Iwcf Wattaya 2007 Rev 2

IWCF – Well Intervention Pressure Control

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Curing a hydrate problem in particular sections of the system has been accomplished by the following measures:Plug in at the surface

Close in the well and depressurise the line, or apply steam or hot water externally.

Hydrate at the stuffing box during wireline operations

Close BOP’s and bleed down the lubricator

Hydrate in the tubing

Continue injecting methanol at maximum rate taking note of the THP at all times as this could begin to rise with the fluid injection.

If during injection of methanol no increase in THP is observed (this will indicate that the tubing is not completely blocked), begin to bleed down the tubing taking careful note of the volume and type of returns. If during injection of methanol an increase in THP is observed (this will indicate that the tubing is blocked, then bleed down the THP to the point below the bubble point so as to create a gas cap above the hydrate. Methanol injected will then stand a better chance of reaching the hydrate.

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IWCF – Well Intervention Pressure Control

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17.3 Hydrate Prevention Present techniques for prevention of hydrates are mainly geared to a live well with a gas cap in the tubing. This allows methanol introduced at the Xmas Tree to gravitate down to the hydrate level, and therefore act directly on top of a hydrate, should it occur. Consideration must be given to a perforated well which has not yet been “cleaned up” as gas will migrate throughout the tubing during the completion of perforation activities. To minimise the risk of hydrate formation in the well bore and surface equipment, the following action points must be taken:  The fluids used for well operations should be incapable of supporting a hydrate. For example, water free base oil, diesel or water glycol mixes may be selected.  Prior to opening a well flow, methanol injection must be started at maximum rate and continued until the flowline temperature is high enough to prevent hydrate formation at that FTHP.  Use only a 60/40 mono-ethylene/sea water mix when pressure testing  Inject glycol at the grease injection head during wireline operations. Continually inject methanol at the Xmas Tree during all well operations. Curing Hydrates

The main guidance for removal of a hydrate plug is to reduce the pressure or increase the temperature, or use methanol, or any combination of these. WARNING:

IT IS HAZARDOUS TO BLEED DOWN PRESSURE ON ONLY ONE SIDE OF A HYDRATE PLUG IN ANY PIPEWORK.

NOTE:

The risk is that if pressure is bled down from one side of a hydrate it will begin to dissolve. As it dissolves, differential pressure can act upon one side of the plug and may cause it to be dislodged at considerable velocity. Bleeding down can be effective in dissolving a hydrate, but it is not recommended as a routine practice. However, once a full column of fluid (preferably methanol) has been established above the hydrate plug then bleeding down the pressure above to destroy the hydrate can be considered. The full column of liquid will act as a cushion and prevent the dissolved plug achieving high velocities caused by the differential pressure across it.

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IWCF – Well Intervention Pressure Control

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Although methanol is a more effective hydrate inhibitor than Glycol, it is not, however, a first choice for injection at the wireline lubricator or flowhead during well operations, as it dissolves sealing greases and may cause loss of seal in a grease head. Also injecting glycol without any form of atomisation may result in the glycol adhering to the wall of the tubing/lubricator, and will not effectively absorb free water being lifted through gas by the wireline.

Figure 17.1- Temperatures At Which Gas Hydrates Will Freeze

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IWCF – Well Intervention Pressure Control

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A hydrate plug in the tubing string under flowing or static conditions results in; being unable to run or pull wireline tools, unable to squeeze or circulate the well dead, and unable to flow the well to remove the hydrates. Hydrates may prevent vital equipment, such as the Downhole Safety Valve from functioning correctly. Thus a downhole hydrate plug gives rise to a potentially dangerous situation and must be avoided at all costs. A hydrate is hazardous when it forms in surface pressure control equipment preventing operation of valves, etc or plugging lubricators or risers. The latter may fool an operator into believing that the pressure has been bled off when pressure may be trapped behind the plug.

17.2 Hydrate Prediction Hydrate pressure / temperature formation conditions can be predicted for natural gas (refer to Figure 17.1). Hydrate prevention is normally accomplished by the injection of methanol or glycol downhole or at the Xmas Tree. The quantity of glycol or methanol required to suppress hydrates depends on pressure, temperature, water cut and flowrate. For the prevention of hydrates caused by the introduction of water whilst pressure testing for wireline entry, 60% glycol will have to be added to the water for use as a hydrate suppresser (refer Table 17.1, on freezing points of water/glycol mixes). Water / Glycol

Freezing Point

SG

(% v/v)

(°C)

100/0

-7

1.115

90/10

-28

1.109

80/20

-43

1.101

70/30

-60

1.091

60/40

-60

1.079

50/50

-44

1.068

Table 17.1 - Freezing Points Of Mono-Ethylene Glycol/Water Mixes

After the glycol/water has been thoroughly mixed, no separation of the solution will occur. The glycol/water solution can therefore be left in the pump unit for the duration of the programme without the solution deteriorating. Mono-ethylene glycol may be mixed with fresh water or sea water without any adverse effect, although sea water is preferred as in itself it is less likely to cause a hydrate than fresh water. NOTE:

Incorrect mixes will significantly reduce the level of protection.

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IWCF – Well Intervention Pressure Control

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17 HYDRATE FORMATION & PREVENTION 17.1 Formation of Hydrates Hydrates will only form if there is free water present in a system. Hydrates are crystalline water structures filled with small molecules. In oil / gas systems they will occur when light hydrocarbons (or carbon dioxide) are mixed with water at the correct temperature and pressure conditions. A very open, cage-like structure of water molecules is the backbone of hydrates. This structure, which bears some resemblance to a steel lattice in a building, can theoretically be formed in ice, liquid water, and water vapour. In practice however, hydrates are only formed in the presence of liquid water. The crystal framework is very weak and collapses soon if not supported by molecules filling the cavities in the structures. Methane, Ethane, CO2 and H2S are the most suitable molecules to fill cavities. Propane and Isobutane can only fill the larger cavities. Normal butane and heavier Hydrocarbons are too big and tend to inhibit hydrate formation. Tests indicate that Hydrate formation is comparable with normal crystallisation. ‘Undercooling’ is possible, but the slightest movement within an undercooled mixture, or the presence of a few crystallisation nuclei will cause a massive reaction. Once the crystallisation has started, hydrates may block a flowline completely within seconds. The crude composition, water composition, temperature and pressure govern the formation of hydrates. In most cases the crude composition cannot be changed. Hydrates can be dissolved / prevented by a temperature increase or a pressure decrease. Changing the composition of the water may prevent hydrate formation. Under the correct conditions of temperature and pressure, hydrates will form spontaneously. At high pressures, hydrates may form at relatively high temperatures; e.g. at 2,900psi they can begin to form at about 77°F. Hydrates do not require a pressure drop to form. However, the refrigeration effect from a small pressure drop, such as a stuffing box leak, may be sufficient to produce optimum pressure and temperature conditions for hydrate formation. Hydrates can form under flowing or static conditions. The first indication of them forming in the tubing or annular flow string is a drop in flowing wellhead pressure followed by an initially slow then progressively rapid drop in wellhead flowing temperature. During well operations, the greatest danger posed by hydrates is the plugging of the tubing string downhole. The biggest risk area for this occurring is on offshore installations from the seabed upwards where temperatures are generally the lowest.

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

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SECTION 17 HYDRATE FORMATION & PREVENTION

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

Figure 16.2 - Typical Subsea Spool Tree Workover System

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IWCF – Well Intervention Pressure Control

Figure 16.1 - Typical Subsea Workover Riser System

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IWCF – Well Intervention Pressure Control

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16 SUBSEA WELL INTERVENTIONS Subsea wells can be serviced by means of subsea workover systems. There are two systems in current use, one for conventional subsea trees and the other for the newer generation of spool trees. The former is described in Section 16.1 below and the latter in 16.1.1.

16.1 Conventional Subsea Well Interventions Conventional subsea well interventions are conducted through subsea workover riser systems which are deployed from floating vessels or from jack-up rigs in shallower waters. Riser systems are attached to the top of subsea Xmas trees and, after completing the appropriate test procedures, allow live well servicing by wireline or coiled tubing methods. Pressure control is provided at surface by a Xmas tree fitted with a lift frame, which accommodates the pressure control equipment installed on the top of the tree. Other than this, pressure control is exactly the same as that described in the previous sections except that vessel movement gives additional rigging up and operational problems. However, the workover riser system must also have subsea pressure control capabilities in the event of an emergency disconnection or a riser failure. Subsea pressure control is provided by a subsea lower riser assembly (LRA) and an emergency disconnect package (EDP) which can safely close in the well and disconnect the riser, with or without wireline or coiled tubing through the subsea tree, in the event of an emergency. These systems maintain the well in a safe condition until the problems are overcome and the riser can be re-attached. Operations can then be resumed and fishing operations initiated, if required. A typical subsea workover riser system is shown in Figure 16.1 16.1.1

Spool Subsea Tree Interventions

Due to the capital costs of conventional workover riser systems, and the incompatibility between the various manufacturers’ designs, the industry has developed the spool tree and associated intervention systems utilising standard drilling rig subsea BOP riser systems. The subsea BOPs were utilised for connection to the tree and to provide pressure control in conjunction with a subsea test tree which latches onto the spool tree tubing hanger. Pressure is contained within the subsea tree and its riser to the surface which is terminated with a surface test tree in the conventional well test fashion. The BOP rams are closed on the subsea test-tree slick joint to provide a barrier to any well pressure below the BOPs. In the event of an emergency, the subsea tree can be closed, the subsea riser disconnected before the BOP shear/blind rams are closed above the tree valve section and the drilling riser disconnected. The main problem thrown up by this method of well intervention was the lack of bore size in standard subsea test tree riser systems initially available, which has driven the design of systems with bores sizes now up to 7” in diameter. Subsea test tree systems must have a cutting capability to sever any wireline or coiled tubing run through the BOPs. Refer to Figure 16.2 for typical spool tree workover system.

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

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SECTION 16 SUBSEA WELL INTERVENTIONS

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

Figure 15.3 - ‘K3’ Choke

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IWCF – Well Intervention Pressure Control

Figure 15.2 - HP Production Chokes

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IWCF – Well Intervention Pressure Control

Figure 15.1 - Cameron Fixed Bean Choke System

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IWCF – Well Intervention Pressure Control

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15 CHOKES 15.1.1

HP Production Chokes

‘K’ Choke Beans and Wrenches:  Flared Orifice entrance reduces erosion on the entrance surface.  Accuracy levels are maintained over extended periods of use.  Choke beans save time and money because replacement intervals are extended. Cameron ‘K’ choke beans come in two styles, positive and combination. The positive bean has a fixed orifice diameter. The combination bean has a fixed diameter and a throttling taper at the entry. The combination bean is used with an adjustable choke needle to make incremental changes to orifice sizes smaller than the fixed orifice. The part numbers of the positive and combination beans are determined by desired orifice size. ‘K1’ positive bean orifice sizes range from 4/64" to 64/64". ‘K2’ positive bean orifice sizes range from 4 /64" to 128/64". ‘K3’ positive bean orifice sizes range from 4/64" to 192/64". ‘K1’ combination bean sizes range from 6/64" to 64/64". ‘K2’ combination bean sizes range form 6/64" to 128/64". ‘K3’ combination bean sizes range from 6/64" to 192/64".

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

SECTION 15 CHOKES

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

NOTES PAGE

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

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14.3 BOP CONTROL SYSTEMS BOP control systems used in well intervention services are usually specifically designed for purpose by the individual manufacturers and there is no industry standard control system as such. Units used with wireline packages are often an integral part of the modern winch. Units used on coiled tubing or snubbing systems are usually rented items supplied by rental companies. Most control systems for small wireline BOPs usually have no accumulation and are directly operated by an air pump. Larger systems such as used on snubbing units may have accumulation with a volume enough for 21/2 closures of all the BOPs, but this is not governed by any legislation or industry standard and is usually determined by either, the service provider’s or operating company’s safety policy. When accumulation is used they are tied into the supply side and are charged with nitrogen as normal for safety reasons. Charging of accumulators must be strictly in accordance with the manufacturer’s instructions.

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IWCF – Well Intervention Pressure Control

Table 14.4 - Ram Preventers - Fluid Required to Operate

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Example Closing forces in relation to area:

 When closing the well, the string is picked up say 20ft off bottom. The annular preventer is then closed and the fail-safes opened against a closed choke.  The tool joint is then spaced out for the correct pipe rams.  The string is stripped down until the tool joint is "hung off” on the rams. The correct operating pressure to set on the manifold regulator is directly related to the well bore pressure. For example. Operating ratio 10:56:1. Working pressure of BOP stack 10,000psi. F 10,000 psi P \F P xA  947 psi A 1056 . This pressure does not include an allowance for friction losses so the minimum pressure would be say 1,000psi x 10.56 = 1,0560lbs closing force.

Figure 14.19 - Closing Forces in Relation to Area

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IWCF – Well Intervention Pressure Control

CAMERON U Size (in) 1

7 /16

9

WP (psi)

Open

Close

3,000 5,000 10,000 15,000

2.3 2.3 2.3 2.3

6.9 6.9 6.9 6.9

SHAFFER ‘SL’ Open

3.37

HYDRIL RAM

Close

Open

Close

7.11

1.5 1.5 1.7 6.6

5.4 5.4 8.2 7.6

2.6 2.6

5.3 5.3

6.8 6.8 7.6 7.6

2,000 3,000 5,000 10,000

11

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2,000 3,000 5,000 10,000 15,000

2.5 2.5 2.5 2.5 2.2

7.3 7.3 7.3 7.3 9.9

7.62 2.8

7.11 7.11

2.0 2.0 2.4 3.24

3,000

2.3

7.0

3.00

5.54

2.1

5.2

5,000 10,000 15,000

2.3 2.3 5.6

7.0 7.0 8.4

3.00 4.29 2.14

5.54 7.11 7.11

2.1 3.8 3.56

5.2 10.6 7.74

2,000 3,000 5,000 10,000

2.3 2.3 2.3

6.8 6.8 6.8

2.03 2.06

5.54 7.11

2.41

10.6

183/4

10,000 15,000

3.6 4.1

7.4 9.7

1.83 1.68

7.11 10.85

1.9 2.15

10.6 7.27

211/4

2,000

1.3

7.0

0.98

5.2

3,000 5,000 10,000

1.3 5.1 4.1

7.0 6.2 7.2

0.98 1.9

5.2 10.6

2,000 3,000

1.0

7.0

135/8

163/4

3

26 /4

1.63

7.11

Table 14.3 - Ram Preventer Opening and Close Ratios

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IWCF – Well Intervention Pressure Control

Variable Rams

7

Figure 14.17 - Variable Rams 5” - 2 /8”

Figure 14.18 - Shearing Blind Rams

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14.2.6

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Ram Types

Shaffer Shear Ram

Shaffer Shear Rams shear pipe and seal the wellbore in one operation. They also function as Blind or CSO (Complete Shut Off) Rams for normal operation. To ensure adequate shearing force, a minimum of 14” pistons is required when operating Shaffer Shear Rams. The hydraulic closing pressure for normal shearing is 3,000psi or blind operation at 1,500psi accumulator pressure. When shearing pipe in a subsea BOP stack, 3,000psi accumulator pressure is required. When shearing, the lower blade passes below the sharp lower edge of the upper ram block and shears the pipe. The lower section of cut pipe is accommodated in the space between the lower blade and the upper holder. The upper section of cut pipe is accommodated in the recess in the top of the lower ram block. Closing motion of the rams continues until the ram block ends meet. Continued closing of the holder squeezes the semicircular seals upward into the sealing contact with the seat in the BOP body and energises the horizontal seal. The closing motion of the upper holder pushes the horizontal seal forward and downward on top of the lower blade, resulting in a tight sealing contact. The horizontal seal has a moulded-in support plate, which holds it in place when the Rams are open. The Shaffer Shear Rams are also available for H2S service that meets the requirements of NACE Standard MR-01-75. U.S. Patent No. 3,736,982 covers Shaffer Shear Rams.

Upper Block

Upper Holder

Upper Rubber

Lower Rubber

Lower Blade

Figure 14.16 - Shaffer Shear Rams

Lower Block

Lower Holder

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IWCF – Well Intervention Pressure Control

14.2.5

Hydril Ram Preventer

Figure 14.15 - Hydril Ram Preventer

Operating Features:       

Available with manual or automatic locking systems. Cylinder liner is field replaceable or repairable. Secondary rod sealing action. Rams can be changed and repaired in the field. Additional room must be allowed for side door openings. Sloped ram cavity is self-draining of mud and sand. Rams are designed to permit drill pipe hang-off.

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UltraLock is a versatile locking system. It provides a maintenance-free and adjustment-free locking system that is compatible with any ram assembly that the blowout preventers can accommodate. Once the UltraLock is installed, no further adjustments will be needed when changing between Pipe Rams, Blind/Shear or MULTI-RAM assemblies. BOPs that are equipped with the UltraLock are automatically locked in the closed position each time that the BOPs are closed; no pre-set pressure ranges are needed. The BOPs remain locked in the closed position, even if closing pressure is lost or removed. Hydraulic opening pressure is required to re-open the preventer, and this opening pressure is supplied by the regular opening and closing ports of the preventer. No additional hydraulic lines or functions are required for operation of the locks. Stack frame modifications are not required because all operational components are in the hydraulic operating cylinders. Existing BOPs with PosLock Cylinders can be upgraded to the UltraLock.

Figure 14.14 - Ultralock Locking System

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14.2.4

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Shaffer BOPs

On Shaffer type LWS or SL rams, the locking device is actuated automatically whenever the ram is closed. Called the Poslock, this system uses segments that move out radically from the ram piston and lock into a groove in the circumference of the operating cylinder whenever the ram is closed. When hydraulic closing pressure is applied, the complete piston assembly moves inward and pushes the ram towards the wellbore. With the rams closed, the closing pressure then forces a locking piston inside the main piston to move further inwards and force out the segments. A spring holds the locking piston in this position so that the segments are kept locked in the groove even if closing pressure is lost. When hydraulic opening pressure is applied, the locking cone is forced outward. This allows the locking segments to retract back into the main piston that is then free to move outwards and open the ram.

Figure 14.13 - Poslock Adjustment

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IWCF – Well Intervention Pressure Control

14.2.3

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‘SS’ Space Saver

Figure 14.12 - Cameron Ram Preventer - Type ‘SS’ (Space Saver)

Operating Features:     

Low in vertical height. Ram position cannot be determined by external observation. Well pressure assists in maintaining rams closed. Has secondary operating rod seal. Rams can be changed and repaired in the field.

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Figure 14.11 – Exploded View of Cameron ‘U’ Type BOP

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Figure 14.10 - UII BOP Hydraulic Control System

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14.2.2

Double ‘UII’

Figure 14.9 - Double ‘UII’ BOP

Operating Features:      

Application in both surface and Sub-Sea applications. Well bore assist. Accurate preload and fast make up for ram change. Secondary seals on operating rod. 250°F of rating for HP wells. Automatic locking device (self adjusting).

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14.2 RAM PREVENTERS It is not possible to detail every type of ram preventer manufactured for all the applications for which they are used in snubbing operations. The following are only typical examples of those in use. 14.2.1

Cameron

The ‘U II’ blowout preventer provides a BOP system (including CAMRAM elastomer sealing) that meets the API 6A rating of 250°F service. The ‘U II’ includes an internally ported hydraulic bonnet stud tensioning system, a short stroke bonnet, bore type bonnet seals, and the proven advantages of the ‘U’ BOP design.  The introduction of the CAMRAM packer has set a new industry standard in meeting the 250°F and withstand excursions to 300°F. Presently, the API standard excludes these critical sealing elements from the rating, which covers only the metal components of the BOP system.  CAMRAN packers and top seals made with CAMLAST are available for high temperature and high H2S service.  The bonnets of the ‘U II’ preventer are opened and closed hydraulically. The bonnet studs are hydraulically stretched to the correct preload by pressure applied behind a piston, which acts on a load rod in the stud. The nut is tightened and pressure is released. Pressure is supplied by an air-powered hydraulic pump via internal porting in each end of the BOP body.  The short stroke bonnet reduces the opening stroke by about 30%, reduces the overall length of the preventer, and reduces the weight supported by the ram change pistons.  The bore type bonnet seal fits into a seal counter bore in the body and has metal anti-extrusion rings.  The ‘U II’ blowout preventer wedgelocks act directly on the operating piston tailrod. The operating system can be interlocked using sequence caps to ensure that the wedgelock is opened before pressure applied to open the preventer.  A ram bearing pad can be attached to the bottom of each ram to reduce ram bore wear.  All Cameron ‘U II’ BOPs are manufactured to comply with NACE and all regulatory body specifications.

IWCF – Well Intervention Pressure Control

SIZE AND

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HYDRIL

WORKING PRESSURE

GK

NL SHAFFER GL

Inches

Psi

Close

Open

6

3,000

2.9

6

5,000

3.9

7 /16

10,000

9.4

8

3.000

8

Close

Close

Open

2.2

4.6

3.2

3.3

4.6

3.2

4.4

3.0

7.2

5.0

5,000

6.8

5.8

11.1

8.7

10

3,000

7.5

5.6

11.0

6.8

10

5,000

9.8

8.0

18.7

14.6

11

5,000

11

10,000

25.1

12

3,000

11.4

9.8

23.5

14.7

5

13 /8

3,000

5

13 /8

5,000

18.0

14.2

23.6

17.4

5

13 /8

10,000

34.5

24.3

47.2

37.6

16

2,000

17.5

12.6

16

3,000

21.0

14.8

3

16 /4

3,000

3

16 /4

5,000

28.7

19.9

3

16 /4

10,000

18

2,000

21.1

14.4

3

18 /4

5,000

20

2,000

20

3,000

20

5,000

30

1,000

30

2,000

19.8

Open

SPHERICAL

19.8

Balancing

8.2

33.8

33.8

17.3

33.0

25.6

44.0

44.0

20.0

48.2

37.6

32.6

17.0

61.4

47.8

58.0

58.0

29.5

Table 14.2 - Annular Preventers - Gallons of Fluid Required to Operate on Open Hole

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14.1.6

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Packing Element Selection

Only packing elements, which are supplied by the manufacturer of the annular preventer, should be used. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed. (Refer to Table 14.1) PACKING UNIT TYPE

IDENTIFICATION Colour

Code

OPERATING TEMP RANGE

WELL FLUID COMPATIBILITY

Natural Rubber

Black

NR

-30°F – 225°F

Water based Fluid

Nitrile Rubber

Red

NBR Band

20°F – 190°F

Oil base/ Oil Additive Fluid

Neoprene Rubber

Green Band

CR

-30°F – 170°F

Table 14.1 - Packing Unit Selection (from Hydril)

Oil Base Fluid

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14.1.5

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Shaffer Annular Preventers

Figure 14.8- Shaffer Annular Preventers

Operating Features:  Will close on open hole (but not recommended). As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inwards to sealing against anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape.  Requires higher closing pressure in subsea applications. As the contractor piston is raised by hydraulic pressure, the rubber packing unit is squeezed inward to a sealing engagement with anything suspended in the wellbore. Compression of the rubber throughout the sealing area assured a seal-off against any shape.  Some sealing assistance is gained from the well pressure.  No provision for measuring piston travel. Hydril and Shaffer's annular preventers are claimed to provide positive closure with 1,500psi closing unit pressure when the rubber elements are new.

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Figure 14.7- Cameron Annular Preventer - Type ‘DL’

Operating Features:    

Quick-release top latch for easier element change. Most sizes use less closing fluid than Shaffer and Hydril annular preventers. Overall height is less than Hydril and Shaffer annular preventers. Weight of preventer is less than Hydril and Shaffer annular preventer in all sizes except for 11“ 10,000psi WP.

