

Yes

Yes

Yes

Impact Testing

K, L

K, L, P

Yes

Yes

Hardness Testing

Sampling

Single

Multiple

Multiple

Dimensional Verification

Sampling

Sampling

Yes

Yes

Traceability

_

Yes

Yes

Yes

Chemical Analysis

_

Yes

Yes

Yes

Visual Examination

Yes

Yes

_

_

Surface NDE

_

Yes

Yes

Yes

Weld NDE

_

Yes

Yes

Yes

Serialization

_

_

Yes

Yes

Volumetric NDE

_

_

Yes

Yes

Welding Parts Quality Control due to PSL Weld Type Pressure containing

Non-pressure containing

Repair

Weld metal overlay (ring grooves, stems, valve-bore sealing mechanisms and choke trim)

Weld metal corrosive resistant alloy overlay (bodies, bonnets and end and outlet connections)

Quality Control Requirements for Welding Stages PSL 1 Preparation -

Completion

-

PSL 2 -

PSL 3/3G a

a, b and (c or d)

a, b, (c or d), and e

Preparation no welding permitted

Preparation

-

-

a

Completion Preparation

-

a h

a and e h

Completion

-

a, b, and (f or g)

a, b, e and (f or g)

no welding permitted

Preparation

-

-

b

b

Completion

-

b

b

b

Preparation

a

a

a

a

Completion

a,b

a,b

a, b, i

a, b, i

no welding permitted

a Visual examination. b Penetrant testing inspection for non-ferromagnetic materials and magnetic particle testing for ferromagnetic material. c Radiation (radiography or imaging) examination. d Ultrasonic examination. e Hardness test (weld). f Ultrasonic examination only if weld is greater than 25% of wall thickness or 25 mm (1 in), whichever is less. g Radiation (radiography or imaging) examination only if weld is greater than 25% or wall thickness for PSL 2 or 20% of wall thickness for PSL 3, or 25 mm (1 in), whichever is less. h Penetrant or magnetic particle as applicable for material defects only. i Measurement of overlay thickness, testing of bond integrity and volumetric examination shall be according to the manufacturer’s specifications. If the overlay is considered part of the manufacturer’s design criteria or of the design criteria of API 6A, volumetric examinations shall be in accordance with the methods and acceptance criteria of 7.4.2.3.15. Note: preparation = surface preparation, joint preparation, fit up and preheat completion = after all welding, post-weld heat treat and machining

Welding Parts Quality Control due to PSL  

PSL-1

Weld Procedure Qualification

ASME SECT. IX With Hardness Survey

Welder Performance Qualification

ASME SECT. IX

Welding Consumables, Documented Controls Instrument Calibration Required

Visual Exam of Weld

Weld Surface NDE: PT/MT

_

PSL-2

PSL-3

PSL-4

No Welding Allowed Same as PSL-1 plus Base Same as PSL-2 plus Chemical Except for Corrosion Resistant Metal Grouping Analysis and PWHT Controls Alloy Overlays Same as PSL-1 plus Hole Qualification

Same as PSL-2

No Welding Allowed Except for Corrosion Resistant Alloy Overlays

Same as PSL-1

Same as PSL-1

No Welding Allowed Except for Corrosion Resistant Alloy Overlays

Required

Required

No Welding Allowed Except for Corrosion Resistant Alloy Overlays

Required

No Welding Allowed Except for Corrosion Resistant Alloy Overlays

_

Required

Weld Volumetric NDE: UT/RT

_

Required For All Fabrication Welds and Repair Welds >25% of Wall

Weld Hardness Testing

_

_

Required For All Fabrication No Welding Allowed Welds and Repair Welds Except for Corrosion Resistant >20% of Wall Alloy Overlays

Required

No Welding Allowed Except for Corrosion Resistant Alloy Overlays

PSL Selection chart

2SV Performance Requirement PR-2

2SV Performance Requirement PR-2

2SV Performance Requirement PR-2

2SV Performance Requirement PR-2

2SV Performance Requirement PR-2 Design validation for PR2 actuators In order to simulate the actual service conditions, the actuator installed on a gate valve 7-1/16" (bore:6-3/8"),5000 psi working pressure. The test medium was hydraulic fluid. a) Actuator seal test at room temperature: Two pressure tests performed on the actuator the test medium was water. 1. A test performed at 1000 psi (20% of working pressure) for 3 minutes. 2. A test performed at 5000 psi (100% of working pressure) for 3 minutes. The above tests were repeated for three times and no leakage observed during each test.

2SV Performance Requirement PR-2 b) Dynamic open/close pressure cycling test at room temperature: A dynamic test performed on the actuator at room temperature. The test fluid was hydraulic oil Prior to operating the actuator, the gate valve was at closed position and subjected to a differential pressure of 5000 psi. The above cycle repeated for 160 times. The operating hydraulic pressure required to set the valve to open position was about 1500 psi. The test completed successfully.

2SV Performance Requirement PR-2 c) Dynamic open/close pressure cycling test at maximum rated actuator temperature: A dynamic test performed on the actuator at 121 "C. The test fluid was water. Prior to operating the actuator, the gate valve was at closed position and subjected to a differential pressure of 5000 psi. The above cycle repeated for 20 times. The operating hydraulic pressure required to set the valve to open position was about 1500 psi. The test completed successfully.

2SV Performance Requirement PR-2 d) Dynamic open/close pressure cycling test at minimum rated actuator temperature: A dynamic test performed on the actuator at -18°C. The test fluid was water (with additives to prevent freezing). Prior to operating the actuator, the gate valve was at closed position and subjected to a differential pressure of 5000 psi. The above cycle repeated for 20 times. The operating hydraulic pressure required to set the valve to open position was about 1500 psi. The test completed successfully.

2SV Performance Requirement PR-2 e) Pressure/Temperature cycles: At the end of last step, the temperature raised to room temperature. A test pressure of 2500 psi applied to the actuator and the temperature was set to 121°C. During the temperature changes, the pressure was maintained between 2500 to 5000 psi. After the temperature and pressure stabilization, the pressure was held for one hour. It is obvious that the temperature change is less than 0.5C per minute, so the temperature is stable in this case. The change in pressure between minutes 380th to 440th is about 90 psi (less than 250 psi) so the pressure is stabilized.

2SV Performance Requirement PR-2 The one hour hold period is from minutes 440th to 500th and the change in pressure within this period is about 30 psi. The maximum allowed pressure change is 250 psi, so the test completed successfully. The temperature reduced to -18°C while maintaining the test pressure between 2500 to 5000 psi. After the temperature and pressure stabilization, the pressure was held for one hour. No leakage observed.

2SV Performance Requirement PR-2 The temperature increased to room temperature while maintaining the pressure between 2500 to 5000 psi then the pressure released. The temperature increased to 121°C and a pressure of 5000 psi applied to the actuator. After a hold period of one hour no leakage observed. The pressure released and the temperature reduced to -18°C and a pressure of 5000 psi applied to the actuator. After a hold period of one hour no leakage observed. A pressure test performed at room temperature at 5000 psi for one hour and no leakage observed. A pressure test performed at room temperature at 500 psi for one hour and no leakage observed.