Cameron's Type DL annular preventer requires 3,000psi hydraulic closing pressure for positive closure with no pipe in the preventer. This requires a bypass arrangement around the 1,500psi annular regulator on 3,000psi closing units.

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14.1.4

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Cameron Annular Preventers

Figure 14.6- Cameron 20,000psi WP Annular Blowout Preventer

Operating Features:    

Will close on open hole. Vents isolate the hydraulic operating system from the well pressure. Standard trim suitable for H2S service. Operating chambers remain sealed during packer element change to prevent contamination.  The quick-release top latch reduces time to change packing element.  The packing element contains steel reinforcing inserts forming a continuous ring that gives maximum support as they close inward.

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Standard Surface Hook-Up Requires Least Fluid So Gives A Faster Closing Time Secondary Chamber Connected To Opening Chamber (S-O)

Subsea Hook-up For Water Depths Over 800ft Secondary Chamber Connected To Closing Chamber (S-C)

Subsea Hook-up For Water Depths Up To 800ft Secondary Chamber Connected To Marine Riser (CB)

Closing Pressure Opening Pressure

Figure 14.5- Hydrill ‘GL’ Annular Preventer Operational Options

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Figure 14.4 – Exploded View of an Annular Preventer

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14.1.3

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Hydril ‘GL’ Annular Preventer

Figure 14.3- Hydril Annular Preventer - Type ‘GL’

Operating Features:      

Will close an open hole (but not recommended). Some sealing assistance is gained from well pressure. Bolted cover for easier element change. Primarily designed for subsea operations. Has a provision to measure piston travel to gauge element wear. Has a balancing chamber to offset hydrostatic pressure effect in subsea operations. The chamber can be connected four ways to optimise operations for different effects: Minimise closing/opening fluid volumes. Reduce closing pressure and times. Automatically compensate (counterbalance) for marine riser hydrostatic pressure effects in deep water. Operate as a secondary closing chamber.

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71/16” 15,000psi WP

Operating Features:     

Will close on open hole. Sealing assistance is gained from the well pressure. Meets the current revision of NACE standards for sulphide stress cracking. The head has a field replaceable wear plate, which is bolted on. Has provision to measure piston travel to gauge element wear.

If the annular packing element wears out during stripping or well killing operations, the element can be changed without having to pull the pipe. After the pipe rams are closed and locked below the annular preventer and both the hydraulic and well pressure below is bled off, the cover of the preventer can be unbolted and the packing element lifted out with a tugger or hoist line. With the element above the preventer, the damaged unit can be split and removed from the pipe. A new element would be installed in reverse sequence of the above.

1

Figure 14.2 - Hydril Annular Preventer - ‘GK’ 7 /6" 15,000psi WP

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When stripping, the closing pressure should be regulated to the minimum required for a slight weeping of well fluid past the element. Closing pressures higher than this will increase element wear. The pipe should be moved slowly, particularly as tool joints pass through the element. The manufacturers also provide information regarding recommended closing pressures during stripping operations. Surge vessels on the closing ports will help to smooth-out surge pressures as tool joints pass through the element. 14.1.2

Hydril ‘GK’ Annular Preventer

41/16” 10,000, 15,000 and 20,000psi WP

Operating Features:        

Designed for stripping and snubbing operations. The packing unit and the operating chambers are tested to rated working pressure. The BOP body is tested to 11/2 times the rated working pressure. Will close on open hole. Has provision to measure piston travel to gauge element wear. Is available with bolted top. Sealing assistance is gained from the well pressure. Meets the current revision of NACE standards for sulphide stress cracking.

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Figure 14.1- Hydril Annular Preventer - ‘GK’ 4 /16" 10,000 15,000 & 20,000psi WP

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14 PREVENTERS 14.1 ANNULAR PREVENTERS 14.1.1

Introduction

The annular preventer consists of a flexible reinforced element that can seal any size tubular. The element is squeezed round the tubular by a piston of relatively large area. Because of this, the operating pressure is relatively low (usually regulated between 0 and 1,500psi as needed) and so pipe can be stripped into the hole under pressure, if necessary. If upset pipe has to be stripped through an annular, the rubber is forced out whenever a tool joint passes through it. This in turn forces fluid from the closing side of the piston and so surge chambers are needed to handle this flow. Figure 14.1 shows a Hydril GK (surface type) preventer. The majority of annular preventers currently in use are manufactured by Hydril (Types ‘MSP’, ‘GK’, ‘GL’, ‘GX’), Shaffer (Spherical) and Cameron (Type ‘D’), these are illustrated (refer to Figure 14.1, Figure 14.2, Figure 14.3 together with a summary of major operating features. The following are the most important aspects of the operation of annular preventers:  To obtain maximum sealing life, hydraulic closing pressures should conform to the manufacturer's recommendations for pressure testing and operational use of the preventers. Excessive closing pressures, when coupled with wellbore pressure sealing effects, cause high internal stresses in the element and reduce element life.  Cavities should be flushed out and the element inspected following each well. Preventers should be stripped and inspected annually. Seals should be replaced and all sealing surfaces inspected.  Cap seals should be replaced when changing elements.  Tooling, especially mills and bits, should be run cautiously through BOPs to minimise element damage. Elements of annular preventers do not, on occasions, retract fully.  The type of elastomer (natural rubber, synthetic rubber, neoprene) used in the packing element should be the most suitable for a particular wellhead environment; Figure 14.1 and Figure 14.2  Although most models and sizes of annular preventer will seal an open hole in an emergency operation, it is not recommended; as such gross deformation of the elastomer causes cracking and accelerated wear.  Closing pressures should be regulated to the pressures specified by the manufacturers. This information should be available at the rig site.

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SECTION 14 PREVENTERS

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NOTES PAGE

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Materials PSL 0

Gasket material for PSL 0 shall conform to appropriate standards.

PSL 1-4

Gasket material for these levels shall conform to appropriate standards.

Coating Platings

and

General. Coatings and platings are employed to aid seal engagement while minimising galling and to extend shelf life. Coating and plating thicknesses shall be 0.0005” maximum. Metallic. Cadmium, zinc, copper and tin coatings or platings are acceptable for service temperatures up to 250F. Non-metallic. Non-metallic coatings are acceptable if they do not interfere with the sealing of the ring gasket.

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13.1.3

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Ring Gaskets

General

The section covers Type ‘R’, ‘RX’, and ‘BX’ ring gaskets for use in flanged connections. Types ‘R’ and ‘RX’ Gaskets are interchangeable on ‘6B’ flanges. Only Type ‘BX’ gaskets are to be used ‘6BX’ flanges. Type ‘RX’ and ‘BX’ gaskets provide a pressure energised seal but are not interchangeable. Design

Dimensions. Ring gaskets shall conform to the dimensions and tolerances specified below and must be flat within 0.2% of ring outside diameter to a maximum of 0.015”. ‘R’ and Gaskets

‘RX’

Surface Finish. All 23° surface on Type ‘R’ and ‘RX’ gaskets shall have a surface finish no rougher than 63 RMS. ‘RX’ Pressure Passage Hole. Certain size ‘RX’ gaskets shall have one pressure passage hole drilled through their height

‘BX’ Gaskets

Surface Finish. All 23° surface on Type ‘BX’ gaskets shall have a surface finish no rougher than 32 RMS. Pressure Passage Hole. Each ‘BX’ gasket shall have one pressure passage hole drilled through its height

Re-use of Gaskets. Ring gaskets have a limited amount of positive interference that assures the gasket will be joined into sealing relationship in the flange grooves; these gaskets shall not be reused.

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13 EQUIPMENT SPECIFIC REQUIREMENTS 13.1 FLANGED END AND OUTLET CONNECTIONS 13.1.1

General - Flange Types and Uses

There are three types of end and outlet flanges, ‘6B’, ‘6BX’ and segmented which are designed to the specification outlined in this section: ‘6B’ and ‘6BX’ flanges may be used as integral, blind or weld neck flanges. Type ‘6B’ may also be used as threaded flanges. Some type ‘6BX’ blind flanges may also be used as test flanges. Segmented flanges are used on dual, triple, and quadruple completion wells and are integral with the equipment. 13.1.2

Design

Pressure Ratings and Size Ranges of Flange Types

Type ‘6B’, ‘6BX’, and segmented flanges are designed for use in the combinations of nominal size ranges and rated working pressure. Type ‘6B’ Flanges

General. API Type ‘6B’ flanges are of the ring joint type and are not designed for make-up face-toface. The connection make-up bolting force reacts on the metallic ring gasket. The Type ‘6B’ flanges shall be of the through-bolted or studded design.

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SECTION 13 EQUIPMENT SPECIFIC REQUIREMENTS

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Tubing is rabbited and clear of debris

Re-active:

Tool joints are doped properly

When running or pulling under pressure ensure TIW valves are used at every joint whilst making up or breaking out tubing. Renew springs and ball and seats. If necessary, drop dart plug and pump into nipple.

C. Use of HWO Auxiliary Equipment

1. Auxiliary Equipment Gin Pole, Counterbalance Winch Tongs

pre-emptive:

Equipment Failure

Ensure equipment is properly rigged up and maintained.

Check for defective or worn tools and equipment

Follow correct rig up and running procedures.

Slinging lifts

Follow correct lifting and slinging procedures whilst rigging up equipment. Ensure correct hydraulic system pressures are being used. Re-active: At the first sign of any wear or tear, secure unit and shut down power pack if necessary and carry out repairs. All worn guy wires and winch cables should be changed-out. (These repairs should be done immediately.)

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4. Stripper BOP Failure

pre-emptive:

Rams closing too slow

Ensure correct preventer pump pressure is maintained for the rams being used.

Valves sticking whilst opening or closing

Ensure equalise and bleed-off valves are functioning properly (as BOP will not open if pressure is trapped between rams). Re-active: Close in tubing rams below stripper BOP and manually lock in. Bleed off pressure. Open rams and change out stripper inserts. Ensure valves are greased properly with correct grease.

5. Jack Movement

pre-emptive:

Slow movement of jack

Ensure all jack pumps are at correct settings. Ensure sufficient hydraulic oil is in reservoir. Check Munsen Tyson valve is functioning properly.

Jack jumps when moving up or down

Ensure counter balance valves are operational and free from grit. Re-active: Secure tubing in well in heavy slips. Check all settings for pumps, and that pumps are all functional. Open travelling slips and check movement on jack without pipe.

B. HWO Well control

1. BPV Failure

pre-emptive:

Gas or liquid flowing from top of tubing

Ensure that back-pressure valves are maintained properly. Check springs ball and seats are not worn or corroded. Ensure tool joints are made up to correct torque and seals are OK. Pipe dope or scale falling on top of BPVs.

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12.6 IDENTIFIED SNUBBING/HWO HAZARDS There are three main areas involving HWO activities where hazards are identified:  HWO operation  Well control  Use of HWO auxiliary equipment. The hazards associated with these categories and the control mechanisms are given in the following table. APPLICATION A. HWO Operation

IDENTIFIED HAZARDS

CONTROL MECHANISM

1. Power Pack Failure

pre-emptive:

Engine Failure

Conduct maintenance procedures and ensure engine is fully serviced with oil and fuel.

Engine out of fuel

Re-active: Immediately set Heavy slips on pipe in the hole, (Snubber/ stationery if in the light mode) close in safety rams on tubing.

2. Hydraulic Failure

pre-emptive:

Hydraulic hose bursting

Conduct proper check on all hose connection valves and pumps.

Valve seizure

Function test all Hydraulically moving parts.

Insufficient oil in Hydraulic Reservoir

Ensure sufficient Hydraulic oil is in the reservoir. Re-active: Make sure unit is secure prior to shutting down engine for repairs.

3. Slip Failure

pre-emptive:

Tubing Sliding Through Slips

Ensure correct pressures are maintained for opening and closure of slips. Ensure slip inserts are free from grease, pipe dope and scale whilst RIH or POOH. Re-active: Close in all slips and secure with clamp prior to changing out worn slip inserts.

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Balance Point

Passing the balance point, is the point at which the pipe, in conjunction with fluid weight in the pipe, equals the force exerted over the diameter of the pipe by the well pressure. It is a delicate operation as the pipe is passing from the snubbers onto the slips. The mode of operation before this point is termed pipe light and after the balance point, pipe heavy. During this period it is possible that the pipe may slip, therefore it is good practice to use both snubbers and slips for a short time until the unit sees sufficient weight to make the slips operate effectively. To help during this time, it is beneficial to move the weight from negative to positive quickly by filling up the pipe when it is near the balance point, moving into the pipe heavy mode.

Figure 12.12 – BHA Configuration

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12.5.2

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Deployment and Pressure Testing Procedures

Pressure Testing

1) The Xmas tree valves should be tested for operation and leaks before the operations commence. 2) Pressure test all items possible before rigging up. 3) Install the BHA on pipe into the Xmas tree with the two valves (usually the master valves) closed. 4) Close the pipe rams in sequence and apply test pressure through the tree wing valve, or other suitable port, testing the BHA check valves and each ram in turn. Use the snubbers to hold the pipe in the BOPs. 5) Test annulars or strippers in the same manner. 6) When all pressure testing and function testing has been completed with the stripper or lower stripper ram closed, equalise the pressure in the BOP stack with the well pressure below the tree. 7) Slowly open the tree valves and observe for any leaks. 8) Begin snubbing pipe monitoring the strippers.

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12.5 Bottomhole Assemblies The configuration of BHAs with regard to check valve and back pressure valve location and function is essential for safety at the start of running, or the end of pulling a workstring:  BPVs used must be as strong as the tubing and are located at the bottom of the string for normal operations. However they may be placed higher if using gases for foam jetting or nitrogen lifting, reducing the inventory of gas that may blow back if there is a failure in the pumping equipment lines.  When using abrasive fluids such as cement, it is advisable to install pump-out type valves in the event of plugging or flow cutting. They are also used if reverse circulating is required.  Standard* back pressure valve configurations are shown in Figure 12.12. The configurations in ‘C’ are preferred. In ‘B’ it must be closely checked to ensure the wireline plug can be set in the nipple. A long end cap may hold up on the top back pressure valve and prevent the lock mandrel from setting in the nipple. The configuration in ‘D’ may be too long to allow closing in the well when the nipple is at the top of the mast. When using pump-out BPVs, the configuration in ‘E’ should be used, but the pump-out ball for expending the BPVs must first be passed through the nipple to check clearance.  Standard in this context means a practise that has become a "standard" within the service companies who provide snubbing/HWO services to the industry, and is not an institutionalised type standard. 12.5.1

Snubbing BHA Arrangements

The BHA shown is typical and must be accompanied by having a tubing safety valve on hand in the work basket. Safety valve must be in the open position (closing device in work basket) and have the correct thread connections for tubing being used. Operating features:  There should be a minimum of two check valves.  At least one wireline nipple must be installed for secondary well control. If a leak occurs to either of the check valves, a wireline run check valve can be installed in this nipple.  Enough distance must be provided, especially in sandy conditions so that both check valves cannot be plugged.  Spacing out of the check valves must be such that they can be snubbed into the well above two closed barriers.  In the event of a tubing leak above the check valves, temporary secondary control is provided by stabbing on the safety valve in the workbasket. Various configurations may be used for differing applications providing they meet with the minimum requirements outlined above.

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Figure 12.11 – Example Snubbing BOP Configuration With Restricter Spools

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Figure 12.10 - Example Snubbing BOP Configuration Over 10,000psi

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12.4.11

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Snubbing BOP Stack Arrangements. Over 10,000psi WP

(Refer to Figure 12.10) Operating features:  This is the very minimum arrangement for over 10,000psi WP and one size of pipe only.  If a leak occurs to the top stripper then the lower stripper and one safety ram can be closed giving double barrier protection to allow repair and re-instatement of the strippers.  If the lower stripper leaks, both safety rams would be closed.  Two tree valves or a combination of both valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial.  When the upper safety or blind rams are closed, the flow line and chokes can be used.  The upper safety rams can be used for stripping in emergency situations.  The combination of shear and blind rams provide ultimate safety, if secondary well control fails.

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Figure 12.9 - Example 5,000-10,000psi Snubbing BOP Configuration

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12.4.10

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Snubbing BOP Stack Arrangements 5,000-10,000psi WP

(Refer to Figure 12.9) Operating features:  This is the very minimum arrangement for 5,000-10,000psi WP and one size of pipe only.  If a leak occurs to the top stripper then the lower stripper and one safety ram can be closed giving double barrier protection to allow repair and re-instatement of the strippers.  If the lower stripper leaks, both safety rams would be closed.  Two tree valves or a combination of both tree valves and blind rams must be available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial.  When the upper safety or blind rams are closed, the flow line and chokes can be used.  The safety rams should never be used for stripping unless in emergency situations.  With pipe in the hole, the blind rams can be changed to safety rams and the pipe can be reciprocated through the upper rams while retaining the two bottom rams in reserve.  The combination of shear and blind rams provide ultimate safety, if secondary well control fails.

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Figure 12.8 - Example 0-5,000psi Snubbing BOP Configuration

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12.4.9

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Snubbing BOP Arrangements 0-5,000psi WP

(Refer to Figure 12.8) Operating features:  This is the very minimum arrangement for 0-5,000psi WP and one size of pipe only.  If a leak occurs to the top stripper then the lower stripper and one safety ram can be closed giving double barrier protection to allow repair and re-instatement of the strippers.  If the lower stripper leaks, both safety rams would be closed.  Two tree valves must be leak free and available to be closed when stripping in the BHA, therefore spacing out to have enough distance to accommodate the BHA is crucial.  The safety rams should not be used for stripping unless in emergency situations.  There is no tertiary barrier system.

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12.4.8

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Testing Requirements

After the snubbing unit is installed, the integrity of the wellhead and the well control equipment must be established before operations commence. This is accomplished by a series of pressure test procedures to sequentially:  Test the tertiary pressure control system against a closed Xmas tree valve.  Test the secondary control system against the tertiary system.  Test the primary control system against the tertiary system. During pressure testing the pipe needs to be held by the snubbers to prevent ejection from the stack.

Figure 12.7 - Typical HWO/Snubbing Layout

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12.4.7

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Tubing Hanger Flange

A tubing hanger flange can be installed below the work window to enable a workstring to be hungoff; this allows work to be carried out on the jack, powerpack, stationary slips or stationary snubbers. A tubing hanger is installed on the workstring and the workstring lowered to hang the hanger off on the tie-down bolts. The tie-down bolts are fully engaged into a mating profile in the hanger. The engagement of the tie-down bolts prevents movement of the hanger either upwards or downwards. (Refer to Figure 12.6).

Figure 12.6 - Tubing Hanger Flange

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12.4.2

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Well Shut-In

If a well needs to shut-in due to a leak in the BOP stack, it is necessary to close the safety rams. To avoid closure of a ram on a connection, the location of the nearest workstring connections needs to be known and possibly the pipe moved accordingly. This may be time consuming and often an annular BOP is added to the stack to allow immediate well closure regardless of the positions of the connections. 12.4.3

Deployment of Long BHAs

If deploying long BHAs with varying diameters, it may not be possible to operate the stripper rubber or stripper rams due to a lack of distance between the wellhead and the strippers. In this case the use of an annular BOP is necessary to allow closure around the BHA until the pipe is across the strippers. 12.4.4

Annular BOPs

Tandem annular BOPs may be used when running non upset pipe, although most operators prefer to use stripper rams as annular rubbers are extremely difficult to replace in situ.. One of the annular preventors is contingency for damage to the first annular. There is a great advantage when using annular preventors in that there is no requirement for a bleed off or equalising line and, therefore, running speeds are faster. Annulars are also used to snub in long BHAs, which may vary in diameter, but most operators use an annular for quick shut-ins as the pipe does not need to be moved to avoid closing a pipe ram on a connection. 12.4.5

Safety (Pipe) BOPs

Safety BOPs are used for safety only. They are closed on the pipe to affect a seal when there is either a leak downstream, or when the stripper or annular rubbers need redressing. They differ from the stripper rams in that they may be dressed primarily for sealing against the pipe rather than stripping. 12.4.6

Shear/Blind BOPs

A set of shear and blind rams are installed as a tertiary barrier. To prevent the pipe dropping after severance, additional safeties are added below the shears.

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Figure 12.5 – Snubbing Process (continued)

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Figure 12.4 –Snubbing Process

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12.4.1

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Stripper BOPs

For upset pipe, two stripper pipe rams are used to affect a seal on the pipe. The unit operator, from a control panel located in the basket, operates these rams. They are regular ram type BOPs that are opened and closed in sequence to allow the upsets to pass into the well. The pressure trapped between the two stripper rams, when the lower stripper ram is closed, is bled off through a choke in the bleed off line. To open the lower stripper ram after closing the upper ram, pressure is equalised across the lower ram by the equalising loop. When more than one pipe size is being run, a set of stripper BOPs for each size must be included in the rig up. To repair a damaged stripper ram, normally two safety pipe rams are closed on the pipe to provide two barriers (in some areas of the world this convention is not recognised). Stripper Ram Operation

The process of snubbing collared pipe into the well is shown in the schematics in Figure 12.4 and Figure 12.5. It involves the sequential opening and closing of the upper and lower stripping rams to lubricate the connections into the wellbore, and also requires the operation of the equalising loop and bleed-off line. The sequence is as follows: 1) The pipe is jacked through the upper stripper ram until the connection is positioned immediately above the ram. 2) The lower stripper ram is closed on the pipe and the equalising loop remote operated valve is closed. The pressure between the two stripper rams is now bled off through the bleed-off line by opening the remote controlled valve. Flow is controlled by the choke. The upper stripping ram is then opened. 3) The connection is now jacked down until it is positioned between the two stripping rams. The upper stripper ram is closed again and the bleed-off line valve closed. The equalising loop valve is then opened allowing well pressure through the fixed choke up below the upper stripper ram. The lower stripper ram can now be opened. 4) The connection is now snubbed into the wellbore and the sequence is repeated for all the other connections.

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Figure 12.2 - Stripper Assembly

Figure 12.3- Double Stripper

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Stripper Rubber

If snubbing pressures are below 3,000psi and a workstring with flush joint or tapered connections such as drill pipe or Hydril are being used, it is preferable that a stripper rubber be used as it is not necessary to operate the stripper rams. The stripper rubber is self energising (Refer to Figure 12.2) and the crew simply require to pick-up, install, and snub the pipe through the stripper into the Well. However, the stripper rubber will wear and usually needs to be changed out during long trips. Closing the stripper or the safety rams, allows safe retrieval of the worn rubber and re-instatement of a new unit. ‘Double’, ‘Tandem’ or ‘Two Stage’ strippers are used to allow the running and pulling of greater lengths of pipe before requiring to change the stripper rubbers. By installing a double stripper, the upper rubber can be used first, and when it begins to leak, the lower stripper rubber is brought into use by closing the well pressure by-pass.(Refer to Figure 12.3). When collared tubing is to be run, the stripper rubber cannot be used.

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12.3.20

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The Snubbing Process

The understanding of the process of snubbing pipe into a live well through the BOP system is fundamental to pressure control. The BOP rig-up must be such that it can allow snubbing of the pipe and provide suitable secondary and, if required, tertiary barrier systems.

12.4 Snubbing Equipment Most of the equipment used in snubbing operations consists of ram and annular type BOPs and chokes that are already described in Appendix C. A typical snubbing rig-up for various well pressures, pipe sizes, are shown in Section 9. They effectively consist of the equipment described in the following sections. The configuration of a snubbing stack is generally: From top to bottom:  Stripper Bowl (Optional)  Stripper Rams/Annular BOPs (Optional). Used to seal around the pipe when snubbing. If using more than one pipe size there must be a set of safety rams for each pipe size or a set of variables. The rams are dressed with inserts to allow stripping of the pipe.  Safety Rams Safety rams are essentially the same as stripper rams except they are used solely for safety. Safety rams may also be situated below the blind and shear rams.  Blind Rams Blind rams are used to seal off the open hole. They seal when the elastomers on each ram meet. They will not seal when there is pipe across them.  Shear Rams. Shear rams have the ability to cut the pipe. There is no seal on this function. Extreme caution should be taken when functioning any of the rams, as accidental functioning of the shear rams could potentially be very dangerous and, at best, cause a fishing job.

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Figure 12.1 - Typical Snubbing/HWO Unit

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12.3.18

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Strippers

The strippers control well pressure when snubbing or any time surface well pressure is encountered if it is less than 3,000psi. It is a self energising unit that utilises the Well pressure to activate the rubber. There are a variety of stripper rubber materials for different pressure regimes and Well fluids. These will vary in Well life according to their resistance to the Well fluids, gas or erosion due to roughness of the wall of the pipe being run, or pulled. Strippers cannot be used when running collared pipe or any pipe with sharp shoulders on the connections. 12.3.19

Circulating System

Pumps, chiksans, kelly hose and a circulating swivel are the main components of the circulating system. The pumps are generally high-pressure rated in order to cope with the maximum anticipated circulating and surface pressure. If nitrogen is to be used, the hose and chiksans should be suitably rated for such service. The stab-on safety valve (stabbing valve or kelly cock), must always be installed between the kelly and the swivel to allow safe changing of the hose or swivel, if necessary.

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IWCF – Well Intervention Pressure Control

12.3.12

Client: WATTAYA TRAINING SERVICES

Control Panels

The main control panel is mounted in the workbasket and is usually in two sections, one for the operator’s use and one for his assistant. From here, all of the unit functions are controlled, generally shared between them with the exception of the BOP shear rams, which are normally operated from another control panel located on the deck. (Some companies replicate the Basket Control Panels at ground level for emergency response). 12.3.13

Power Pack

The power pack and its accessories consist of a diesel engine and hydraulic pumps. The output from the pumps is regulated to the various pressure ratings of the hydraulic functions. It displays the various function pressures on gauges. 12.3.14

Hose Package

The hose package transports the hydraulic fluid to and from the various functions, some of which are high up on the unit and are therefore of considerable length. Some of the hoses can experience very high pressures and must be thoroughly tested before use. 12.3.15

BOP System

The BOP configuration is dependent upon whether the HWO unit is being used as a rig on a Well that has been killed, or in the snubbing mode rigged up above the Xmas tree. If on the former, the BOP configuration will be like that in a drilling situation, and may be covered by the operator’s Well control policies and procedures. If on a snubbing job, the configuration is quite different being rigged up above the Xmas tree. Refer to Section 9.2 for all well control equipment and procedures. 12.3.16

Equalising Loop

The equalising loop is used for equalisation of pressure across the lower stripper BOPs. (Note: BOP rams can only be opened when pressure is equalised otherwise the ram seals will be damaged). The loop connects from below the upper stripper ram to below the lower stripper ram. The remote operated valves are controlled from the workbasket to equalise or isolate the upper rams. The loop also contains a fixed choke to control the flow rate, and a set of manual valves to enable repair of the remotely operated valves. Hence, the manual valves are located to the inside of the remotely operated valves. 12.3.17

Bleed-Off Line

The bleed-off line is used for bleeding off the pressure below the upper stripper ram enabling it to be opened. It connects from below the upper stripper ram to the pits or safe bleed-off area. It also has a remotely operated valve, (Hydraulic Control Valve, HCR), a manual valve, (always on the ‘inside’ of the HCR in order to effect repairs to the HCR if necessary), and a choke for flow control. If the choke is located in permanent pipe it will be a fixed choke or alternatively, if it is in temporary pipe it will be an adjustable choke.

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IWCF – Well Intervention Pressure Control

12.3.3

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Splined Tube

Some units have a splined tube which passes rotational torque force generated by the rotary table through to the bottom plate and hence to the wellhead. If a splined tube is not used, the forces are transmitted through the hydraulic cylinders possibly reducing the operating life. 12.3.4

Access Window

The window is installed at the base of the jack between the stationary slips and the stripper and is the access for stripper rubber change out, installing tools in the string, and running the control line to safety valves. 12.3.5

Travelling Slips

The travelling slips are attached to the upper end of the jack and grip the pipe to hold it in the pipe heavy mode (when the pipe weight is greater than the force of well pressure). There are two sets, one set for snubbing termed snubbers or lights and one set for lifting termed slips or heavies. As a pipe is snubbed into the hole, it comes to a balance point, which changes from pushing to holding back weight, the point the lifting slips take over. There are pressure control risks when moving past the balance point and the companies have procedures to help overcome these risks. 12.3.6

Travelling Snubbers

The travelling snubbers are the inverted slips described above used to hold the pipe in the pipe light mode (when the force of well pressure is greater than the pipe weight). These are also attached to the upper end of the jack and grip the pipe to push it into the hole. 12.3.7

Stationary Slips

The stationary slips are located below the jack and above the access window and hold the pipe while the travelling slips are released for the next stroke. 12.3.8

Stationary Snubbers

The stationary snubbers are also located below the jack and above the access window and hold the pipe while the travelling snubbers are released for the next stroke. 12.3.9

Power Swivel

The swivel is used for rotating the pipe for drilling or milling operations. It, like the other systems, are hydraulically powered and controlled from the control panel. 12.3.10

Power Tongs

Power tongs are used to make up and break out the pipe connections. They are located in the workbasket and controlled hydraulically from the control panel. 12.3.11

Work Basket

The workbasket is the work platform of a HWO unit and is located at the top of the hydraulic jack, and on which the operator and assistant perform the manual functions including the picking up, laying down, stabbing, making up or breaking out of the pipe joints.

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IWCF – Well Intervention Pressure Control

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The main elements (refer to Figure 12.1) of an HWO unit are as follows:                   

Hydraulic jack assembly Guide tube Splined tube (only on Halliburton units) Access window Travelling slips Travelling snubbers Stationery slips Stationery snubbers Rotary power swivel Power tongs Work basket Control panels Hydraulic power pack Hose package BOP system Equalising loop Bleed-off line Strippers Circulating system.

HWO units are supplied in a range of lifting capacities (lbs in thousands), 60K, 90K, 120K, 200K, 250K, 400K and 600K. Snubbing capacity is half of this rating. When used instead of a conventional drilling or workover rig, the Well would be killed and plugged, the Xmas tree removed and BOPs installed on the casing head. It can also be used for recompleting Wells as it has the capability to run and pull completion strings by running the downhole safety valve control line through the access window. 12.3.1

Hydraulic Jack Assembly

As described earlier, the jack assembly consists of one or more hydraulic cylinders that travel in a vertical direction to move pipe in or out of the hole. For higher snubbing or lifting power, more cylinders are added into the system, which reduces running speed, unless larger capacity pumps are used. The operator controls the hydraulic power to the jack as the weight of pipe changes, or as the weight of pipe overcomes well pressure, and changes from snubbing to lifting and visa versa. 12.3.2

Guide Tube

This is simply a tube, which prevents the bucking of the pipe under snubbing forces. It should be sized to be just larger than the particular tubing to be run or pulled to constrain lateral movement. It travels up and down with the hydraulic jack.

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IWCF – Well Intervention Pressure Control

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12.3 SNUBBING/HYDRAULIC WORKOVER UNITS (HWO) The Snubbing/HWO Unit is a well service unit utilised for both snubbing and dead well servicing. Snubbing is the process of ‘tripping pipe in a well which has a surface pressure great enough to eject the pipe if no restraining force is applied’; this is termed the ‘pipe light’ mode. Stripping is the term for moving pipe through a rubber element to contain pressure whether it is in the snubbing mode or ‘pipe heavy’ mode (where the pipe is too heavy to be ejected). In practice, however, snubbing has come to mean all of the operations conducted on a live well. The HWO unit is also used in place of a conventional drilling or workover rig on dead Well servicing as it is easily mobilised, has a small footprint and is cost effective in comparison to mobilising a workover rig. They are also very useful when working in confined spaces and with small diameter (macaroni) pipe where a drilling rigs instrumentation is generally not sensitive enough. An HWO unit would only be used before CT on a snubbing job where:  There is insufficient space above the wellhead or deck space.  Rotational torque is required on the pipe that is greater than that available from downhole motors.  Pressures exceed the rating of CT pipe i.e. circa 5,000 psi burst and collapse.  Horizontal wells with extended reach. The first snubbing units were mechanical units using mechanical advantage in order to force the pipe in the hole against Well pressure. In the development of the hydraulic type unit, the power to raise and lower the tubing was provided by a set of hydraulic rams, through a set of bi-direction travelling slips or snubbers.

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IWCF – Well Intervention Pressure Control

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12.2 BARRIER PRINCIPLES A combination of pressure control barriers is used in snubbing operations to provide both internal pipe and external pipe pressure control similar to coiled tubing operations addressed in the next chapter. For external pressure control the barriers during normal operations are stripper rams, annular BOPs and BOP pipe rams. The stripper rams or annular BOPs are considered as primary barriers and the safety BOPs as secondary barriers. The internal primary barriers during normal operations are double BHA check valves. An advantage of snubbing over coiled tubing is that a secondary wireline installed check valve can be run into the BHA on failure of the other check valves and is the secondary barrier. BOP shear/seal rams are barriers on both sides and are considered tertiary barriers. 12.2.1

Snubbing Arrangements

Snubbing operations with an HWO unit entails installation of the well control equipment onto the top of the Xmas tree for ‘through-tubing’ work. BOP configurations for snubbing operations are shown in the following sections. The arrangements shown illustrate the use of a stripper and stripping pipe rams but an annular preventer can also be installed between the stripper and the stripper rams when required to deploy long BHAs, or for fast shut-ins without having to position connections away from the safety (pipe) rams. Workstring BHAs also contain barrier systems for primary and secondary pressure control as show in section 12.5. NOTE:

The snubbing configurations shown are generic and may not conform to individual service companies’ policy and procedures. There is no API standard for snubbing well control equipment and development of the method has been driven by the users. The configurations listed meet the absolute minimum and it would be common practice for additional safety to be added.

The schematics are for one pipe size only and if two pipe sizes were to be used then two sets of safeties would be needed, or variable rams installed. This would then allow double barrier protection for changing the stripper ram sizes.

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12 SNUBBING OPERATIONS A HWO unit is utilised on both live well interventions and dead well workovers. When utilised on workovers, the well control is similar to a rig operation, requiring the well to be killed and plugged and the Xmas tree replaced by a BOP stack on the casing head. The only difference in well control equipment may be in the work strings used where check valves may be installed to the BHA as additional primary well control. In place of the rig circulation system, pumps, tanks, mixing hoppers and hard piping would have to be provided unless the operation was rig assisted. It is essential that prior to any snubbing/HWO operation the safety issues are addressed. Reference should be made to relevant sections of the appropriate Safety Manual. At the safety meeting all aspects of the operation and detailed contingency plans should be discussed. Snubbing/HWO emergency procedures will form the basis of these contingency plans. Of particular importance are the aspects of Well Control Procedures. Under no circumstances should safety be compromised. Procedures should be observed, work permits strictly adhered to, and equipment operated within designed parameters. Aspects of well control must be included in the planning and equipment selection process. Snubbing operations are performed on live wells, and particular emphasis must be given to the required well control competencies and equipment to be used for each individual application. However, when used in snubbing operations, the pressure control systems are significantly different. The equipment arrangements for snubbing operations are described in the sub-sections below. 12.1.1

Pressure Control Requirements

Pressure control requirements for workover operations are covered in API RP 53. These documents do not, however, address snubbing operations. The expertise within the industry is with a small group of specialised contractors, who posses the required equipment and competence. However, it is incumbent upon the asset holder (or his delegated representative) to ensure that all activities carried out on the asset (the well) are conducted in a manner to provide for complete well control.

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SECTION 12 SNUBBING OPERATIONS

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NOTES PAGE

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NOTES PAGE

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11.4.4

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Tubing Pinhole Leak

The tubing develops a leak at the surface. In this particular situation the procedure is relatively simple: 1) 2) 3) 4) 5) 11.4.5

Stop the coiled tubing, run the pinhole back into the well Inform the company representative, make contingency plan Monitor the pressure in the tubing. The pressure should bleed down If the pressure drops and the check valves are holding Pull out of the hole spooling the pinhole onto the reel. Tubing Ruptures

This assumes the tubing ruptures as it comes over the gooseneck and separates. Initially this can be a potentially hazardous, and serious situation. The seriousness is dependent on the tubing’s internal pressure, the wellhead pressure, and the type of medium within the tubing. The procedure is: 1) 2) 3) 4) 5) 6) 7) 8) 11.4.6

Stop the coiled tubing. Inform the company representative. Let the pressure in the tubing bleed down. If the pressure drops and the check valves are holding. Pull rupture to deck level and splice tubing. If it appears that the check valves are not holding. The shear seal should be closed and the well secured. Prepare to fish coiled tubing. Tubing Separates Downhole

If the tubing separates downhole the procedure becomes a little more complicated but less hazardous if conducted correctly: 1) 2) 3) 4) 5) 6) 7) 8)

Stop the coiled tubing. Establish approximately at what point the tubing parted. There is a need to consider the possibility of killing the well. Assuming the well is in a safe condition, pull out of the hole slowly to a pre-determined depth. Start closing the swab valve counting the turns to establish when the coiled tubing is above the tree. Once the end of the tubing is above the swab, shut in the well using the upper and lower master valves. Bleed down the riser and pull the end of the tubing to surface. Prepare to fish the lost coiled tubing.

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IWCF – Well Intervention Pressure Control

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11.4 EMERGENCY PROCEDURES All procedures are dependent on a combination of the position of the tool string in the wellbore and the wellhead pressure. 11.4.1

Platform Shutdown

In the event of a platform shutdown, the ongoing operations must be suspended and the well made safe. Individual installations will have their own specific shut-in procedures and will be made known before commencement of coil tubing operations. The well is usually made safe by carrying out the following procedure: 1) 2) 3) 4) 5) 6) 11.4.2

Stop the coiled tubing. Stop pumping fluids. Close the slip rams. Close the tubing rams. Await further instructions. A decision should be made to close the shear/seal on top of the wellhead. Stripper/Packer Element Leak

The stripper/packer should be energised sufficiently enough by hydraulic pressure, so that it will contain the well bore fluids, but not restrict the running of the coiled tubing. Should the element begin leaking and it cannot be energised enough to stem the leak, the following procedure should be implemented: 1) 2) 3) 4) 11.4.3

Stop the coiled tubing. Close the tubing rams. Inform the company representative. Form a remedial plan. Leak between the Top of the Tree and the Stripper/Packer

In the above situation the following should be implemented: 1) Stop the coiled tubing. 2) Inform the company representative. 3) Depending on the severity of the leak, a decision should be taken about closing the shear seal.

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11.3.5

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Pressure Control Equipment Considerations

The style of stripper/packer in relation to the operation requires consideration. On a conventional stripper/packer it may take over 45 minutes to change the elastomers with pipe in the hole. To change the elastomers in a side door stripper/packer, may take as little as 5 minutes. A tandem stripper/packer should be employed to serve as an additional well barrier in high wellhead pressure situations. A tandem stripper/packer it will add approximately 4ft. to the stick up height that needs to be considered. BOPs are now available in several different configurations. The standard is a quad, i.e.; with four separate ram functions. The trend now is to combine the rams to form combi BOPs. The most common configuration is the triple combination. This BOP combines the two top functions and eliminates the need to pull pipe as is necessary after the shear on the quad. The shear/seal is a large single cut and seal device. This is normally flanged on top of the wellhead and used only as a last resort. The shear/seal usually is of a size equal to the wellbore, and is capable of cutting the toolstring. Control Hoses

On a semi-submersible the injector and the BOPs may be a considerable height above the drillfloor. This must be considered with the position of the power pack and control house, whereby extensions to the control hoses may be required. Similarly on a platform, if the coiled tubing is to be run from the pipe deck to the skid deck, the control hoses may again require extensions. Support Stand

The standard type support stand is manually operated and requires constant monitoring in live well situations. If the operation is performed with the well on production, and cold liquids introduced through the coiled tubing this will cause the riser to contract, the support stand may become trapped under the injector. A hydraulic support type stand has built in relief valves to release the pressure should the riser shrink. Tie Back Points

The use of tie-down points requires the need to have similar tie-back points on the injector. Under normal circumstances injectors are not fitted with this facility. If the frame is to be used ensure that the attaching points are tested and are fit for purpose. Pre-Job Safety Checks:  Have the BOPs been adequately pressure tested ?  What is the maximum expected well pressure ?  Can the injector snub against this pressure without buckling the coiled tubing ?  Will the shear rams cut the coiled tubing against this pressure ?  Is a tandem stripper/packer required ?  Is an extended tool, pressure deployed system required ?

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11.3.4

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Rig Floor Equipment

There should be enough rig floor tuggers capable of pulling the injector into position for stabbing onto the BOP with sufficient lifting capacity. There should be two for the injector positioning, one to install the toolstring and one or more for man riding. The tie down points must be designed and certified for the job. Rig floor working space should not be restricted with unnecessary items of equipment or tubulars in the derrick. The main access and emergency exit points should not be restricted. Refer to Figure 11.19 DRILLING RIG

CRANE PEDESTALS

COILED TUBING

RADIUS

PACKAGES

OF SAFETY

Figure 11.19 - Radius of Safety

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11.3 Operational PLANNING AND SAFETY 11.3.1

Introduction

Initially look at the different factors that control any Coiled Tubing operation. These factors when combined in the right order, and planned properly, will see the completion of a successful coiled tubing operation. 11.3.2

Operational Considerations

Gas Well

Gas wells cause undue wear to stripper rubbers and, hence, it may be necessary to provide an additional stripper/packer, to complement the standard package. High Wellhead Pressure

Use of coiled tubing in high pressure situations, require a thorough check of certain aspects pertaining to the well control equipment. For example, the pressure rating of the equipment, back-up stripper/packer or annulus preventer and the capability of the hydraulic system to, either, shear or affect a proper seal around the tubing. Toolstring Length

The operation will dictate the length of the tool string that in turn may affect the rig up, e.g. length of riser, pick up height of the injector and stick up height of well control equipment. Toolstring Deployment Systems

Novel deployment systems have been developed for the deployment of extra long toolstrings such as TCP type perforating guns. These systems provide barrier protection when the toolstring is being made up and lubricated into the well. Such systems may require the assistance of a wireline unit and crew. 11.3.3

Working Location

Type of Rig

A semi-submersible drilling or workover vessel requires the addition of a heavy duty lifting frame installed between the block and the surface tree in which to support the injector and BOPs. Drilling rigs can usually accommodate the width of injectors quite easily but in certain circumstances the ‘A’ frame height can be restrictive. Workover rigs tend to have smaller ‘V’ doors than conventional drilling rigs, and dimensions of this should be checked against the injector size available. On land well operations where there is no means of holding back the injector against the pull of the tubing from the reel, an adjustable stand is required to support the forces with the ground.

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Figure 11.18 - CT BOP Configuration with Shear Seal BOP

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Figure 11.17 - Standard CT BOP Configuration

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11.2.3

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Coiled Tubing Standard BOP Configuration

(Refer to Figure 11.17). Figure 11.17Operating features:  The stripper is adjustable for well pressure up to manufacturers max pressure rating (Manufacturers data).  If the stripper fails, the pipe rams can be closed to allow repair.  If the tubing is broken and falls down hole, the blind rams are closed along with a Xmas tree valve provided the tubing is clear of the tree.  If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery; hence the tree valves cannot be used. 11.2.4

Coiled Tubing BOP Configuration with Shear/Seal BOP

(Refer to Figure 11.18) Operating features:  The stripper is adjustable for well pressure up to manufacturers max pressure rating (Manufacturers data).  If the stripper fails, the pipe rams can be closed to allow repair.  If the tubing is broken and falls down hole, the blind rams are closed with a Xmas tree valve, providing the tubing is clear of the tree.  If the rams leak, the tubing can be cut with the shear rams and the blind rams closed. The tubing is held in place with the slip rams to aid in recovery; hence the tree valves cannot be used.  Tertiary well control is provided by the shear/seal BOP and is the final and last resort in the event of secondary well control failure.

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11.2.2

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Coiled Tubing Tooling

Tooling can be categorised into standard toolstrings and specialist tools. These toolstrings contain the standard tools used in all applications to which the specialist tools are attached. The complete assembly is referred to as the Bottom Hole Assembly (BHA). A typical toolstring contains:  Tubing connector  Dual flapper valves  Emergency release sub. Optional standard tooling:  Circulating subs  Swivels  Bull noses. Specialist tooling:       

Downhole motors Jetting nozzles Wireline type hydraulic operated tools Through tubing packers Bridge plugs Perforating guns Logging tools

The dual flapper valves are an integral element in well control as they contain well pressure from the inside of the tubing. The dual flappers give double isolation and meet most legislative requirements. Therefore, when the BOP tubing rams are closed well pressure is contained to both below the rams and from the tubing, hence the well is safe for corrective actions. A split in the tubing below the BOPs circumvents the dual flapper seals and, in this situation, the shear rams would be closed to contain well pressure.

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IWCF – Well Intervention Pressure Control

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11.2 Pressure Control equipment 11.2.1

Check valves

Check valves are installed in the coiled tubing BHA above the disconnect sub. They provide primary inside pressure control. The four most common types used are shown in Figure 11.13, Figure 11.14, Figure 11.15 and Figure 11.16

Figure 11.13 - Ball Check Valve

Figure 11.15- Flapper Check Valve

Figure 11.14 - Dome Check Valve

Figure 11.16 - Removable Cartridge Flapper Valve

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11.1.9

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Tubing

There are a number of coiled tubing manufacturers but they are mainly U.S. or Japanese companies. Some of the US companies use Japanese supplied steel for tubing manufacture. The normal method of tubing manufacture is to produce rolled plate steel that is cut into long flat strips. Each strip is then progressively folded round with rollers and formed into a long spiral. When it is completely formed into a round tube, the edges, now abutting, are welded. These individual lengths are then welded together to produce the length required to be contained on a shipping reel. Continuously milled tubing has now been introduced but is much more costly. The common steel used is an American alloy grade ‘A606’ type 4 modified, suitably quenched and tempered, which provides the best economic combination of ductility and strength to combat the cyclic bending stresses. By specially selecting billets from the furnace to meet particularly tight tolerances of chemistry, higher grades can be produced such as ‘QT-800’. More exotic pipe materials are also being manufactured but have cost penalties. 11.1.10

Barrier Principles

A combination of pressure control barriers are used in coiled tubing operations to provide both internal pipe and external pipe pressure control. For external pressure control the barriers during normal operations are stripper/packers, annular BOPs and BOP pipe rams. Strippers or annular BOPs are considered as primary barriers and the BOPs as secondary barriers. The internal barrier during normal operations is double BHA check valves. Both check valves together are considered as the primary barrier and the BOP cutter rams secondary. BOP shear/seal rams or cutter gate valves are barriers on both sides and are considered tertiary barriers.

IWCF – Well Intervention Pressure Control

Figure 11.12- Pressure Control Stack Up

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Figure 11.11 - Shear/Seal Actuator Assembly

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11.1.8

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Shear/Seal

This device is usually a 61/8” bore combination ram with single cut and seal rams. (Refer to Figure 11.10) This provides a single cut/seal function for installation safety and is the tertiary barrier. In the event of a platform emergency, a designated person is responsible for its closure, but normally the platform manager’s permission is sought, time permitting. To illustrate the main components of a typical hydraulic ram, a sectioned drawing of a shear/seal actuator is illustrated. (Refer to Figure 11.11). Figure 11.12 shows the height of a typical stack up arrangement using a dual combination on the tree, a triple combination BOP, a quick union connector, a tandem and standard stripper/packer.

Figure 11.10 – Shear/Seal Single BOP

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Figure 11.9 - Pressure Control Stack Up

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Figure 11.8 - EH34 Quad BOP

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Figure 11.7 = Coiled Tubing Quad BOP

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Figure 11.6 - Quad BOP Cutaway

A combination BOP incorporates the functions of two upper and the two lower types of rams into one unit, and in so doing reduces rig up height and simplifies the control system. However, it would be necessary to alter the well control procedures accordingly. A triple combination is a model that has a slip ram (bottom) pipe ram (middle) as well as the combination shear/blind rams (top). A triple combination combined with two radial stripper/packers provides a shorter stack up than a conventional stack-up, (refer to Figure 11.9)

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11.1.7

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BOP System

The BOPs are very similar in function to wireline BOPs and are mounted above the wellhead adapter. They usually have four sets of rams dressed as follows, top to bottom:    

Blind Shear Slip Pipe.

The shear rams usually have the ability to cut stiff wireline i.e. coiled tubing with electric line cable inside it, used on coiled tubing logging operations. In some areas of the world, an additional Shear/Seal valve is installed between the BOPs and the wellhead adapter as a tertiary barrier. The shear seal valve has the ability to cut the tubing and affect a seal. It is generally tied into a higher volume hydraulic pressure supply than available from the coiled tubing unit such as a rig Koomey or independent system etc. The BOP is the secondary/tertiary barrier in pressure control. As a failsafe device, the BOP should only be operated as a safety device, and with careful consideration, and not used for any other use such as a means of “parking” the tubing while at depth. A standard quad BOP is configured with four rams. (Refer to Figure 11.6 and Figure 11.8) From top to bottom: Blind Rams

Blind rams only seal on open hole when the elastomers on each ram meet and seal. If there is pipe across the ram area the seal cannot be affected. This type of ram does not hold pressure from above.

Shear Rams

Shear rams have the ability to cut tubing. When using CT logging i.e. tubing with logging cable through it, the shear rams must have the capability to cut both. There is no seal on this function. Extreme caution should be taken when functioning any of the rams as accidental functioning of the shear rams could potentially be very dangerous, possibly causing a fishing job.

Slip Rams

The slip ram is designed to hold the full tubing weight, and it too has no sealing function. Caution should be used when considering the use of these rams as the slip toolface can significantly mark the tubing and induce an area where premature cracking can occur.

Pipe Rams

Pipe or Tubing rams are used to affect a seal against the tubing. Wellbore pressure aids in the sealing of the ram when a differential is created, by bleeding off above. This type of ram does not hold pressure from above.

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Figure 11.5 - Radial Stripper/Packer

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Figure 11.4 - Tandem Sidedoor Stripper/Packer

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Figure 11.3 - Side Door Stripper/Packer

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Figure 11.2 – Conventional Stripper/Packer

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11.1.5

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Injector

The injector is the motive device that imparts upward or downward movement to the tubing and is mounted above the BOPs on the wellhead. It must be supported, as the connection to the BOPs is not designed to absorb the weight and lateral forces caused by the tension in the tubing from the reel. This support can be a crane for land wells (providing the lifting gear and pad eyes are rated for the weight of equipment and forces encountered), or to a mast or derrick offshore. Freestanding frames with hydraulic jacking legs are also available where no other means of rigging up is available. Hydraulically driven travelling chains equipped with gripper blocks impart movement to the tubing. The gripper blocks grip by friction that is adjustable through a hydraulic piston applying pressure across the chains. This pressure must be sufficiently high enough to grip the tubing, eliminating slippage, but not excessively high to crimp the tubing. 11.1.6

Stripper/Packer

The stripper is situated below the injector head in the injector head frame. It is designed to be as close as possible to the gripper chains to prevent buckling due to snubbing forces. The stripper is hydraulically controlled to press the rubber element against the tubing to create a seal. The stripper rubber is exposed to wear from the roughness of the pipe OD, and will need to be changed from time to time. This can be done on the wellhead by closing the BOPs and removing well pressure. The stripper/packer is located at the top of the pressure control stack-up attached to the injector head and is the primary pressure control barrier. It is constantly energised throughout the coil tubing operation to affect a seal against the tubing. (Refer to Figure 11.2, Figure 11.3, and Figure 11.4) As it is in constant use, on high pressure or gas wells, the elastomer sealing element can wear out quite rapidly, hence the contingency requirement for a back-up stripper or annular BOP. An example of such a rig up is shown in Figure 11.9. As stated above, this back-up unit would only be brought into use if the first packing element failed. Used in conjunction with the tubing rams in the BOPs, this provides an additional barrier and allows safer access to change the worn elastomers in the first stripper. In other circumstances the back-up stripper may be used to allow operations to continue without having to repair the first stripper Because of the increased height due to using tandem stripper/packers, an alternative radial stripper/packer; shown in Figure 11.5. can be used. This reduces the stack up height by about half and makes changing the elastomers a very simple task.

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IWCF – Well Intervention Pressure Control

Figure 11.1 - Typical Coiled Tubing Unit

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These bending cycles force the tubing to exceed its elastic limit inducing fatigue, and, therefore, reducing the working life before failure. Tubing under pressure while passing over the reel and gooseneck dramatically decreases this cycle time to failure. Most coiled tubing service companies have developed computer programmes, using logging databases, to determine the time to failure for each tubing size and type of material to which a factor of safety is applied. This is an inexact science but, due to the safety factor, there are actually very few recorded well site incidents caused purely through tubing failure. More than likely, service life is much shorter than actual life. All coiled tubing units (Refer to Figure 11.1) are constructed similarly and consist of:        11.1.1

Operators control cabin Tubing reel Power pack Goose neck Injector head Stripper BOP system.

Operators Control Cabin

The cabin houses all of the controls for the reel, injector head and all electronic logging systems and instrumentation. The controls operate the hydraulic valves and pressure supplied from the power pack. It is placed directly behind the reel to provide the operator with a full view of all activities, especially the spooling of the tubing off and on the reel. 11.1.2

Tubing Reel

The reel stores the tubing that is coiled around the core of the reel. Ideally the core should be as large a diameter as possible to prevent severe bending of the tubing, but must be of a manageable size for transporting to and from well sites. The radius of the core of the reel is smaller than that of the goose neck e.g. 24” (4ft dia.) versus 72” for 11/4” tubing, hence most tubing fatigue is caused at the reel. The reel is driven by chain from a hydraulic motor controlled from the control cabin. The tubing is pulled off the reel, and up over the gooseneck by the injector. The reel holds constant back tension to prevent the spool unravelling and to keep the tubing steady. 11.1.3

Power pack

The power pack is the provider of all hydraulic power. It consists of a skid-mounted diesel engine and hydraulic pumps. It supplies regulated pressure for all the systems in the reel, injector head, BOPs and the control cabin. 11.1.4

Goose Neck

The gooseneck is simply a guide that accepts the tubing coming from the reel, and leads it into the injector chains in the vertical plane. The goose neck guides the pipe using sets of rollers in a frame spaced on the recommended radius for the tubing being run i.e. 72” with 11/4“ tubing etc.

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11.1 COILED TUBING UNITS Well servicing using coiled tubing (CT) has grown significantly with the development of tooling and tubing technology. In recent years the size of tubing available has increased from the original 1” through 11/4”, 11/2”, 13/4“, 2” and now up to 31/2”. These larger sizes are now being used as siphon strings, completions etc. but are not yet generally used as work strings. Along with this increase in size of tubing have come material improvements to give higher performance. Coiled tubing units have largely replaced snubbing units for operations on completed wells and their versatility, due to new tooling developments, has extended their range of capabilities in recent years. The range of services now provided includes:             

Drilling and milling using hydraulic motors Casing cutting Circulating Tubing clean outs (sand or fill) Cementing Through-tubing operations Tubing descaling Running, setting, pulling wireline pressure operated type tools Fishing wireline tools Logging (stiff wireline) Nitrogen lifting Selective zonal acidising Perforating.

Much of the recent increase in capability is due to the increased performance of downhole motors, which provides the ability to rotate, enabling drilling and milling operations etc. The limitation of coiled tubing is usually the pressure rating of circa 5,000psi. and the depth to which it can be run, constrained by its relative low strength. It is also limited in its service life due to the bending cycles over the reel, and to a lesser extent the goose neck, in conjunction with the service conditions it encounters.

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11 COILED TUBING OPERATIONS Coiled tubing operations are very similar in method to snubbing operations, except that the coiled tubing unit uses an injector head with travelling chains instead of a hydraulic jacking unit. The BOP stack, however, is simplified due to the coiled tubing being of smaller diameter and non-upset allowing a stripper to be used. Specialised BOPs have also been developed with gripper rams to cater for easier pipe retrieval if ever the pipe is sheared. All coiled tubing BHAs include double check valves for inside primary pressure control except in very special circumstances. When planning a coiled tubing operation, include a rough draft on well control requirements for the particular application. One of the main reasons for this is that it may be a significant factor regarding the amount of items required in the well equipment stack-up. Both the well characteristics and the type of operation should be considered as they determine the minimum size and type of well control devices that need to be employed to safely and successfully conduct the programme. In coiled tubing operations both internal and external pressure control must be assessed. ‘Internal’ refers to the inside of the coiled tubing and ‘External’ to the coiled tubing annulus. The typical Well Control Stack is:    

Stripper BOP Riser Shear Seal.

Starting from the top of the tree, many operators utilise a single shear/seal device that is flanged to the tree irrespective of well conditions and the operation to be carried out. This is generally a tertiary barrier. Other operators only use a shear/seal device when they deem it applicable. The bore diameter and cutting capabilities of the shear/seal will depend largely on the type of toolstring. On top of the Xmas tree or a shear/seal, if used, is a crossover flange to quick union sectional riser continuing to the operating level, i.e. rig floor or platform deck, with any additional stick up height that is required. The BOP is mounted directly on top of the riser using any crossovers that are required. The BOP can either be a conventional quad BOP, or the later style combination BOP’s. Combination BOP’s were developed to be shorter and therefore have less stick up. The stripper/packer or stuffing box attaches to the top of the BOPs. This piece of equipment is normally bolted to the underside of the injector head. A tandem stripper/packer, or even an annular BOP, can be installed between the standard stripper/packer and the BOP for additional safety, particularly when the well conditions may cause premature stripper rubber wear. Whichever combination of BOPs is selected in the stack-up for an operation, it should include a closed barrier to allow safe stripper/packer rubber replacement and a backup barrier.

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SECTION 11 COILED TUBING OPERATIONS

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NOTES PAGE

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NOTES PAGE

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10.3.12

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Safety Check Union

This device can be included in braided/stranded wireline Lubricator hook-ups just below the Grease Injection Head. The wire is threaded through both these units and in the event that the wire breaks, and is blown out of the Grease Injection Head, the well pressure will automatically shut off by the Safety Check Union. Shut-off is accomplished by the velocity of the escaping well effluents causing a piston to lift a ball up against a ball seat. (Refer to Figure 10.18) Well pressure holds the ball against the seat. This device does in fact fulfil the same function as the internal Wireline Valve in the solid wireline Stuffing Box. As with all Lubricator equipment, this Safety Check Union is furnished with Quick Unions.

Figure 10.18 - Safety Check Union

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Figure 10.17 - Grease Injection Rig Up

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Pneumatics

The drive air enters the unit via a bulkhead quick connect to a pressure control valve which is pilot controlled from the control panel, and also acts as a stop/start control. A separate supply is plumbed to the control panel into a three way, two position valve. Position one is where the supply is blocked with the reservoir vented to atmosphere, position two is where the supply air is directed to the reservoir via the reservoir lid pressure controller; both allow the operator an auto pre-set reservoir pressurisation or vent to atmosphere in one control valve. WARNING:

HIGH PRESSURE - Never allow any part of the human body to come in front of or in direct contact with the grease outlet. Accidental operation of the pump could cause an injection into the flesh. If injection occurs, medical aid must be immediately obtained from a physician.

WARNING:

COMPONENT RUPTURE - This unit is capable of producing high fluid pressure as stated on the pump model plate. To avoid component rupture and possible injury, do not exceed 75 cycles per minute or operate at an air inlet pressure greater than 100psi. (10 bar).

WARNING:

SERVICING - Before servicing, cleaning or removing any component, always disconnect or shut off the power source and carefully relieve all fluid pressure from the system.

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IWCF – Well Intervention Pressure Control

10.3.11

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Grease Injection System

The system is designed to deliver grease as demanded under continuous operation within the parameters of a single pump unit. There are two circuits on the unit for control/drive air and grease and both are described below: Grease System

The system pump draws grease from the grease reservoir through the pump suction tube and it is pumped to the outlet port that is split into two lines. One line delivers grease to the control panel vent valve, allowing the operator to vent grease pressure to atmosphere via a short hose into an alternate grease reservoir that is not in use. (This is normally permissible as grease from this source should be clean; however, care should be taken to isolate grease from airborne contamination). The other line is the grease supply line plumbed via a rotary valve to hose storage reels, and then to the appropriate grease head. (Refer to Figure 10.17) The grease return line via the hose reel, rotary valve, and system pressure gauge leads to a system pressure control vent valve from which the vented grease flow rate is controlled. This grease is plumbed (now at atmospheric pressure) through a short flexible hose to a waste grease container and should not be re-used as this may be contaminated. Excessive grease returns will indicate incorrectly sized flow tubes. NOTE:

If a 5/16” line is used, the supply pump must be fitted with at least a 3/4” ID hose to ensure adequate supply to retain the seal.

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Figure 10.16 - Electric Line Lubricator and Triple BOP

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Electric Line Lubricator/Triple BOP Stack Arrangement

(Refer to Figure 10.16Figure 10.15).

Figure 10.15 - Braided line Lubricator and Dual BOPs

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Flow Tubes

A range of flow tubes (refer to Figure 10.14) are available with small increments of IDs so as to provide an effective seal over the life of a wireline that reduces in size with usage. The OD. of the line should be measured and the size of the tubes selected for the closest fit (ID. of flow tubes should be 0.002” - 0.004” larger than OD of wireline, or 0.004” – 0.006” depending on whether conventional 1-6-9 line, or Dyform is used). Slip each tube in turn over the wire and physically check that they do not grip the wire as this can lead to ‘bird caging’ of the outer strands when running in the well. This is an effect where the drag on the outer strands gradually holds them back with regard to the inner strands, so they become loose and spring out from the cable like a bird's cage until they jam at the packing nut. If the packing nut is too tight it can also cause this same effect. (Alternatively, if the tubes are too big, they will not create an effective barrier and too much grease will be wasted)

Figure 10.14 - Flow Tube Schematic

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Figure 10.13 - Grease Injection Head

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The flow tubes are close-fitting around the wireline and they, along with the flow tube sleeves, form the main length of the grease head. This affords sufficient length to form an effective pressure barrier. The flow tube sleeves are simplified body parts that hold the various other components rigidly together and seal them. In addition, they are made of a very hard metal and the wire predominantly bears on them, preventing wear on the other parts. The flow tube coupling forms a junction for the flow tubes and also as the point of entry for the grease. The Hydraulic Packing Nut is a simple but efficient device that is remotely operated by a hydraulic hand-pump assembly. Pumping pressure into the cylinder actuates the Hydraulic Packing Nut. When a complete seal is established, the pressure is maintained by closing the valve at the hand pump assembly. Opening the valve and relaxing the seal relieve the pressure. Thus, the piston in the packing nut is retracted by a strong spring when the pressure is relieved from the piston. The body has a port and a flow hose to lead off any seepage that migrates through the line and finds its way above the flow tubes (refer to Figure 10.13). The optional differential air inlet pressure regulator valve, when used, controls the flow of grease to the control head that is supplied by the grease supply system. Ideally, the grease is delivered at a pressure of 200 psi. greater than the wellhead pressure if flow tubes are correctly sized. As flow tubes wear, or the Braided Line tightens, grease delivery may have to be delivered at pressures up to 1000psi, or even 2000psi maximum to retrieve the wire from the well.

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10.3.10

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Braided Line Lubricator/Dual BOP Stack Arrangement

(Refer to Figure 10.15) Operating features:  The grease seal pressure is adjustable for varying well pressures.  The lubricator is an intrinsic part of the primary well control system along with the grease seal.  If the grease seal fails, both the wireline BOP wire rams can be closed on the wire. The lower ram is inverted so that grease can be injected to create a seal.  If the wire is broken and expelled from the lubricator, two Xmas tree valves must be closed to provide double isolation.  If the rams leak, the wire can only be cut with a wire cutting actuator. Operating features:  The grease seal pressure is adjustable for varying well pressures.  The lubricator is an intrinsic part of the primary well control system along with the grease seal.  If the grease seal fails, both the wireline BOP wire rams can be closed on the wire. The lower ram is inverted so that grease can be injected between the rams to create a seal.  If the wire is broken and expelled from the lubricator, the blind ram plus a Xmas tree valve must be closed to provide double isolation (or two tree valves).  If the rams leak, the wire can only be cut with a wire cutting actuator.  If the Xmas tree Upper Master Valve is not a wire cutting valve, a Shear Seal Safety Head would be run directly on top of the tree. This results in the complete sealing and also lubrication of the wireline, which reduces friction. NOTE:

When calculating the amount of stem required to overcome the well pressure, a percentage must be added to compensate for friction.

The Grease Injection Control Head is composed of three flow tube sleeves*, a flow tube sleeve coupling, a quick union pin end, a flow hose and a line rubber and hydraulic packing nut assembly at the upper end. The amount of flow tube sleeve used depends on the well pressure. For 3/16” Braided Line:  3 flow tubes 0 - 4,000psi  4 flow tubes 4,000 - 6,000psi  5 or 6 flow tubes 6,000 - 10,000psi.

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Line Wiper

This is a tool that attaches to the hay pulley when the wire is being pulled to remove all contaminants from the wire before it is spooled. Grease Head

The grease head terminates the top of the lubricator. The grease head is used on braided line, electric line or plain cable. It seals around cable by grease being pumped, at higher pressure than that inside the lubricator, into the small annulus space between a set of flow tubes and the cable filling the cable interstices. The grease, being at higher pressure, tends to flow downward into the lubricator and also upward out of the tubes. The upward flow is forced out through a return line for disposal by activating a cable pack off above the tubes. Downward flow is only constrained by the differential pressure applied between the grease and the lubricator pressure. Adjustments must be made to maintain the optimum conditions between grease lost to the hole, amount of gas entrained in the grease returns and differential pressure. To supply grease under pressure the following equipment is required to rig up the Grease Injector Head:        

High pressure grease pump Grease reservoir Compressor Hoses Wiper box Grease injector head assembly Sheave Crane or draw works.

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IWCF – Well Intervention Pressure Control

Figure 10.12 - Slickline Lubricator and Dual BOP

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10.3.9

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Slickline Lubricator/Dual BOP Stack Arrangement

(Refer to Figure 10.12) Operating features:  The stuffing box is adjustable (manually or more commonly hydraulically) to cater for packing wear.  The lubricator is an intrinsic part of the primary well control system along with the stuffing box.  If the stuffing box leaks, the upper wireline BOP wire/blind rams can be closed on the wire to repair the packing.  If the upper rams leak, the lower rams can be used.  If the wire is broken and expelled from the lubricator, both rams can be closed to provide double isolation.  If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

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IWCF – Well Intervention Pressure Control

Figure 10.11 - Slickline Lubricator and BOP

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10.3.8

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Slickline Lubricator/Single BOP Stack Arrangement

(Refer to Figure 10.11) Operating features:  The stuffing box is adjustable (manually or more commonly hydraulically) to cater for packing wear.  The lubricator is an intrinsic part of the primary well control system along with the stuffing box.  If the stuffing box leaks, the wireline BOP wire/blind rams can be closed on the wire to repair the packing.  If the rams leak, the wire can be cut with a wire cutting actuator or the upper master valve, although this may lead to valve damage.

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IWCF – Well Intervention Pressure Control

10.3.7

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Hydraulic Packing Nut

The Hydraulic Packing Nut assembly (Refer to Figure 10.10) is designed for a standard Wireline Stuffing Box to allow remote adjustment of the packing nut. This method is a safe and convenient way of regulating the packing nut. Regulation is made from a ground position by means of a hydraulic hand pump and hose assembly. Benefits

The need for a person to climb the lubricator is eliminated. The hand pump is positioned away from the nut itself so possible contact with escaping well fluid can be avoided. Operation

The Hydraulic Packing Nut Assembly includes a piston which has a permissible travel of 0.4” enclosed in a housing. The housing has a 1/4” NPT connection for a hydraulic hose. As hydraulic pressure is applied the piston is moved downward against the force of the spring. This downward action is transmitted to the upper packing gland and causes the Stuffing Box packing to be squeezed around the wireline, sealing off well fluids within the Stuffing Box.

Piston 90o Elbow Housing

Valved Nipple

O-Rings Grub Screw Piston Spring

Piston Housing

Stuffing Box Housing

Figure 10.10 - Hydraulic Packing Nut

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IWCF – Well Intervention Pressure Control

Figure 10.9 - Wireline Stuffing Box

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10.3.6

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Stuffing Box

The Stuffing Box (refer to Figure 10.9) is a sealing device connected to the top of the Lubricator sections, and in conjunction with the lubricator is the primary pressure control on the well. It allows the wireline to enter the well under pressure and provides a seal should the wireline break and is blown out of the packing. The Stuffing Box will cater for all sizes of slickline, but the size of the wire must be specified to ensure the correct sheave size is installed. If the wireline breaks in the well, the loss of weight on the wire at surface allows well pressure to eject the wire from the well. To prevent well fluids leaking out the hole left by the wire, an Internal Blow Out Preventer Plunger is forced up into the Stuffing Box by well pressure, and seals against the lower gland. A packing nut and gland located at the top of the Stuffing Box can be adjusted to compress the packing and seal on the wireline. Hydraulically controlled Packing Nuts are available to ease operation should the packing require to be compressed during wireline operations. These are controlled remotely by a hand pump, and this avoids the need for manual adjustment of the Packing Nut. For wireline operations, the top sheave is normally an integral part of the Stuffing Box. This reduces the rig up equipment required and the large 10 or 16 ins. sheaves can handle the larger OD wire with less fatigue and breakdown. Wireline sealing devices fulfil one of two functions:  Pressure containment (sealing)  High pressure containment on braided line. For solid wirelines, only pressure containing Stuffing Boxes are utilised. The standard Stuffing Box is available in 5,000psi. and 10,000psi. pressure ratings although higher pressure ratings are also available. A swivel-mounted (360° free movement) sheave wheel and guard are fitted to the top half of the Stuffing Box. The wheel is positioned so as to maintain the passage of the wire through the centre of the packing rubbers. Some sheave guards on the Stuffing Box are designed to trap any wire, which breaks on the surface before it drops downhole.

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MAXIMUM WORKING PRESSURE (psi)

COLOUR

3,000

Red

5,000

Dark Green

10,000

White

15,000

Yellow

Table 10.1 - Colour Coding and Pressure Rating of Pressure Control Equipment

The first band indicates if the service is Standard or Sour:  Standard service has no band.  Sour service has an orange band. The second band indicates the temperature of the service:  Standard service (-30°C to 250°C) has no band.  Low temperature service (below –30°C) has a blue band.  High temperature service (above 250°C) has a purple band. Upper Lubricator Sections

These accommodate the toolstring that has a smaller OD than the lubricator. These toolstrings are normally 1”, 11/2” and 17/8”, although larger sizes are available for heavy-duty work. The upper section, connecting to the lower lubricator, will have a connection to mate with the top of the lower lubricator sections.

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Construction

Lubricators for normal service (up to 5,000psi.) can be made of carbon or manganese steel. Over 5,000psi, consideration should be given to sour service as quantities of H2S can be absorbed into the steel of the Lubricator body and heat treatment becomes necessary. All Lubricator sections must have full certification from the manufacturer or test house. A standard colour code identifies different pressure ratings of lubricator. Riser sections, used in offshore platforms to reach from the wellhead deck to a working deck above, are similar to lubricator sections except they are generally much longer in length and may be installed between the wellhead adapter and the BOPs. They may also be of even thicker section to support the increased weight being carried.

Figure 10.8 – Lubricator Sections

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Lower Lubricator Sections

These are sections of thick wall tube usually between 8 to 10 ft. long with quick union connections at each end and made up in a total length to accommodate the longest tool to be run. They are installed immediately above the BOPs and usually have a bore size approximately ½” larger than the Xmas tree. The section above the BOPs must have two bleed-off valves (contingency for one being plugged by debris or hydrates). Lubricators - Bleed Off Valve

The Lubricator is, in effect, a pressure vessel situated above the Xmas Tree, subjected to the wellhead shut-in and test pressures. For this reason, it should be regularly inspected and tested in accordance with Statutory Regulations. All Lubricator sections and accessories subject to pressure must be stainless steel banded; the band should be appropriately stamped with the following data:- maximum working pressure, test pressure, and date and rating of last hydrostatic test. Description

A Lubricator allows wireline tools to enter or be removed from the well under pressure. It is a tube of selected ID and can be connected with other sections to the desired length by means of Quick Unions. The following factors govern the selection of Lubricators:    

Shut-in wellhead pressure Well fluid Wireline tool diameter Length of wireline tools.

The lowermost Lubricator section normally has one or more bleed off valves installed; a pressure gauge can be connected to one of the valves to monitor pressure in the Lubricator. If the Lubricator has no facility to install valves then a Bleed-off Sub, a short Lubricator section with two valves fitted, should be connected between the Wireline Valve and Lubricator. NOTE:

To meet IWCF Barrier criteria, the needle valve configuration should be, from the Lubricator: Needle Valve, Tee (with gauge), Needle Valve. This maintains two Barriers in the event of one Needle Valve leaking.

Quick Unions connect Lubricator sections together and to the Wireline Valve; these unions have Acme type threads and seal by means of an ‘O’ring, thereby requiring only tightening by hand. (Refer to Figure 10.7)

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10.3.5

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Quick Unions

The connections used to assemble the Lubricator and related equipment are referred to as Quick Unions (Refer to Figure 10.7). They are designed to be quickly and easily connected by hand. The box end receives the pin end that carries an ‘O’ ring seal. The collar has an internal Acme thread to match the external thread on the box end. This thread makes up quickly by hand and should be kept clean. The ‘O’ ring forms the seal to contain the pressure and should be thoroughly inspected for damage and replaced if necessary. A light film of oil or grease helps in the makeup of the union and prevents cutting of the ‘O’ ring. Pipe wrenches, chain tongs or hammers should never be used to loosen the collar of the union. If it cannot be turned by hand, all precautions must be taken to make sure that the well pressure has been completely released. CAUTION:

In general, unions that cannot be loosened easily indicate that high pressure may be trapped inside. If this pressure is not bled off first, unscrewing the union could cause a sudden release of pressure, projecting equipment parts at lethal speeds.

The collar of the union will make up by hand when the pin end (with the ‘O’ ring) has been shouldered against the box end. When the collar bottoms out, it should be backed off approximately one quarter turn to eliminate any possibility of it sticking due to friction when the time comes to disconnect it. Rocking the lubricator to ensure it is perfectly straight will assist in loosening the quick union. In addition, ensure that tugger lines and hoists are properly placed to lift the lubricator assembly directly over the wellhead.

Figure 10.7 - Quick Unions

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Figure 10.6 - Wireline Valve Ram Configuration

NOTE:

Ensure that the correct guide is installed as an incorrect guide may damage or cut the wire.

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Figure 10.5 – Dual BOP Braided Line (Inverted Lower Ram)

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Uses of Wireline Valves

 To enable well pressure to be isolated from the lubricator when leaks develop etc. without cutting wire by closing the master valve.  To permit assembly of a wireline cutter above the rams.  To permit dropping of wireline cutter or cutter bar.  To permit ‘stripping’ of wire through closed rams only when absolutely necessary.  CAUTION: WIRELINE VALVES WILL HOLD PRESSURE FROM BELOW ONLY.  Equalising Valves  Permits equalisation of pressure from below the closed rams, after bleeding off of the lubricator. The equalising valve must be opened and closed prior to use.  A check should be made to ensure that the equalising assembly is not inverted and that the retainer screw is towards the bottom of the valve. (Refer to Figure 10.4)  When operating with stranded/braided line, it is strongly recommended that a twin valve or two single valves (one on top of the other), be installed and equipped with the appropriate size moulded rams with the lower rams inverted to shut off from above. This enables grease injection between the rams to block off the interstices of the braided line, preventing leakage through the internal parts of the wire.  NOTE: If the BOP fails its pressure test, the equalising valve should be checked to confirm it is fully closed. Description of Operation

A mechanical or hydraulic force is applied to close the rams to seal against well pressure. The sealing elements are arranged so that the differential pressure across them forces them closed and upward, assisting in the sealing action. Figure 10.6 shows the ram configuration of a Wireline Valve. Blind rams close without wire and will also close on slickline without damage. Both 3/16” and 7/32” rams have a semi circular groove in each of the two ram faces to permit the ram to close and seal on 3/16” or 7/32” braided line.

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Figure 10.4- Typical Wireline Valve (BOP)

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10.3.4

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Wireline Valve (BOP)

Description

A Wireline Valve, (refer to Figure 10.4) must always be installed between the Wellhead/ Xmas tree and Wireline Lubricator. This valve is a piece of safety equipment that can close around the wireline and seal off the well below it. This enables the pressure to be bled off above it, allowing work or repairs to be carried out on equipment above the valve without pulling the wireline tools to surface. A positive seal is accomplished by means of rams that are manually or hydraulically closed without causing damage to the wire. Hydraulically actuated Wireline Valves are now more commonly used because of the speed of closing action and ease of operation. During an emergency, often the valve is not easily accessible to allow fast manual operation and therefore remote actuation is preferred. Single or dual ram valves are available in various sizes and in a full range of working pressure ratings. Dual rams offer increased safety during slick line work and allow the injection of grease to secure a seal on braided wireline. They are used particularly in gas wells, or wells with a gas cap. On slickline operations in low-pressure wells, a single BOP is usually installed dressed with slickline rams to close and seal around the wire. On high-pressure wells a dual BOP is used, the lower rams dressed for slickline and the uppers with blind rams. The injection point is used to pump grease if there is leakage past the rams. When running cable, a dual BOP is used with both rams dressed for the particular cable size, and bottom rams inverted with a grease injection point between the rams. (Refer to Figure 10.5 ) In a situation where slickline and braided line are both being used, a triple BOP would be installed with the lower and middle rams dressed for the braided line and the upper for slickline. On electric line jobs, triple BOPs are used, the upper rams being blind. Wireline Valves are fitted with an equalising valve that allows Lubricator and well pressure to equalise prior to opening the rams when wireline operations are to be resumed. Without this, if the valve rams were to be opened without first equalising, the pressure surge could blow the toolstring or wire into the top of the Lubricator, causing damage or breakage. WARNING:

SINCE THEY ARE SUCH A VITAL COMPONENT IN CONTROLLING THE SAFETY OF THE WELL, IT IS IMPORTANT THAT WIRELINE VALVES ARE REGULARLY PRESSURE AND FUNCTION TESTED. TESTS SHOULD BE CARRIED OUT PRIOR TO TRANSPORT OFFSHORE, BEFORE EACH NEW WIRELINE OPERATION AND AFTER ANY REDRESS OR REPAIR OF THE VALVE.

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10.3.3

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Pump-in Tee

A Pump-In Tee (Refer to Figure 10.3) consists of three main parts:  A Quick Union box end  A Quick Union pin end  A Chiksan/Weco type connection. The Pump-in Tee, when rigged up, is placed between the Wellhead adapter and the wireline BOP. Therefore, Quick Union sizes and pressure ratings must be compatible with all surface equipment. Pump-in Tees may be required as part of a wireline rig-up. By connecting a kill-line to the Chiksan/Weco connection, the well can be killed in an emergency situation. This line can also be used to pressure test or release pressure from the surface equipment. NOTE:

On some locations, the pump-in tee will be part of the wellhead adapter.

Figure 10.3 - Pump-in Tee

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10.3.2

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Wellhead Adapter (Tree Adapter)

All Wellhead Adapters are crossovers from the Xmas tree to the bottom connection of the Wireline Valve or Riser. It is important to check that the correct types of threads with appropriate pressure ratings are used on the top and bottom of the adapter. Three types of Wellhead Adapter (Refer to Figure 10.2) are in common use:  Quick Union to Quick Union  API Flange to Quick Union  Acme Thread to Quick Union.

Figure 10.2 - Wellhead Adapters

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10.3 WELLHEAD PRESSURE CONTROL EQUIPMENT To enable the tools to be run into the well under pressure, the surface equipment shown below is required. Each component on the following list is discussed in the next sections.               

Quick Unions Wellhead Adapter Pump-in Tee Wireline Valve (BOP) Lubricator - Bleed Off Valve Safety Check Union Stuffing Box Hydraulic Packing Nut Grease Injection Head Flow Tubes Grease Injection System Hay Pulley Weight Indicator Wireline Counter Wireline Clamps.

The relative positions of some of these components are shown in the following sections. 10.3.1

Wireline Lubricators and Accessories

The wireline lubricator, when assembled, acts like a pressure vessel on top of the Xmas tree into which the wireline tools are ‘lubricated’. It consists of:      

Wellhead adapter Wireline BOPs or wireline valve Lower lubricator section(s) Upper lubricator section(s) Stuffing box or grease head Line wiper.

It is extremely important that a wireline lubricator pressure rating meets the maximum anticipated surface well pressure. Lubricators must be designed, not only to withstand the stress caused by internal pressure but also from stresses caused by jar action or high pulling forces. To install the tools, the lubricator must first be isolated from well pressure at the Xmas tree, usually by the swab valve, and all pressure bled off through an appropriate bleed-off valve. The lubricator is then broken out at the connection immediately above the BOPs. The Wireline tools, after attaching to the toolstring, are pulled up into the lubricator bore, and the lubricator reinstalled. The lubricator should then be pressure tested to a minimum of SITHP, before opening the tree and running in the hole.

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10.2.7

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Types of Wireline

Electric line

Cable used on electric line units can be either mono-conductor, coaxial or multi-conductor braided line and supplied for various service conditions. Each particular type has a range of sizes and specific uses according to the required service or tool being run. Careful handling of electric line is essential, especially with the smaller sizes and when rigging up, to prevent line damage and penetration of the core insulation leading to subsequent loss of signal. Slickline

Slickline is a high-strength mono-filament steel line and is available in common sizes of 0.082”, 0.092”, 0.108” and 0.125”. 0.136” and 0.142” are also available now for heavy duty slickline work. These are also supplied for various service conditions. Being slick the OD of the wire is easy to seal around using a simple packing device called a stuffing box whereas the cable requires a grease seal arrangement. Braided Line

Braided wireline used for heavier duty wireline operations is supplied in 3/16” and 7/32” sizes.

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The hay pulley is the device used to turn the wire from the horizontal plane to the vertical up to the lubricator stuffing box sheave. As well as turning the wire it also moves the forces generated on the wire into the same axis as the lubricator reducing any possible bending moments. It has been known for a hay pulley failure due to severance of the tie down chain, causing the lubricator to break off the well.

Figure 10.1 - Typical Wireline Rig Up

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10.2.2

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Power Pack

The power pack is normally a diesel driven hydraulic unit and provides hydraulic power through supply and return hoses to the winch. Power packs are normally fireproofed and certified for division 1, zone 2 hazardous areas. Electric power packs are also available, but are not so common. 10.2.3

Operator’s/Engineer’s Cabin

The cabin is an integral part of the winch unit situated directly behind the drum for direct observation and monitoring of the wireline spooling. It contains the winch and possibly the power pack operating controls. In an electric line unit, it also contains all of the electronic instrumentation, computing and log printing equipment. Electric line units have fine smooth controls for accurate logging operations whereas the slickline unit has a wide range of speeds for both fine and very fast operation when jarring. 10.2.4

Winch

The winch consists of the wireline reel driven by a hydraulic motor controlled from the console in the cabin, all of which is mounted in the unit frame. Hydraulic power is supplied from the power pack. The reel controls have a forward and reverse directional valve, a number of gear ratios to cover a wide range of speeds and a hydraulic bypass valve for fine control within each gear range. The reel is driven by chain drive from the gearbox and has a brake band. If there are two reels on the winch, slickline and braided, there is an additional manual operated clutch system for reel selection. 10.2.5

Spooling Head

The spooling or measuring head controls the winding of the wire off and onto the reel and also measures the length of wire spooled. The depth measurement is given on an odometer via a cable drive and a precisely machined measuring wheel (one for each size wire). The wire is held against the measuring wheel by pressure wheels to eliminate slippage. Electric line units usually have electronic type depth measurement devices. 10.2.6

Weight Indicator and Hay Pulley

The weight indicator can be mounted on the hay pulley or be an integral part of the spooling head. If mounted at the hay pulley, the weight sensor is a load cell placed between the hay pulley and the tie down chain. The cell is connected to the indicator situated in the unit with a long hydraulic hose. The system is graduated for the wire to pass around the hay pulley at an included angle of 90°. If this angle is not maintained, there will be an error in the readings. Correction tables are available which correct for varying angles. Modern units usually have more sophisticated type weight indicators, some hydraulic and others electronic. These units must be regularly serviced and checked for accuracy, as this is fundamental to wireline service especially when using relatively low strength wire.

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Mechanical wireline also known as slickline (as the line has a smooth OD), is used to conduct mainly mechanical operations such as:           

Installing flow controls. Installing gas lift valves. Depth finding. Plugging. Bailing. Paraffin cutting. Tubing gauging. Setting bridge plugs. Fault finding. Fishing. Logging - through-tubing BHP gauges or the latest electronic solid state logging tools such as spinners, CCLs, etc.

The slickline unit can also be rigged up with braided line for heavy-duty wireline operations such as running heavy, large tools or performing heavier duty fishing operations. A more recent development in wireline services is the Heavy Duty Wireline Unit used mainly for fishing jobs where regular fishing methods have failed. These units, in conjunction with heavy-duty tooling, are so powerful they can destroy normal wireline tools and devices, if desired. Although wireline handles most tasks required for well servicing, it is obviously limited in its capabilities. It also has a role in dead well servicing, as it is normally required for plugging the well to make it safe prior to Xmas tree removal and BOP installation. It is also used to conduct remedial operations such as setting bridge plugs, re-perforating etc. It’s greatest limitation, due to using gravity as it’s motive force, is in working in high angle or horizontal wells with inclination angles higher than 70°, although recent developments such as ‘Roller Bogies®’ have been successfully used in deviations up to 80+°. 10.2.1

Wireline Units

As pointed out earlier, there are two types of wireline unit - the electric line or logging unit and the mechanical or slickline unit. Both types of unit are constructed similarly in that they have:     

Power pack Operator’s/engineer’s cabin Winch, including a wireline drum or reel Spooling or measuring head Weight indicator and pulleys.

Wireline units must be self contained and able to be mounted on a truck (or trailer) or portable to enable trucking and/or shipping to the well site. A typical wireline unit is shown in Figure 10.1.

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10 WIRELINE OPERATIONS 10.1 INTRODUCTION Most well servicing is accomplished using wireline methods which are relatively simple to rig up and conduct operations, compared to other methods. Wells in which Wireline Services are performed may contain a wide range of wellhead pressures (WHP), for example from a few psi. up to several thousand psi. This pressure is normally due to the natural pressure of the producing formation into which the well has been drilled. Working in a pressurised well allows remedial or investigative work to be performed without ‘killing’ the well. Although killing the well is safer, it is a costly, time consuming exercise requiring a rig and perhaps damaging the producing formation in the process. Current Wellhead Pressure Equipment and practices allows a wire to be run in and out of the well. Various wireline tools can be run and retrieved with a high degree of safety. Despite this, wireline operations with pressure in the well require highly-qualified personnel and rigorous operating and safety procedures, since the safety/control of the well is under their management. The development of wireline pressure control systems have made this service one of the safest in the industry. Braided line (i.e. electric line and swab line) and slickline pressure control equipment is similar in design and operation but do have some differences which are outlined below.

10.2 WIRELINE UNIT Wire line was the first and is the most common method of servicing Wells. It is extremely efficient, economic and relatively easy to rig up and deploy. Electric line services provide essential information about the reservoir and the completion and perform many services, typically:  Logging - depth determination, cement bonding, sonic, nuclear, temperature, pressure, spinner, density, dipmeter, profile, etc.  Calipering.  Downhole sampling.  Perforating.  Setting bridge plugs, packers and cement retainers. This is achieved by communicating with the tools through the conductor cable.

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SECTION 10 WIRELINE OPERATIONS

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BOPs are usually compact for manipulation into position above the Xmas tree or onto a riser often used in platform arrangements. They are fitted with flexible hoses to enable ease of installation and to reach between the BOP hydraulic control system and the BOPs when in situation. The connections on the BOP must be compatible with the riser/tree connection and lubricator or be supplied with appropriate crossovers. Well intervention pressure control procedures are addressed in Sections 10 to 12.

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9

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WELL INTERVENTION SERVICES

9.1 GENERAL Well interventions in the context of IWCF are servicing operations conducted through the Xmas tree (through-tree) on live Wells. These are carried out by the following methods:  Wireline (electric, braided line and slickline)  Coiled tubing  Snubbing. Well service operations or workovers on dead Wells where the Xmas tree is replaced by Well control equipment, are carried out by:  Drilling rigs  Workover rigs  Hydraulic workover units. During workovers, it is probable that Well interventions with wireline and/or coiled tubing are required as part of the work programme to prepare the Well for tree removal, or establish production post workover. Many offshore installations have drilling rigs onboard used for the drilling phase of a development. These units are often retained to conduct Well servicing operations on fields which frequently have Wells requiring servicing, although it is becoming more common for the drilling units to be demobilised, and dead Well servicing to be accomplished by a Hydraulic Workover Unit. Where a drilling rig is available for Well servicing, it is obviously more economic for it to be used than mobilising an HWO unit. On installations that have not retained the drilling rig, or on small platforms (drilling performed with a jack-up rig), the HWO unit is commonly used. This is due to their easy deployment and their small footprint. On subsea Wells, normally the only means of conducting a Well intervention is to use a semisubmersible vessel (drilling unit, DSV or specialised Well servicing unit) from which a workover riser can be deployed. However, if the work programme can be conducted solely with wireline, this can be successfully carried out by subsea wireline systems deployed from Well servicing vessels (for example the Stenna Seawell). These vessels also have the capability to carry out subsea tree change outs once appropriate barriers have been installed by wireline. Well control equipment used on Well interventions in live Wells is specific to the particular service being used for the intervention, albeit BOPs and strippers all operate under the same principles. The main differences in the systems usually lie in the design of BOP ram elements, strippers or stuffing boxes, grease heads used in wireline braided line operations, and the configuration of these above the Xmas tree.

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SECTION 9 WELL INTERVENTION SERVICES

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Figure 8.24 -Example Composite Xmas Tree

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Kill Wing Valve

The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure equalisation across tree valves e.g. during wireline operations or prior to the removal/opening of a sub-surface safety valve. This valve is usually manually operated. Swab Valve

The Swab Valve permits vertical entry into the well for wireline (e.g. running BHP/BHT gauges, tubing conditioning) or for well interventions such as coiled tubing operations and logging. This valve is operated manually. Xmas Tree Cap

The Xmas Tree Cap provides the appropriate connection for well control equipment when conducting well interventions and is installed directly above the swab valve. The Xmas Tree cap normally includes a quick union type connection and should be strong enough to support the well control equipment. The bore of the cap flange should be compatible with the tree and permit the running of service tools. Sometimes the cap is removed and replaced by tertiary well control equipment. (e.g. Shear Seal)

Figure 8.23 - Typical Surface Xmas Tree

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8.12 XMAS TREES As already described, a Xmas Tree is an assembly of valves and fittings used to control the flow of tubing fluids at surface, provide access to the production tubing and on some subsea completions to provide access to the annulus string. In general, a Xmas Tree is essentially a manifold of valves, installed as a unit on top of a tubing head or subsea wellhead. The range of trees available is wide, and are not all addressed in this manual. However the valve layout of surface Xmas trees is similar throughout and typically contains the following valves and features: Lower Master Valve (LMV)

The Lower Master Valve is utilised on all Xmas trees to shut in a well. This valve is usually operated manually. As its name implies, the master is the most important valve on the Xmas tree. When closed, this valve should keep the well pressure under full control and therefore should be in optimum condition - it should never be used as a working valve. In moderate to high-pressure wells, Xmas trees are often furnished with a valve actuator system for automatic or remote controlled operation (i.e. surface safety valve system). This is often a regulatory requirement in sour gas or high-pressure wells. Upper Master Valve (UMV)

The Upper Master Valve is used on moderate to high pressure wells as a emergency shut-in system where the valve should be capable of cutting at least 7/32“ braided wireline. This valve can be actuated pneumatically or hydraulically. The UMV valve is a surface safety valve and is normally connected to an emergency shut-down (ESD) system. Flow Wing Valve (FWV)

The Flow Wing Valve permits the passage of well fluids to the choke valve. This valve can be operated manually or automatically (pneumatic or hydraulic) depending on whether a surface safety system is to be included in the production wing design. Choke Valve

The Choke Valve is used to restrict, control or regulate the flow of hydrocarbons to the production facilities. This valve is operated manually or automatically and may be of the fixed (positive) or adjustable type. It is the only valve on the Xmas tree that is used to control flow. It is sometimes located downstream at the production manifold. NOTE:

All other valves used on Xmas trees are invariably of the gate valve type providing full bore access to the well. These valves must be operated in the fully open or closed position.

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Figure 8.22 - Typical Compact Wellhead

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8.11 WELLHEADS 8.11.1

Tubing Heads

At the drilling stage, casing is run and cemented in a well to line the well to protect against collapse of the borehole, to prevent unwanted leakage into or from rock formations and to provide a concentric bore for future operations. Various strings of casing are run, i.e. conductor, surface string (which provides a base for the wellhead) followed by one or more intermediate strings depending on the target depth and expected conditions in the well. At the completion stage, production tubing is run to act as a flowline between the formation and surface. Unlike casing, production tubing is not cemented in the hole so the entire tubing weight must be supported by a suspension system suitably installed in a tubing head. The tubing head is positioned on top of the uppermost casing head of a well and is used to suspend the production tubing and to produce an effective seal between tubing and casing. Tubing heads are composed of a body, a hanger-sealing device (tubing hanger), and a mechanism that retains the hanger. Figure 8.22 shows a typical modern compact wellhead. The wellhead equipment installed on top of the tubing head serves to control and directs the flow of well fluids from the production tubing string. Surface equipment may range from a simple flow cross with stuffing box to an elaborate Xmas tree. Choice of surface tree depends on well fluid production method (natural flow or artificial) and the wellhead pressure encountered. In general, most surface trees are comprised of at least one master valve, at least two wing or flow valves (one of which may be hydraulically operated), and one swab valve utilised in wireline operations. (Refer to Figure 8.23). Wellhead equipment (spools, valves, chokes) are either screwed, flanged or a combination of both. Wellheads with screwed connections are used for pressures not exceeding 1,000psi. (69 bar); those with screwed valves and chokes not exceeding 5,000psi. (345bar). However, most operators specify flanged connections, even for low pressure wellheads since they are less susceptible to leakage, easier orientated and, especially in the larger sizes, easier manipulated. NOTE:

API test pressures for all wellhead, including pressure control equipment and downhole equipment, is twice the rated working pressure for equipment up to 5,000psi and 11/2 times working pressure for 5,000psi and above.

With regard to subsea wellheads, there is no API standard and manufacturers all have their own specific design that includes some means of orientation in order to align the subsea tree inlets and outlets to the flowlines or indeed in a subsea manifold system.

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Multiple Tubing Heads/Hangers

The purpose of a multiple completion is to produce reservoirs simultaneously without any pressure or reservoir fluid combining during the transfer of fluid from the production zones to the production facilities. For multiple string completions two or three segments, one for each production string, are used to form a hanger assembly which, when installed in the appropriate tubing head, resembles a mandrel type tubing hanger. Figure 8.21 shows a tubing hanger spool arrangement for use in a dual completion. An important characteristic of this tubing hanger is the support wedges (or in other heads support pins) used to guide and align the two segmented hangers in their proper positions in the upper bowl. The segmented hangers are locked in place with the tie-down screws. A disadvantage of this type of hanger is that seals are often damaged while installing the second segment. NOTE:

Segmented hangers are available to accommodate a backpressure valve and are also manufactured with control line outlets to allow an SCSSV to be installed in the production tubing.

Figure 8.21 – Tubing Hanger Spool

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The disadvantages of ram type tubing hangers are:  After long service periods, it may be difficult to re-open the rams  The tubing pick-up weight must be overcome prior to opening the rams otherwise the rams will be difficult to open  They are bulky, heavy and expensive.

Figure 8.20 - Cameron Single Ram Tubing Head (‘SRT’)

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Figure 8.19- Cameron ‘F’ Tubing Head and Hangers

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Ram Type Tubing Head

Ram Type Tubing Heads find their application in completions where manipulation of the tubing is necessary to locate and latch into a packer and to maintain tension in the tubing when landed. Figure 8.20 shows a ram type tubing head that comprises a housing with two side outlets in which are located retractable rams. These rams, when closed, support the hanger nipple, which is screwed on to the top of the tubing string. A seal assembly provides the seal between the annulus and the tubing, which is located around the hanger nipple above the rams. With the ram type tubing hanger installed on the wellhead and the packer set, production tubing is run and spaced out so that the final position of the hanger nipple is that distance below the tubing head corresponding to the amount of stretch required to give the appropriate tension. The tubing is latched into the packer and tension applied to the tubing so that the hanger nipple is just above its final hang off position. The rams are closed, the tubing weight is set on the rams and the handling string removed. The seal assembly is then installed, bolted down, and the seal system energised by the injection of plastic packing. Finally, the BOPs are removed and the Xmas Tree installed. NOTE:

Like mandrel type hangers, landing nipple hangers are provided with a top thread for the landing joint, an internal left hand thread or wireline profile for the installation of a back pressure valve, and can be supplied with extended necks to facilitate secondary sealing. Also, ram type tubing heads are available with control line outlets to allow an SCSSV to be incorporated in the tubing string.

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The important features of tubing hanger spools are: Top and Bottom

Connections

the size and pressure ratings of these connections (usually flanged) must be compatible with the size and pressure rating of the joining connections.

Upper Bowl

provides the seal area for various tubing hangers and a load shoulder to support the production tubing.

Lower Bowl

this is provided to house some type of isolation seal.

Set Screws

or hold-down screws are found in most tubing heads and have two important functions.  

Retain the tubing hanger and prevent any upward tubing movement due to pressure surges. Activate (energise) the body seals on the tubing hanger.

Outlets

these provide access to the annulus (e.g. for pressure monitoring or gas lift) during production.

Test Port

permits the pressure testing of the hanger seal assembly, lockdown screw packing connection between flanges, and the secondary (isolation) seal.

The important features of tubing hangers are: Landing Threads

these are the uppermost threads on the hanger and they must support the entire weight of the tubing string during landing operations.

Bottom Threads

these must support the entire weight of the tubing string and seal the producing conduit from the tubing/casing annulus.

Sealing Area

these provide compression type sealing between the outside diameter of the hanger body and the inside diameter of the hanger bowl. Sealing is accomplished by energising elastomer seals or metal-to-metal seals by the action of tubing weight on various load-bearing surfaces. Tubing hangers are sized according to the upper bowl of the tubing head and the tubing size the hanger will be supporting. Thus, a 7” x 27/8” tubing hanger means a 27/8” production string suspended from a tubing head 71/16” top bowl.

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Tubulars up to and including 41/2“ are classified as tubing, over 41/2“ is casing. In large capacity wells, casing size tubulars are often installed as the production conduit. Tubing selection is governed by several factors. Anticipated well peak production rate, depth of well, casing sizes, well product, use of wireline tools and equipment, pressures, temperatures, and tubing/annulus differential pressures are among those which must be considered. To meet various completion designs, there is a wide range of tubing sizes, wall thickness (weights) and materials to provide resistance to tubing forces and differing well environments. The best tubing selection is the cheapest tubing which will meet the external, internal and longitudinal forces it will be subjected to, and resist all corrosive fluids in the well product. Tubing in the main is supplied in accordance to API specifications which has a range of materials to resist most of the potential corrosive well conditions but today where deeper high pressure sour reservoirs are being developed, the API range is not suitable. To fill this gap in the market steel suppliers provide propriety grades. These grades are usually high chrome steels designed for various high temperature and sour well conditions up to 24% chrome. For ease of identification, tubing is colour coded to API specification. Some specialist supplier's steels are not covered by the code and provide their own specific codes. Refer to these codes to ensure the tubing is according to requirements. 8.10.9

Tubing Hangers

Bowl Type Tubing Head/Mandrel Type Tubing Hanger

A Tubing Head/Tubing Hanger combination unit is attached to the uppermost casing head on the wellhead. The main functions of this unit are to:     

Suspend the tubing Seal the annular space between the tubing and the casing Lock the tubing hanger in place Provide a base for the wellhead top assembly (Xmas Tree) Provide access to the annular space (‘A’ annulus).

Suspension of the tubing is accomplished usually by threads, slips or any other suitable device, i.e. rams. The tubing head consists of a spool piece type housing where the internal profile of the top section is a straight or tapered cylindrical receptacle (bowl) into which the tubing hanger is landed, suspending the tubing and sealing off the volume between the tubing and the casing. A tapered mandrel type tubing hanger system is shown in Figure 8.19.

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8.10.7

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Control Lines

The conduit, which supplies the hydraulic fluid to the SCSSV, is termed the ‘control line’. The control line is normally 1/4“ OD tubing attached between the sub-surface valve (TRSV) or nipple (WRSV) and the tubing hanger. It is attached with compression fittings, and clamped to the outside of the tubing. The method of porting through the hanger to the control manifold is dependent on the type of wellhead and hanger system being used. Some systems on land wellheads are simply fed out through a port with a packing element (often a tie-down bolt hole) that is tightened to seal around the outside of the tubing. Other systems have drilled ports through the hanger, into which the control line is fitted again by a compression fitting, and the spool sealed off from the annulus and the Xmas tree bore by concentric weight set or pressure energised seals. Subsea wellheads have different methods of termination so the tree can be installed without diver assistance. The control line material is selected to meet the environment in which it is to be installed and must be compatible with the safety valve and the hanger materials to avoid corrosion caused by electolosis (Dissimilar materials). There is a large choice of control lines materials from 316ss for sweet service to Inconel and Elgiloy alloys for more demanding service. They are also supplied in hard durable plastic coatings for added protection from corrosion and against crushing damage during installation, which at one time was one of the major problems during completing. Two lines can be encased for operation of dual-control line safety valves. Control lines are held flat to the tubing by control line protectors usually placed across a coupling or connection and sometimes also in the middle of a joint. The protector has a slot into which the control line plastic outer coating fits. Simple banding can be used but it is not strong and is easily ripped off. Protectors are now metal clamp types as earlier rubber versions were easily detached and caused major problems while retrieving the completion string. 8.10.8

Tubing

The purpose of using tubing in a well is to convey the produced fluids from the producing zone to the surface, or in some cases to convey fluids from the surface to the producing zone. It should continue to do this effectively, safely and economically for the life of the well, so care must be taken in its selection, protection and installation. The tubing must retain the well fluids and keep them out of the annulus to protect the casing from corrosion and well pressure which may be detrimental to future well operations such as workovers. Tubing connections play a vital part in the function of the tubing. There are two types of connection available today; API and premium connections. API connections are tapered thread connections and rely on thread compound to affect a seal whereas the premium thread has at least one metal-to-metal seal. Premium connections are generally used in high pressure wells.

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8.10.6

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Surface Control Manifolds

Surface control manifolds are designed to provide and control the hydraulic pressure required to hold an SCSSV open. The manifold has one or more air powered hydraulic pumps to maintain the hydraulic operating pressure for the safety valve. The hydraulic pressure is through a three-way control valve, which is controlled by remote pressure pilots and fire sensors. Pilot, sensor or manual activation removes the hydraulic pressure, closing the safety valve. NOTE:

Activation can occur from the operation of remote-control pressure sensing pilots, fusible plugs, plastic line, sand probes, level controllers or emergency shutdown (ESD) systems.

Surface control manifolds are generally supplied as complete systems containing a reservoir, pressure control regulators, relief valves, gauges, and a pump with manual override. Manifolds, in combination with the various pilot monitors, have many different applications, e.g. controlling multiple Wells using individual control, multiple Wells using individual pressures and any combination of these. Other additional features have been incorporated into surface control manifolds when the system is integrated with other pressure-operated devices. A control panel, designed to supply hydraulic pressure to a surface safety valve (SSV) and hydraulic pressure to an SCSSV, contains circuit logic for proper sequential opening and closing of the safety valves, i.e. Sequential closing:  SSV first  SCSSV second. Sequential re-opening:  SCSSV first  SSV second. Sequential logic is incorporated to increase the service life of hydraulic master valves and SCSSVs to prevent SCSSVs becoming flow cut by high velocity wells. Improvements have also been made in the monitoring systems, e.g.:  Sand erosion probes installed on a flowline to monitor sand flow production.  Quick exhaust valves, which allow rapid exhausting of control line pressure, to speed up valve closures.

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Figure 8.18 - Typical Annular Safety Valve System

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8.10.5

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Annulus Safety Valves

The sub-surface safety valves discussed so far, i.e. tubing retrievable and wireline retrievable, only provide control on the tubing. In these systems, no annular flow control exists. Annulus safety valve systems are usually associated with completions where artificial lift or secondary recovery methods are employed e.g. gas venting in electric submersible pump (ESP), hydraulic pump, and gas lift installations. Their application is to remove the potential hazard of a large gas escape in the event there is an incident where the tubing hanger seal is breached. There are a number of designs on the market and the variety of modes of operation is too wide to be covered in this document, however the basic concepts are the same. With any annulus system, there must be a sealing device between the tubing and the casing through which the flow of gas can be closed off. This is generally a packer type installation, but may also be a casing polished bore nipple into which a packing mandrel will seal. In the sealing device there is a valve mechanism operated by hydraulic pressure similar to an SCSSV. The valve mechanism opens the communication path from the annulus below to the annulus above the valve and is fail-safe closed. The closure mechanism may be a sliding sleeve, poppet or flapper device. Figure 8.18 shows a typical annulus safety valve.

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8.10.4

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Safety Valve Leak Testing

Leak tests are performed immediately after Sub-Surface Safety Valves are installed. A typical leak test involves closing the production, kill and swab valves on the Xmas tree and bleeding off the control line pressure to the Sub Surface Safety Valve. Tubing pressure is bled off slowly above the valve to zero for a tubing retrievable valve and in 100psi. (6.9bar) stages for a wireline retrievable valve. The system is closed in again and tubing pressure monitored. If there is a rapid build-up, a major leak is indicated or improper functioning of the valve; in this case the valve should be cycled and the test repeated. After a specified shut-in period the tubing head pressure should be below a maximum allowable pressure as specified by the operator’s leak off criteria. Many operators apply an API standard. NOTE: The API Standard allows some leakage through downhole Safety Valve, which is why some companies do not consider them to be Barriers. Permitted Leakage;  Gas Leakage allowed - upto 900scft/hr (25.5m³/hr)  Fluid Leakage allowed - upto 6.3gal/hr (0.4m³/hr) NOTE:

It is extremely important that pressure data is fully and accurately recorded.

After initial installation, leak tests should be carried out periodically; this accomplishes three functions:  To test the integrity of the seal in the safety valve.  To test that the lock mandrel in a wireline retrievable valve is still properly locked.  To cycle the valve to prevent 'freezing' in wells where they have been sitting in either fully open or fully closed position for extended periods of time. NOTE:

Authorised personnel should conduct all the above tests on all Sub-Surface Safety Valves.

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Figure 8.17 - Typical Tubing Retrievable SCSSV (TRSV) Flapper Type

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Tubing Retrievable SCSSV

Tubing retrievable safety valves operate by the same principle as wireline SCSSVs. The main difference is that all components are incorporated in one assembly which is installed in the completion string, (refer to Figure 8.17). Some later models have rod pistons instead of concentric piston designs. They also have both equalising and non-equalising versions, and versions that enable the insertion of a wireline valve inside the TRSV when the operating mechanism has failed. If the failure is due to a leaking control line then this contingency measure is ineffective. In this case it may be possible to run a ‘Storm Choke’ to continue production until it is possible to conduct a workover. To enable the installation of the insert valve, the tubing retrievable valve needs to be ‘locked open’ or ‘locked out’. However the reduced internal bore may adversely affect production rates. The components required for a TRSV safety system are:    

Hydraulic control line Control line protectors Hydraulic control manifold Tubing retrievable safety valve.

and additionally for insert capability:    

Wireline safety valve Locking mandrel Wireline installation and retrieval tools for the locking mandrel Lock-out tool for the tubing retrievable valve.

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Figure 8.16 - Typical Wireline Retrievable SCSSV (Ball Type)

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Statistics have proven that the TRSV valve is more reliable than the WRSV and that the flapper is more reliable than the ball mechanism, therefore the TRSV flapper valve is considered to be the most reliable of all. SCSSVs utilise only the ball or flapper type closure mechanisms. Both categories are supplied with or without internal equalising features. The equalising feature allows the pressure to equalise across the valve so it can be re-opened. Valves without this feature need to be equalised by pressure applied at surface. The equalising valve having more operating parts is less reliable than non-equalising valves, however, with the latter, equalisation pressure is often difficult to provide and often more time consuming. Wireline Retrievable SCSSV

Wireline retrievable sub-surface safety valves are located and locked, using standard wireline methods, in a dedicated safety valve landing nipple (SVLN). The SVLN is connected to a hydraulic control line pressure source at the surface, normally by a 1/4” OD stainless steel tubing. When the safety valve is set in the nipple, the packing section seals against the bore of the nipple below the port. The packing section of the lock mandrel forms a seal above the port in the nipple. Control pressure, introduced through the control line, enters the valve through the port in the housing and allows pressure to be applied to open the valve. Figure 8.16 shows a typical surfacecontrolled, wireline retrievable safety valve. Because a wireline retrievable SCSSV seats in a landing nipple installed in the production string, it offers a much smaller bore than a tubing retrievable SCSSV for the same size of tubing. Frequently, WRSVs have to be pulled prior to wireline operations being carried out below them, which have strong implications on well safety. Compared to a tubing retrievable SCSSV, the wireline retrievable SCSSV is easy to replace in the case of failure. Introducing a planned maintenance schedule in which valves are regularly pulled and serviced can prevent most failures. However, during wireline entry operations there is also a safety risk, and care must be maintained at all times. The components that are required for the installation of a wireline retrievable SCSSV are:       

Hydraulic control line Control line protectors Hydraulic control manifold Wireline retrievable safety valve Safety valve landing nipple Locking mandrel Wireline installation and retrieval tools for the locking mandrel.

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Bottom Hole Regulators

Bottom hole regulators are essentially throttling valves installed downhole to enhance the overall safety in wells where high surface pressures or hydrate formation present problems. Bottomhole regulators are designed to reduce surface flowline pressures to safe, workable levels and to keep surface controls from freezing. In gas wells, the pressure drop across a regulator will be downhole where the gas and surrounding well temperature is higher than at surface. The higher gas temperature and surrounding well temperature tend to prevent hydrate formation when a pressure drop occurs across the regulator. In oil wells, the installation of a bottomhole regulator is used to liberate gas from the solution downhole and lighten the oil columns to increase flow velocity. The regulator has a stem and seat that are held closed by a spring and at a pre-set differential pressure the valve opens. If high reductions in pressure are necessary, more than one regulator can be installed, providing stepped reductions reducing the risk of hydrate formation and flow cutting. NOTE:

8.10.3

An equalising sub should be installed between the lock mandrel and the regulator to facilitate the equalisation of pressure.

Surface Controlled Sub-Surface Safety Valves

The SCSSV is a downhole safety device that can shut in a well in an emergency or provide a barrier between the reservoir and the surface. As the name suggests, the valve can be controlled from the surface by hydraulic pressure transmitted from a control panel through stainless steel tubing to the safety valve. The remote operation of this type of valve from the surface can also be integrated with pilots, emergency shut down (ESD) systems, and surface safety control manifolds. This flexibility of the surface controlled safety valve design is its greatest advantage. In the simplest system an SCSSV is held open by hydraulic pressure supplied by a manifold at the surface. The pressure is maintained by hydraulic pumps controlled by a pressure pilot installed at some strategic point at the wellhead. Damage to the wellhead or flowlines causes a pressure monitor pilot to exhaust pneumatic pressure. A low pressure line in turn causes a relay to block control pressure to a three-way hydraulic controller. This results in hydraulic pressure loss in the SCSSV control line. When this pressure is lost, the safety valve automatically closes, shutting off all flow from the tubing. There are two main categories of SCSSVs:  Wireline Retrievable SCSSV  Tubing Retrievable SCSSV.

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The valve is held open by a spring force that may be increased by adding spacers or changing the spring. The relationship between flow rate and differential may be adjusted by changing the bean size. The valve when closed will remain in this position until pressure is applied at surface to equalise across it when the spring will return to the open position. NOTE:

Pulling Should Not Be Attempted Unless Pressures Have Been Equalised And The Valve Is Open.

These valves are still in use today but also a derivative, the Injection Valve, which is normally closed, is widely used in injection wells. This injection valve opens when fluid or gas is injected and travels to the fully open position when the predetermined minimum injection rate is reached, (refer to Sub-Section on Injection Valves). Ambient Safety Valves

This type of direct-controlled safety valve is a fail safe closed valve which is pre-charged with a calibrated dome (chamber) pressure prior to running. Ambient controlled valves will open when the well pressure reaches the set point of the dome calibration. The valve will close when the flowing pressure of the well, at the point of installation, drops below the pre-determined dome pressure. Ambient type safety valves are also generally referred to as a ‘storm chokes’. This type of valve is not limited by a flow bean which gives it a large internal diameter and, hence, a large flow area making it suitable for high volume installations possibly producing abrasive fluids. Ambient type safety valves are run with an equalising assembly to allow equalisation across the valve should it close, and a lock mandrel to locate and lock the valve in the landing nipple. NOTE:

Both pressure differential and ambient controlled sub-surface safety valves close on pre-determined conditions. They do not offer control until these conditions exist. In addition, valve settings may change if flow beans become cut. Surface controlled safety valves should be considered in such cases.

Injection Valve

Injection valves are normally closed valves installed in injection wells. They act like check valves allowing the passage of the injected fluid or gas but close when injection is ceased. The closure mechanism is usually either, a ball or flapper type that opens when the differential pressure from the injected medium equalises the pressure below the valve. As the injection rate is increased to the pre-calculated rate, the differential acts on a choke bean and overcomes a spring to move the mechanism to the fully open mode. If the injection rate is insufficient or fluctuating, the mechanism will be damaged and possibly flow cut. The flapper-type valve is the most popular as its operation is less complicated and is less prone to damage if the injection rate is not high enough.

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WRSV Applications

TRSV Applications

General application: where intervention by wireline is available

General application: where larger flow area is desired for the tubing size

High pressure gas wells

High volume oil and gas wells

Extreme hostile environments where well fluids or temperature tend to shorten the life of component materials

Subsea completions

High velocity wells with abrasive production

Multiple zone completions where several flow control devices are set beneath the TRSV Greater depth setting capabilities

Table 8.1 - Sub-Surface Safety Valve Applications

8.10.2

Sub-Surface Controlled Sub-Surface Safety Valves

These valves are installed in regular wireline type nipples on a lock mandrel. Pressure-Differential Safety Valves

This type of direct-controlled safety valve is a ‘normally open’ valve that utilises a pressuredifferential to provide the method of valve closure. Normally a spring holds a valve off-seat until the well flow reaches a pre-determined rate. This rate can be related to the pressure differential generated across an orifice or flow bean. When this differential is reached or exceeded, a piston moves upwards against a pre-set spring force closing the valve. Valves of this type are sometimes termed ‘storm chokes’. There are three closing mechanisms available with these valves, i.e.:  Poppet  Ball  Flapper.

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Figure 8.15 - Example of Downhole Safety Valve System

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Figure 8.14 – Sub-Surface Safety Valve Applications

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8.10.1

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Types of Sub-Surface Safety Valves

Fail-safe Sub-Surface Safety Valves, whether directly or remotely controlled, are installed to protect personnel, property and the environment in the event of an uncontrolled well flow (or blow-out) caused by collision, equipment failure, human error, fire, leakage or sabotage. Whether safety valves are required in a particular operating area, depends on the location of the Wells and in some cases on company operating policy and/or government legislation. In general, each application must be considered separately due to varied well conditions, locations, regulations, depth requirements etc. Table 8.1 shows the various applications of WRSVs and TRSVs.

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8.10 SUB-SURFACE SAFETY VALVES (SSSV) The applications of various sub-surface safety valve systems are shown in Figure 8.14. The modern sub-surface safety valve has been developed from the earliest low technology versions produced in the 1930's. The initial demand was for a downhole valve that would permit flow during normal conditions, but would isolate formation pressure from the wellhead to prevent damage or destruction. This valve would be installed downhole in the production string for use in an emergency. The valve that was developed was a Sub-Surface Controlled Safety Valve (SSCSV) which was a poppet type valve with a mushroom shaped valve/seat system. Compared with today's valves, this simple poppet type valve had several disadvantages; restricted flow area, tortuous flow paths, low differential pressure rating and calibration difficulties. Despite these limitations the valve operated successfully and other versions were developed with less tortuous flow paths such as the ball and flapper valve. These valves have a long service record, and are commonly used today in such areas as the Gulf of Mexico USA and Nigerian Niger Delta. They are also used in the UK North Sea as an emergency valve on Wells where Control Line integrity has failed. From this beginning, the Surface Controlled Sub-Surface Safety Valve (SCSSV) was developed in the late 1950's. This moved the point of control from downhole to surface, (refer to Figure 8.15). This design provided large flow areas, remote control of opening and closing, and responsiveness to a wide variety of abnormal surface conditions (fire, line rupture, etc.). Initial demand for this valve was slow due to its higher cost and the problems associated in successfully installing the hydraulic control line; hence its usage was low until the late 1960's. The SCSSV is controlled by hydraulic pressure supplied from a surface control system, which is ideally suited to manual or automatic operation, the latter of which pioneered the sophisticated emergency shut-down systems required today. The versatility of the valve allows it to be used in specialised applications as well as in conventional systems. SCSSVs are available in two variants - Tubing Retrievable Safety Valves (TRSV) and Wireline Retrievable Safety Valves (WRSV). SCSSVs are available with ball or flapper type closure mechanisms. NOTE:

SCSSVs are set below any possible depth where damage could occur to the valve from surface impact or explosion

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Figure 8.13 - Types of SPM Valves

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Figure 8.12 - Side Pocket Mandrel (SPM)

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8.9.4 Circulating Valves

A circulating valve is recommended to be installed in any SPM whenever a circulating operation is to be carried out. The circulating valve is designed to enable circulation of fluid through the SPM without damaging the pocket. The valve allows fluid to be dispersed from both ends allowing circulation of fluid at a minimal pressure drop. Some valves permit circulation from the casing into the tubing only and others to circulate fluid from the tubing into the casing only. If a valve is not used when circulating, the pocket could flow cut and a workover would be required to replace the SPM. 8.9.5 Differential Dump Kill Valves

Differential dump/kill valves are designed to provide a means of communication between the casing annulus and the tubing when an appropriate differential pressure occurs. Below a pre-set differential pressure, the valve acts as a dummy valve since it uses a moveable piston to block off the circulating ports in the valve and the side pocket mandrel. The differential pressure necessary to open the valve will depend on the type and number of shear screws installed. The valve will only open when the casing annulus pressure is increased by the differential (of the shear screw rating) above the tubing pressure. An increase in tubing pressure above the casing annulus pressure will not open the valve. After opening, the piston is locked in the up position and fluids can flow freely in either direction. The hydrostatic pressure from the column of annulus fluid will kill the well and remedial operations can be planned. 8.9.6 Equalising Dummy Valves

The equalisation valve is designed to equalise pressure between tubing and casing and/or to circulate fluid before pulling the valve from the SPM. The valve has two sets of packing that straddle and pack off the casing ports in the SPM. The tubing and annulus are isolated from each other until a pulling tool operates the equalising device. Pressures equalise through a port before the valve and latch are retrieved.

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8.9 SIDE POCKET MANDRELS The Side Pocket Mandrel system was originally designed for gas lift completions. They provide a means of injecting gas from the casing-tubing annulus to the tubing via a gas lift valve. However in recent times, they have also been commonly used in place of an SSD as a circulating device, because seal failure can be rectified by pulling the dummy gas lift valve (or kill valve) with wireline and replacing the seals. SPMs are installed in the completion string to act as receptacles for the following range of devices:      

Gas lift valves Dummy valves Chemical injection valves Circulation valves Differential dump kill valves Equalising valves.

It is essential to understand the operation of the device installed in a SPM before conducting any well intervention, as it may affect well control. Refer to Figure 8.12 for a typical SPM and Figure 8.13 for types of valves. 8.9.1 Gas Lift Valves

There are many different designs of gas lift valves for various applications. They range from simple orifice valves to pressure operated bellows type valves. However, they all contain check valves to prevent tubing to annulus flow. These check valves may leak after a period of use and they should never be relied on as barriers in a well control situation. These should be replaced with dummy valves and the tubing pressure tested to confirm integrity. 8.9.2 Dummy Valves

These are tubing/annulus isolation valves. They are installed in place of the valves in order that the completion tubing string can be pressure tested from both sides during installation or when well service operations are required. 8.9.3 Chemical Injection Valves

The injection valve is designed to control the flow of chemicals injected into the production fluid at the depth of the valve. A spring provides the force necessary to maintain the valve in the failsafe closed position. Reverse flow check valves, which prevent backflow and circulation from the tubing to the casing, are included as an integral part of the valve assembly. Injection chemicals enter the valve from the annulus in an open injection system. (This requires the annulus to be full of the desired chemical. An alternative method is to run an injection line from surface to the SPM.) When the hydraulic pressure of the injected chemicals overcomes the pre-set tension in the valve spring, plus the pressure in the tubing, the valve opens. Chemicals then flow through the crossover seat in the valve and into the tubing.

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Figure 8.11 - Sliding Side Door (SSD)

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8.8 BLAST JOINTS Blast joints are installed opposite perforations (non-gravel packed) where external cutting or abrasive action occurs due to produced well fluids or sand. They are heavy-walled tubulars available usually in 10, 15, and 20ft. lengths. They should be long enough to extend at least 4ft. on either side of a perforated interval for a safety margin.

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8.6 SLIDING SIDE DOORS Sliding Side Doors (SSDs) or Sliding Sleeves are installed in the tubing during well completion to provide a means of communication between the tubing and the annulus, or across zones that may be selectively produced when the sleeve is moved to the open position, (refer to Figure 8.11). SSDs are used to:  Bring a well into production after drilling or workover by circulating the completion fluid out of the tubing, and replacing it with a lighter underbalanced fluid.  Kill a well prior to pulling the tubing in a workover operation.  Provide selective zone production in a multiple zone well completion. The application of SSDs as a circulation device means they must be positioned as close as possible to the packer, normally within 100ft. Used for selective zonal production, a number of SSDs can be installed in a single completion string between isolation packers and selectively opened or closed by wireline or coiled tubing methods. Coiled tubing is generally used in high angle or horizontal wells where wireline tools cannot be jarred effectively. SSDs are available in versions that open by shifting an inner sleeve either, upwards or downwards, by the use of an appropriate shifting tool. When there are more than one SSDs in a well, the sleeves may be opened and/or closed with selective shifting tools without disturbing sleeves higher up in the string. CAUTION:

Tubing and annulus pressures must be equalised before an SSD is opened to prevent wireline tools being blown up or down the tubing.

A common fault with SSDs is that seal failure usually leads to a workover, although a pack-off can be installed as a temporary solution. The top sub of the SSD incorporates a nipple profile, and the bottom sub has a polished bore. This enables the installation of the pack-off, sometimes also termed a straddle.

8.7 FLOW COUPLINGS Flow couplings, are heavy-walled tubulars, which are installed above, and sometimes below, any completion component which may cause flow turbulence such as wireline nipples, SSDs, SubSurface Safety Valves etc. and delay the effects of internal erosion, thus prolonging the life of the completion. They may be manufactured from harder materials and have a thicker external wall thickness so that, if erosion is experienced, the flow coupling will still maintain pressure integrity over the projected life of the well. In higher velocity wells, such as high pressure gas wells or injection wells, It is common practice to have a flow coupling placed above and below restrictions.

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Figure 8.10 – Tubing Seal Receptacle

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Figure 8.9 – Polished Bore Receptacle

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Figure 8.8 - Permanent Packer Seal Accessories

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8.5.3 Permanent Packer Accessories

An important aspect in a completion with a permanent packer is the tubing/packer seal. As the packer in effect becomes part of the casing after it is set. The tubing must connect to the packer by a method that allows it to be released. This connection, whether it is a straight stab in, latched or otherwise, must have a seal to isolate the annulus from well fluids and pressures. This seal usually consists of a number of seal elements to cater for some wear and tear. These seal elements are classified into two groups, ‘premium’ and ‘non-premium’. The premium group is used in high temperature and/or severe or sour well conditions i.e. H2S, CO2 etc. These are normally ‘V’ type packing stacks containing various packing materials resistant to the particular environment. The non-premium seals are for low to medium temperature and/or sweet service and can be either ‘V’ type packing stacks or moulded rubber elements. Locator Tubing Seal Assemblies

Locator tubing seal assemblies and Tubing Seal Extensions, (refer to Figure 8.8a and Figure 8.8b), are fitted with a series of external seals providing an effective seal between the tubing and packer bore. They also have a No-Go type locator for position determination within the packer. Locator seal assemblies are normally spaced out so that they can accommodate both upward and downward tubing movement induced by changes in temperature, pressure and ballooning. Seal Bore Extensions

A seal bore extension is used to provide additional sealing bore length when a longer seal assembly is run to accommodate greater tubing movement. The seal bore extension is run below the packer and has the same ID as the packer. Anchor Tubing Seal Assemblies

Anchor tubing seal assemblies, (refer to Figure 8.8c and Figure 8.8d), are used where it is necessary to anchor the tubing to a permanent packer while retaining the option to unlatch when required. Anchor latches are normally used where well conditions require the tubing to be landed in tension or where insufficient weight is available to prevent seal movement. Polished Bore Receptacles (PBRs)

A PBR is simply a seal receptacle attached to the top of a permanent packer or liner hanger packer in which the seal assembly lands. As the PBR bore can be made larger than the packer, this provides a larger flow area through the seal assembly, (Refer to Figure 8.9). Tubing Seal Receptacles

A TSR is an inverted version of a PBR whereby a polished OD male member is attached to the top of the packer and the female (or overshot) is attached to the tubing. The seals are contained in the female member so that they are recovered when pulling the tubing, (refer to Figure 8.10).

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8.5.2 Retrievable Packer Accessories

Travel Joints (Telescoping or Expansion joints) A travel joint is used to compensate for tubing movement due to temperature and/or pressure changes during treating or production and is used with retrievable packer systems. Figure 8.7 shows a travel joint commonly used on the short string in dual string completions.

Figure 8.7 - Travel Joint

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8.5.1 Setting Methods Mechanical

Run on a workstring, it is set by manipulation of the tubing i.e. by applying compression or tension in combination with rotation depending on the particular setting mechanism for that packer. NOTE:

Packers having rotation set/release mechanisms should not be used in highly deviated wells since the application of tubing torque may not be transferred downhole.

Hydraulic

Can be run on a workstring or on the tubing string. When the desired setting depth is reached, the tubing is plugged below the packer with a check valve, standing valve or a wireline plug. Hydraulic pressure is applied to the tubing to set the packer. Electrically on Wireline

This is more commonly used with permanent packers, but retrievable packers, i.e. permatrieve, are also set with this method. The packer is attached to a wireline setting adapter, connected to a setting gun on the end of the wireline and run in the wellbore. On reaching the desired depth an electrical signal transmitted to the gun activates an explosive charge and, through a hydraulic chamber, provides the mechanical forces to set the packer.

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Figure 8.6 - Examples of Common Types of Hydraulic Packers

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Figure 8.5 - Examples of Common Types of Retrievable Packers

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Completion Variations

Figure 8.4 - Examples of Packer Installations

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Retrievable Packers

These are often run into the wellbore on the production tubing string, but can also be set individually on Wireline. As the name implies, retrievable packers can be recovered from the well after setting by a straight overpull, usually around 40,000#, with the tubing. Permanent Packers

These are installed in the wellbore either by Wireline or Coiled Tubing, or as an integral part of the production tubing string. A permanent packer may also be considered as an integral part of the casing. Older type permanent packers can only be removed from the well by milling operations. However, more modern permanent packers can be retrieved by cutting the centre mandrel with a chemical cutter, but these packers are not covered in this manual.

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8.4 PERFORATED JOINTS In Wells where flowing velocities are high, a restriction in the tubing, such as a gauge hanger, can cause false pressure and temperature readings. Vibrations in the tool can cause extensive damage to delicate instruments. To provide an alternative flow path, a perforated joint is installed above the gauge hanger nipple and allows unrestricted flow around the gauge. The perforated joint is normally a full tubing joint that is drilled with sufficient holes to provide a flow area greater than that in the tubing above.

8.5 PACKERS A packer is a primary safety device used to provide a seal between the tubing and the casing which allows Well Control. With a suitable completion string, this seal allows the flow of reservoir fluids from the producing formation to be contained within the tubing up to the surface. This isolates the production casing from being exposed to well pressure and corrosion from well effluents or injection fluids. A packer is tubular in construction and consists basically of:  Case hardened slips to bite into the casing wall and hold the packer in position against pressure and tubing forces.  Packing elements that seal against the casing. Figure 8.4 gives examples of typical packer installations and shows common types of packers. In general, packers are classified in two groups:  Retrievable (Refer to Figure 8.5)  Permanent (Refer to Figure 8.6) Packers may be further classified according to the number of bores required for production i.e. Single

One concentric bore through the packer for use with a single tubing string.

Dual

Two parallel bores through the packer for use with two tubing strings.

Triple

Three parallel bores through the packer for use with three tubing strings.

A typical packer description, therefore, might be: 95/8“, dual 31/2“ x 31/2“, hydraulic-set retrievable packer.

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Figure 8.3 - Typical Wireline Landing Nipples

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8.2 TUBING PROTECTION JOINT This is normally a single tubing joint, short joint or pup joint and is used to prevent downhole gauges from buffeting in the flow stream. The protection joint is installed directly below the gauge hanger landing nipple in the tailpipe and must be long enough to accommodate the longest BHP toolstring that may be run.

8.3 WIRELINE LANDING NIPPLES Landing nipples, (Refer to Figure 8.3), are short profiled tubulars installed in the tubing string to accommodate wireline retrievable flow control devices. These can seal within the nipple bore if required, dependent upon the tool's function. The most common tools run are plugs, chokes, and pressure and temperature gauges. The main features of a landing nipple are:  Locking groove or profile  Polished seal bore  No-Go shoulder (only on nipples that rely on a shoulder for device location). Landing nipples are supplied in ranges to suit most tubing sizes and weights with API or premium connections and are available in two basic types:  No-Go or Non-Selective (or Selective by a Top or Bottom Shoulder).  Selective. 8.3.1 No-Go or Non-Selective

The non-selective nipple receives a locking device that uses a No-Go for location purposes. This requires that the OD of the locking device is slightly larger than the No-Go diameter of the nipple. The No-Go diameter is usually a small shoulder located below the packing bore (bottom No-Go) but in some designs, the top of the packing bore itself is used as the No-Go. Only one No-Go landing nipple of a particular minimum ID size should be used in a completion string. The No-Go provides a positive location and are widely used in high angle wells where wireline tool manipulation is difficult and weight indicator sensitivity is reduced. 8.3.2 Selective

In the selective system, the locking devices are designed with the same key profile as the nipples and selection of the nipple is determined by the operation of the running tool and the setting procedure. The selective design is full bore and allows the installation of several nipples of the same size and type. Uses of landing nipples are to:    

Plug tubing from above, below or from both directions for pressure testing. Leak detection. Install safety valves, chokes and other flow control devices. Install bottomhole pressure and temperature gauges.

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8.1 WIRELINE RE-ENTRY GUIDE A wireline entry guide is used for the safe re-entry of wireline tools from the casing or liner back into the tubing string. It attaches to the end of the production string or packer tailpipe assembly and, where possible, has a chamfered lead in with a full inside diameter. Wireline re-entry guides are generally available in two forms: 8.1.1 Mule-Shoe

This type of guide would be second choice on any completion design. Essentially it has the same function as the Bell Guide but incorporates a large 45° angle cut on one side of the guide, (refer to Figure 8.2a). It would only be used when the completion tailpipe has to be run into another packer, or past a Liner Hanger. Should the guide hang up on a casing item such as a liner or packer top while being run, rotation of the tubing will cause the 45° shoulder to ‘kick’ into, and enter the liner or packer. This item has a very limited re-entry chamfer, and has been known to cause severe re-entry difficulties for toolstrings in deviated Wells. 8.1.2 Bell Guide

This guide has a 45° lead in taper to allow re-entry into the tubing of wireline and Coiled tubing tools, and would always be the ‘first choice’ option. This type of guide, (refer to Figure 8.2b), is used in completions where the end of the tubing does not need to pass through any casing obstacles such as liner laps.

Figure 8.2 - Wireline Re-entry Guide

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Figure 8.1 - Generic Oil well Completion

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COMPLETION EQUIPMENT In general, a well completion should provide a production conduit which:  Maximises the safe recovery of hydrocarbons from a gas or oil well throughout its producing life.  Gives an effective means of pressurising selected zones in water or gas injection wells. Downhole accessories used should be designed to provide the safe installation and retrieval of the completion, and flexibility for sub-surface maintenance of the well using wireline, coiled tubing or other methods. Different types of wells present distinct design and installation problems for engineers. Most completions are just variations on a few basic design types and, therefore, in the majority of cases, the equipment used is fairly standard. However, there is a move to more versatile and complex equipment as used, for example in Smart Wells, but that is beyond the scope of this manual. An overview of the equipment commonly used in single and dual string completions is given in the following sections. The detailed operation of some the items such as sliding side doors (SSDs), side pocket mandrels (SPMs) and packers will not be covered in this manual. However, the relative location of these tools in a completion and their functions in intervention work or workovers will be addressed. Figure 8.1 shows a schematic drawing illustrating the location of equipment in a generic oil well completion. In order ensure compatibility between the manual and course lecture, the completion description will start from the bottom of the completion and work ‘uphole’.

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SECTION 8 COMPLETION EQUIPMENT

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Figure 7.3 – Typical Pump Hook-Up

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7.4 LUBRICATE AND BLEED For a gas well, or gas filled tubing, an alternative method is to use the lubrication kill. In this method varying amounts of mud are lubricated into the well, and the well pressure is bled off after each batch of mud has been lubricated into it. The method consists of the following steps: 1) Calculate the capacity of the tubing and pump half this volume of kill fluid to the well. 2) Observe the well (1/2 to 1 hour), the tubing head pressure will drop due to the hydrostatic head of the initial kill mud pumped. When the tubing head pressure is constant, the next step is taken. 3) Pump kill fluid for about 3 - 5 minutes, and not more than about 10 barrels, and making sure that the tubing head pressure does not go more than 200psi above the observed static pressure taken in step 2. 4) Bleed off gas from the tubing at a high rate immediately after pumping the batch of kill fluid. The amount of drop in tubing head pressure could be equal to the amount of hydrostatic head of the mud pumped. If the bleeding off is not carried out quickly, the additional pressure due to the extra hydrostatic head will cause mud losses and the sooner the tubing head is reduced, the smaller the loss will be. 5) Repeat the pump and bleed and observe the tubing head pressure after each step. If necessary, reduce the quantity of kill fluid if the amount of gas being bled off is excessive. After repeated pumping of batches of mud and the well is deemed dead, observe the well for a considerable period before starting any further work. 6) If the fluid level is too low, then the kill fluid has been too heavy and additional lighter fluid should be added until the well is full of fluid. 7) Alternatively, if the well will not die, it could be that too much gas was bled off or some of the kill fluid was blown out of the well during the bleed off cycle, resulting in gas flowing into the well bore. Wait for the well to settle and after re-appraising the situation, carry on with the batch and bleed procedure until the well is completely dead.

7.5 PUMP REQUIREMENTS The normal pump equipment required for a well kill is:     

Pump Unit Storage tank Pill tank (if necessary) Mixing tank Interconnecting pipe work with valving.

Refer to Figure 7.3 for a typical pumping hook-up.

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7.3 BULLHEADING (OR SQUEEZE KILL) This method consists of pumping kill fluid to the well and forcing the well fluids back into the formation at a rate that will not fracture the formation. This method is difficult to use on a well with fracture production. Bullheading is often used on wells that have not been completed with tubing, as it is easier to organise and accomplish compared to, for example, a coiled tubing well kill. It can also be used when the tubing has been landed in a packer and the circulation device, such as a sliding sleeve, cannot be opened, hence a circulation kill would not be possible without a tubing perforating service. In this method the pump rate has to be high enough to ensure that the rate the kill fluid is moving down the tubing is faster than it can free fall. This prevents the contamination of the kill fluid by the hydrocarbons in the tubing. In effect, the kill fluid displaces the hydrocarbons back into the formation. If the pump rate is not fast enough slippage of the hydrocarbons past the front of the kill fluid will occur and lessen the kill efficiency. An example of a bullhead/squeeze kill graph is shown in Figure 7.2. Normally this method only finds use in wells with small tubing and with high permeability allowing adequate pumping rates. In larger tubing (31/2"+) and in low permeability wells, this method is more time consuming and difficult, and especially gas wells and wells with high gas/oil ratios. This method also has the potential draw back in that some of the kill fluid is inevitably pumped into the formation. A bullhead kill graph is very simple to produce as the pump pressure line is simply drawn from the initial SITHP to the second point which is the overbalance at the volume of fluid required to the top of the formation. The fracture pressure gradient should also be plotted to ensure this pressure should not be exceeded during the operation.

Figure 7.2 - Typical Bullheading Pressure Chart

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An alternative method of using a circulation kill method is to use coiled tubing that can be run into the well under pressure. The well can then be killed by pumping mud down the small bore coiled tubing and back up the tubing/coiled tubing annulus. The procedure is the same as for the reverse circulation kill though, of course, this is actually a forward circulation procedure. The backpressure is held as before on the tubing to control the bottomhole pressure. This method would be used where it was not possible to establish communication around the tubing shoe or through a sliding sleeve, and where it is not desirable to bullhead.

Figure 7.1 – Typical Reverse Circulation Chart

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7.2 REVERSE CIRCULATION This kill method is the safest, and probably the simplest, as it uses the natural ‘U’ tubing effect of the different gravities of fluids in the annulus and tubing, to flow the well fluids out through the Xmas tree choke and existing flowlines to the production facilities. The only pump pressure required is to equalise across the circulation device before opening and, when the kill fluid is near in balance, tubing-to-tubing/casing annulus and circulating friction losses need to be overcome. This method requires a circulation path between the tubing and tubing/casing annulus to be opened by operating a circulation device in the completion string, or punching a hole in the tubing with wireline. The procedure is even more effective if a plug can be installed to isolate the completion/packer and kill fluid from the formation, but this is dependent upon whether or not operations are to be carried out below this point. If there is no plug, the old completion/packer fluid may contaminate the formation if losses occur before the clean kill fluid can enter the tubing. The well is circulated with a backpressure maintained on the tubing so that a constant bottomhole pressure can be maintained to eliminate any further flow of reservoir fluids into the well. In other words, maintaining a hydrostatic head on a formation that is greater than the actual formation pressure, but not too much greater, otherwise there will be excessive fluid loss, or even fracturing of the formation. To prevent any further inflow of formation fluids it is common practice to maintain a tubing pressure that is some 150 - 200psi. greater than the shut-in pressure. This will ensure that when pumping is started, the kill fluid pressure on the formation will be higher than the formation pressure. As the kill fluid is pumped to the tubing the surface pressure can be slowly reduced in proportion to the amount of fluid rise in the tubing. One of the main reasons for using the reverse circulation method is that it is easier to pump maintaining oil and/or gas on top of the kill fluid, than it is to force the oil and gas down below the kill fluid. There is far less contamination of the kill fluid with well fluids, and there is less of a problem in establishing a clean kill fluid for circulation. The slightly higher hydrostatic head on the formation is maintained during the kill operation reducing the chance of influx of the formation fluids. As the kill fluid moves up the tubing, the backpressure held on the tubing head is reduced. This can be shown in the form of a graph with tubing head pressure against time (assuming a constant pumping rate) or tubing head pressure against quantity pumped. (Refer to Figure 7.1). The operator on the choke will reduce pressure in accordance with the graph that is based on tubing capacity and the pumping rate. If there is a fluctuating pump rate there will have to be communication between the pump operator and the operator on the tubing head so that the pressure is reduced at the correct rate. The reverse circulation method can be used for all types of wells except possibly those with very high production rate and very low reservoir pressure. In this case it is not possible to have a kill fluid of sufficiently low hydrostatic head to kill the well without heavy losses, or where it is not possible to fill the tubing without exceeding the reservoir pressure.

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PRODUCTION WELL KILL PROCEDURES Well intervention personnel may be involved in preparing a production well for workover. This entails killing the well by displacing well fluids with workover fluids. The choice of kill procedure will depend on a number of factors including tubing and casing integrity, ability to circulate the fluid in the annulus, formation pressure, characteristics of the completion methods and formation parameters that may inhibit techniques such as pumping into the formation. Each well must be assessed individually to determine the most effective kill procedure to be implemented. The kill methods available are:     

Reverse circulation Forward circulation Bullheading Lubricate and bleed Deploying Coiled Tubing (or a workstring by Snubbing) and displacing the tubing.

As the completion tubing is normally full of well fluids, and the tubing/casing annulus full of completion or packer fluid, it is easier to conduct a reverse circulation as the gravities of the fluids will tend to keep them segregated as they are pumped up the tubing. The preferred method is to install a wireline set plug as low as possible in the well below the packer, (e.g. packer tailpipe), if possible, to isolate the formation from the kill fluid, and then reverse circulate to kill the well. Forward circulation is not recommended as it involves higher circulating pressures and disposal of formation fluids through the tubing spool side outlets is very troublesome to handle effectively. For these reasons this method is not described. Bullheading is only recommended where it causes no damage to the formation. Some operators have strict policies stating under which conditions this method may be used. Lubricate and bleed is the least preferred and is only used when there is some obstacle to conducting the other methods. For instance, it may be a combination of an obstruction in the tubing that prevents the running of wireline to open a circulating path (e.g. a partially closed valve) and a blockage or tight formation preventing bullheading.

7.1 WELL PREPARATION Prior to initiating well killing operations, several safety precautions must be exercised. The well must be shut-in in advance of operations to stabilise bottomhole pressure and allow time to inspect and service the Xmas tree. The tree valves and sub-surface safety valves should be tested to ensure they comply with API criteria. Where practicable, each annulus should be checked for H2S. The well shall then be isolated from all external control systems and the lines isolated by double barrier isolation and depressurised. The only exception is during kill operations when hydrocarbons are being flowed to the production system.

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SECTION 7 PRODUCTION WELL KILL PROCEDURES

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6.7 CIRCULATING PRESSURE LOSSES Pressure losses in the movement of fluids are due to friction between the fluids and the tubulars in the wellbore and surface lines. Friction is resistance to movement. A force is required to overcome friction of a body or substance from a position of rest to movement. The amount of friction to overcome this resistance is dependent upon a number of factors:        

Density of the body or substance. Type of substance. Roughness of the surfaces making contact. Surface area in contact. Thermal and electrical properties. Direction of movement. Velocity. The force required to overcome friction is termed frictional loss.

The pressure losses occurring during production well kill operations, are usually incalculable due to the lack of information on the relevant factors. These pressure losses are, therefore, not usually taken into account during well kill operations and are used as an additional safety factor.

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6.6 MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP With data from the formation integrity test, the maximum pressure, which can be applied without fracturing the formation, and the maximum fluid weight, can be determined. The formation breakdown pressure: =

Applied surface pressure + hydrostatic pressure of fluid in the casing

The applied surface pressure at which leak-off occurred, or at FIT pressure, is the maximum allowable annulus surface pressure with the fluid weight in use at that time. MAASP is the maximum surface pressure that can be tolerated before reaching the formation fractures. MAASP = Formation breakdown pressure – HP of fluid in use at the formation or re-written as: MAASP = (Fracture gradient – Fluid gradient) x TVD of formation or as: MAASP = (Max. equivalent fluid weight – Fluid weight in well) x (0.052 x TVD of formation). MAASP is only valid if the well is full of the original fluid during the LOT or FIT; if the fluid weight in the well is changed, MAASP must be recalculated. The calculated MAASP is no longer valid if influx fluids enter the well. In practise MAASP is calculated as a percentage of the original casing burst pressure rating. This percentage is derived from experience and the age of the well casings, i.e. if the well is old and it is suspected there is casing corrosion or wear, the percentage will be lower than that of a more recently developed well. In general, the pressure rating is 80% of original burst. This pressure is used in the equation in place of the formation breakdown pressure.

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6.5.2 Formation Integrity Test

A FIT can be performed when it is not acceptable to fracture a formation. In a FIT, fluid is pumped into the shut in well until a predetermined pressure is reached that is determined to be below the pressure to break down the formation. This value used is usually obtained by assessing information from well’s completion report and nearby well data. The procedure is: 1) 2) 3) 4) 5)

Before starting, gauges should be checked for accuracy. The casing should be pressure tested before well operations commence. Circulate and condition the mud, check mud density in and out. Close BOPs. With the well closed in, the pump is used to incrementally raise the pressure in the well to the test pressure and monitor the pressure to ensure that there is no leak off.

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Figure 6.2 - Idealised Leak-Off Test Curves

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6.5 FORMATION INTEGRITY TESTS To determine the fracture pressure of a formation, a leak-off test (LOT) or a formation integrity test (FIT) may be performed with a solids carrying fluid or mud. Where solids free workover fluids are used, a formation integrity test cannot be conducted and in these cases the formation is protected solely by a MAASP, which is set at a safe percentage of the original casing pressure rating, (i.e. 80% of casing burst pressure) LOTs and FITs determine if the cement seal between the casing and the formation is adequate and the maximum pressure or fluid weight that the formation(s) can withstand without fracturing. As the leak-off test actually causes a fracture to determine the fracture gradient, it is rarely used in well servicing operations and the FIT is adopted. Whichever is to be performed, it must be ensured that the well is fully circulated to the correct weight workover fluid and the pump deliverability is sufficient. 6.5.1 Leak-Off Test

The test is performed by applying incremental pressures from the surface to the closed wellbore/casing system until it can be seen that fluid is being injected into the formation. Leak-off tests should normally be taken to this leak-off pressure unless it exceeds the pressure to which the casing was tested. A typical procedure is as follows:  Before starting, gauges should be checked for accuracy. The upper pressure limit should be determined.  The casing should be pressure tested before well operations commence.  Circulate and condition the mud, check mud density in and out.  Close BOPs.  With the well closed in, the pump is used to pump a small volume at a time into the well typically a 1/4 or 1/2bbl per min. Monitor the pressure build up and accurately record the volume of mud pumped. Plot pressure versus volume of mud pumped.  Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped.  Bleed off the pressure and establish the amounts of mud, if any, lost to the formation. Examples of leak-off test plot interpretation: In non-consolidated or highly permeable formations, fluid can be lost at very low pressures. In this case the pressure will fall once the pump has been stopped and a plot such as that shown in Figure 6.2a will be obtained. Figure 6.2b and Figure 6.2c show typical plots for consolidated permeable and consolidated impermeable formations respectively.

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6.4 FORMATION FRACTURE PRESSURE The amount of pressure a formation can withstand before it splits is termed the fracture pressure. The pressure of fluid in a well must exceed formation pressure before the fluid can enter a formation and cause a fracture. Fracture pressure is expressed in psi, as a gradient in psi/ft, or as a fluid weight equivalent in ppg. In order to plan a conventional rig well intervention, it is necessary to have some knowledge of the fracture pressures of the formation to be encountered. If wellbore pressures were to equal or exceed this fracture pressure, the formation would break down as the fracture was initiated, followed by loss of workover fluid, loss of hydrostatic pressure, loss of primary well control and irreparable damage to the formation. Most operating companies have strict policies and procedures to ensure the fracture pressure is never exceeded (unless the formation was to be deliberately fractured for reservoir productivity improvement through sand fracing operations, etc.). Unless the service is to conduct remedial operations on or in the casing across the formation, it is preferred to isolate the formation from the kill fluid by installing a barrier or plug. Fracture pressures are related to the weight of the formation matrix (rock) and the fluids (water/oil) occupying the pore space within the matrix, above the zone of interest. These two factors combine to produce what is known as the overburden pressure. Assuming the average density of a thick sedimentary sequence to be the equivalent of 19.2ppg then the overburden gradient is given by: 0.052 x 19.2 = 1.0psi/ft Since the degree of compaction of sediments is known to vary with depth, the gradient is not constant. Onshore, since the sediments tend to be more compacted, the overburden gradient can be taken as being close to 1.0psi/ft. Offshore, however the overburden gradients at shallow depths will be much less than 1.0psi/ft due to the effect of the depth of seawater and large thickness of unconsolidated sediment.

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6.3.4 Subnormal Pressures

These are formation pore pressures, which are measurably less than normal and occur in formations, which do not outcrop and have not been compacted. These can be found in mountainous areas. Subnormal pressures occur less frequently than abnormal pressures and tend to be “lost circulation” zones. NOTE:

It is the abnormal and subnormal pressures that cause the most problems and, the further they deviate from normal, the greater the difficulties in well control

6.3.5 Pressure Gradients Formation Pore Pressure Gradient

The increase of formation pore pressure per unit of depth where the formation pore pressure is the maximum within a series of formations. Initial Formation Strength Gradient

The increase of Initial Formation Strength per unit of depth, where the Initial Formation Strength is expressed as the pressure at which the weakest formation in a series will break down and allow fluid to enter.

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6.3 FORMATION PRESSURE 6.3.1 Normal and Abnormal Formation Pore Pressures

The pressure at which a fluid or gas exists in the pores of a permeable rock is called the Formation Pore Pressure. Generally speaking, the greater the depth, the higher the pressure. The actual pressure in any formation is determined by :  The density of the fluid  Whether or not the formation containing the fluid outcrops at the earth’s surface i.e. whether or not the fluid is subjected to atmospheric pressure. If it is, and these are the only two factors affecting it, then the formation pore pressure is proportional to the hydrostatic head of the particular fluid. If the permeable formation does not outcrop, then a third factor influences the formation pore pressure:  Forces exerted on the trapped fluid by compaction or movements of internal forces within surrounding formations. Formation pore pressures are normally classified into three groups. 6.3.2 Normal Pressure

If the fluid in the pores is subject to hydrostatic pressure only, and the hydrostatic head is proportional to the vertical depth of the formation in the well, the pressure is said to be normal. Normal pore pressure is between 0.433 and 0.465psi/ft. 6.3.3 Abnormal Pressure

If a porous and permeable formation does not outcrop at the surface, then the fluid in the pores will be trapped. This fluid is almost certain to be subjected to several of the following conditions causing the pore pressure to rise, sometimes considerably:     

Compaction of the formation containing the fluid. Water squeezing out of the pores of surrounding clays or shale by compaction. Folding, faulting and thrusting, production compaction pressures and more traps. Thermal expansion due to increased temperature. Alteration in the rock constituents by temperature, pressure etc.

If the resulting pore pressures are above 0.465psi/ft they are said to be abnormal.

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6.2.6 Preparation of Brines

Brines are normally supplied in stored liquid form at the higher end of the weight range available, and are transported in bulk to the well site. The density is normally adjusted by adding water. In some rare circumstances where a higher weight was desired, or if the liquid had been accidentally contaminated with water, salt supplied in sacks would be added to build it up to the correct weight. Field mixing is not recommended, as the handling systems usually are not able to meet the high standard of cleanliness required to prevent contamination of the brine from incompatible liquids or solids. When brine densities reach saturation point, the salt will either crystallise or settle out and pose a real hazard to operations. Temperature changes in the well can also cause crystallisation or solids fall out. Crystallisation is sometimes called freezing, as it appears to form like ice. 6.2.7 Filtration and Cleanliness

Brines are usually filtered to a predetermined level of cleanliness, selected to meet the required demands, by a filtration unit or a centrifuge. The two main types of filtration units used are:  DE Filtration Press  Cartridge Units. The former uses Diatomaceous Earth formed as a cake on the faces of plates pressed together through which the fluid is pumped. 6.2.8 Health and Safety

The health of personnel and protection of the environment is paramount. The lower density brines such as sodium chloride are not harmful, but the higher density brines are exceedingly toxic. These should be handled carefully and all personnel involved in mixing, storage and handling should wear protective clothing and goggles. An emergency dousing shower should also be easily accessible close to the workplace. Some brines are also very corrosive to workwear, such as leather boots, and all precautions should be taken to avoid contact, or to ensure they are thoroughly washed after contact. 6.2.9 Pollution Control

In most countries, there is legislation regarding the use of hazardous materials, therefore, disposal should be in accordance to the local laws, and the well site appropriately constructed to capture and retain leakage or spillage. All movement or spillage of these materials should be recorded, and the appropriate authorities notified.

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6.2.4 Composition of Brines

The following list shows the various types of brines, composition and weight ranges: Potassium Chloride

KCl

8.3 9.7lbs /gal

Sodium Chloride

NaCl

8.3 10.0lb s/gal

Calcium Chloride

CaCl2

8.3 11.8lb s/gal

/Calcium

CaCl2/ CaBr2

11.8 15.2lb s/gal

Calcium Chloride/Calcium Bromide/Zinc Bromide

CaCl2/ CaBr2/ ZnBr2

14.5 19.2lb s/gal

Calcium Bromide/Zinc Bromide

CaBr2/ ZnBr2

14.5 19.2lb s/gal

Zinc Bromide

ZnBr2

13.5 21.0lb s/gal

Calcium Chloride Bromide

6.2.5 Brine Selection

Selection of the brine is not simply by picking the brine best fitting the particular weight range required, or by cost. For instance, the weight range of sodium chloride may provide the hydrostatic pressure required in a well, (say 9ppg), but it causes shales and clays to swell reducing permeability. Therefore if clays were present, as observed from cores etc., the brine selected should be potassium or calcium chloride. Potassium chloride is corrosive and an inhibitor should be added to maintain a pH of 7 to 10. Fluid compatibility is essential in the fluids design.

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To provide the properties required for each of the above, many types of fluids are utilised, e.g. drilling muds, milling fluids, brines (including seawater), salt saturated brines, diesel and dead oil. Some like the drilling or milling fluids, must have cuttings carrying capability, cool the bit or mill and reduce friction to deliver hydraulic energy downhole. Others used, say for circulating purposes, or to provide an overbalance only, may be clear brines or seawater etc. Completion or packer fluids are usually solids free to prevent drop out and sticking. These are also dosed with biocide, corrosion and/or scale inhibitors for long term protection of the formation and tubulars exposed to the fluid. However, one important function of them all, whether used as a completion fluid or in a re-completion, is that they must provide an overbalance at the packer depth, in case of a leak, to control well pressure. Generally, the most economic fluid, which meets all of the criteria is used and, if possible, it should be solids free and non-damaging. This criteria would tend to result in clear brines being used as they are cheap, readily obtainable, easily transportable and easily filtered in normal weight ranges. However the points, which make them desirable, are also their worst features in that they have no bridging capability, and are easily lost into the formation (unless the well is plugged). In this case, a LCM pill is usually placed against the formation to prevent or reduce the losses. The solids in the LCM pill are often designed to be removed by post re-completion flushing or acidising. The use of a high viscous pill as an LCM is not recommended as the long chain molecules, which plug the pores, cannot be removed by these methods. 6.2.3 Clear Fluids

At one time it was felt that poor well performance was due to reasons other than by damage from drilling muds and other fluids. When it was recognised that some formations were sensitive to invasion by foreign fluids and particles, operators began to look closely at this subject, and observed that fresh water was the biggest culprit. After this revelation, the use of low water loss muds, cements and non-aqueous fluids became the norm. Clear brines have become the commonest workover fluids as they not only meet most of the criteria, but are also a good medium in which to run and install tools and equipment. They are weighted by salts to achieve the desired densities. Brines are available in weight ranges from 8.3 to 21.0lbs/gal. The heavier brines can be very corrosive to metals and hazardous to personnel, hence require special handling. Personnel must use appropriate safety workwear and be aware of the hazards. They are also more difficult to prepare to prevent crystallisation or freezing.

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6.2 DAMAGE PREVENTION It should be an aim in any programme to prevent any damaging fluid from contacting the formation, if possible. If this cannot be achieved, then the use of clear non-damaging filtered brines should be adopted. In some cases where it is necessary to use LCM or similar materials then a post servicing stimulation should be considered to reduce the damage. 6.2.1 Well Plugging

The best means of preventing formation damage is to isolate the fluids entirely from the formation by installing a barrier in the form of a mechanical plug but this is only possible if the well programme does not require work below the lowest plugging point. The most common method of installing a barrier is by setting a plug in a packer tailpipe nipple on wireline leaving well fluid or gas across the formation. The plug can then be inflow tested to confirm there is no leak. If the tubing is to be removed from the well, wireline plugs can only be installed in completions with permanent or permanent retrievable style packers. An alternative when working on monobore type completions, is to install a retrievable through-tubing bridge plug close to the top of the formation. This has an advantage in that the packer or liner hanger packer above can be removed without disturbing the barrier. Whatever type of device is used for plugging, it must be designed so that it can be recovered from the well after the work is completed. Some scale, rust and other debris, will likely cover the plug, and although washing or bailing can remove most of it, some will remain. Most devices used generally have a long mandrel with a fishneck that stands above the plug enabling washing and latching with a pulling tool. Other devices such as pump-through plugs, allow the plug to be opened by application of tubing pressure above it. After, the well can be opened up to clean out the fill first before recovering the plug. Once the tubing is successfully plugged, and the plug tested, the well can be circulated to the workover fluid, i.e. brine, etc. 6.2.2 Workover Fluids

Fluids used in completing or servicing operations have many applications. They are employed in perforating, cementing, fracturing, acidising, well killing, re-completing, milling, drilling, cleaning out and preventing fluid losses. They may also have an important long-term function as an annulus packer or completion fluid.

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6.1.4 Well Intervention

Some well interventions and most notably when fluids are placed against the formation will cause damage. Typical damage is:    

Pore, vug or fracture plugging by solids in circulating or well kill fluids. Permeability reduction through filtrate invasion by circulating or kill fluids. Sand face/cement breakdown due to effects during acid stimulation. Permeability reduction due to insoluble precipitates formed during acid stimulation with hydrofluoric acid.  Formation blocking with long string molecules in high viscous fluids or diverting agents.  Clay swelling from incompatible brine or water contamination.  Pore or perforation plugging due to bullheading with scale or debris in the tubing and casing. To prevent the risk of these occurring, it is obvious that well interventions require thorough planning to minimise formation damage.

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All completion and service equipment, especially the tubing should be thoroughly cleaned before being installed and thread dope used sparingly. If the well is to have an open hole type completion, then the well fluids programme should be designed to prevent formation damage. However, in practice this is difficult and most engineers acknowledge damage will be caused to some extent. In the situation where LCMs need to be used to support the workover fluid, the engineer must select a material, which can be easily removed afterwards. Sized salt or calcium carbonates are examples where the former is cleared by flushing with water, and the latter with an acid wash. 6.1.3 Producing

Although it may be of some surprise, damage can occur during the producing phase of a well. This is normally due to the production of asphalt, wax or scales but can also be due to other chemicals contacting the formation. Common types of damage:  Reduced permeability if formation is in contact with corrosion, scale or paraffin inhibitors.  Formation or perforation blocking with precipitated scale.  Asphalt deposition around the wellbore can cause plugging and oil wetting, which in turn can cause emulsion blocking.  Permeability reduction due to movement of fines through the reservoir.  Altering relative permeability detrimental to production due to increasing water production.  Clay swelling due to contamination with incompatible brines or water.  Plugging due to contamination with fill, silt or crud. Many of these can be remedied or reduced by clean-out or stimulation operations.

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6.1.1 Drilling/Casing

Drilling fluids usually contain chemicals and/or solids as bridging agents to control the loss of drilling fluids. Fluid losses can lead to well control problems and are also expensive to replenish, especially when using the more exotic mud systems such as Pseudo or Oil based muds etc. Drilling fluids cause the following types of damage:  Solids plugging of pores, vugs or fractures either natural or induced.  Clay swelling reducing permeability.  Filtrate penetration detrimentally changing the relative permeability to producing fluids. Similar damage can be caused during the casing cementing process for the production casing by cement pre-flushes and cement slurries. Non-damaging drilling fluids are often used to penetrate the producing formations when the wells are to be completed with open hole, barefoot or gravel pack type completions. In the main, however, damage done during the drilling is not a serious problem in most wells as they are usually to be perforated. The perforating depths, under normal circumstances, exceed the depth of any damage areas. They also generally have a total flow area greater than the tubing area; hence there is little impediment to achieving maximum production rates. Perforating is usually carried out in a clear non-damaging fluid such as brine or fresh water so that minimal post perforating damage is caused. 6.1.2 Completing

The damage caused during the completion phase, compared to drilling, is generally minimal if good completion designs and practices are employed. Most damage caused would be through contamination by fluids or pills used containing loss control materials (LCM) and other foreign bodies. Possible damage may be:      

Plugging of pores, vugs and fractures by LCM. Clay swelling due to incompatible well fluids. Deposition of mill scale, rust or thread dope. Perforating tunnels plugged by perforating debris from the shaped charges. Perforating tunnel compaction or crushing caused during the perforating process. Cleaning up at too high a rate causing movement of formation fines to plug pores.

With current technology it is easy to complete wells and displace to clean filtered brines or fresh water before perforating, thereby reducing the risks of any damage occurring. Also, most perforating is done with an underbalance pressure in the tubing, which reduces the amount of invasion. Displacing the tubing (fully or partially) to a lighter gravity fluid such as diesel, base oil or fresh water creates this underbalance. If a fluid cannot provide sufficient underbalance or if a very high underbalance is demanded, nitrogen can be used although it is much more costly.

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6

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PREVENTION OF FORMATION DAMAGE Damage to the formation can be caused by many mechanisms. Although some of these may be due to well conditions, the majority is through contamination of the formation by foreign substances not only during the drilling, completing and producing phases but also during the servicing of a well. These damage mechanisms are described in Section 6.1 below. To prevent damage, which reduces the productivity of a well, it is essential to be able to preferably isolate the formation from the contaminants or, if not possible, reduce the amount of contaminants in the fluids by conducting remedial stimulation operations. These are discussed in Section 6.2.

6.1 FORMATION DAMAGE The types of damage, which can occur during the different phases of a well’s life, are described in the following section. Refer to Figure 6.1 for the effects of skin damage to the well pressure profile.

Figure 6.1 - Formation Damage Pressure Drop

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SECTION 6 PREVENTION OF FORMATION DAMAGE

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NOTES PAGE

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5.6 PARTIALLY DEPLETED RESERVOIRS Similar to low-permeability Wells, in a depleted oil reservoir, an effective artificial lift system can be installed to increase production. If a Well was originally planned and designed for gas lift, and completed with gas lift mandrels in the string, then the gas lift valves are simply installed by wireline intervention. However, if a re-completion is needed, a full dead Well workover would be necessary. In high angle Wells, gas lift valves can be installed by coiled tubing methods. Improved recovery by reservoir pressure maintenance is usually the best long-term approach to increased production rates.

5.7 SAND CONTROL There are normally two solutions to control unconsolidated sand and these are; to gravel pack or, install a pre-packed screen, although resins are occasionally used. The drawback of having to implement such sand control measures is that they reduce productivity typically by 10% to 15%. The installation of a gravel pack entails a full workover and re-completion, although new snubbing methods with an HWO unit have now been developed. For a successful gravel pack it is important to ensure that clean fluids, (containing little or no dispersal solids), are used on initial completion or when the gravel pack is installed. A second requirement is that the gravel is correctly sized in relationship to the formation sand to prevent further ingress, or alternatively cause a blind off. It is also desirable, if completing in a sand zone that is known to be unconsolidated, that the gravel pack is installed immediately, as it is more difficult to install at a later stage. If an Open Hole (external) gravel pack is required, the hole will need to be enlarged to about twice its size by under-reaming before the liner/screen is run. Properly sized gravel is placed outside the screen by reverse circulation techniques. External gravel packs are utilised when high production rates are required. Internal gravel packs are the norm, but do incur a penalty by causing reduced production rates. The use of pre-packed screens has risen in recent years as they can often be installed in an existing completed well avoiding re-completion; however they are more prone to blinding off. They do not provide the same effectiveness as a regular gravel pack in controlling the production of fines.

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5.5 STIMULATION OF LOW PRODUCTIVITY WELLS There are many reasons why a Well may have low productivity, for instance:         

Formation damage Low permeability Pressure depletion. Liquid hold up in a gas well Gas slip in an oil well Sand or other fill or debris, (refer to Section 5.2) Excessive water or gas production, (refer to Section 5.3) Mechanical failure, (refer to Section 5.4) Artificial lift failure.

You will note that some of the above have already been addressed in previous sections. With regard to the others in the list, there may be a number of possible solutions for each problem. For instance:  Reservoir problems such as formation damage and low permeability can sometimes be improved by stimulation operations, such as, acidisation or hydraulic fracturing.  In oil or gas Wells where there is liquid hold up or gas slip, this is often countered by installing smaller diameter tubing strings. These may be Reeled Tubing strings installed inside the original completion by large size CT units. This tubing reaches down into the sump and provides a smaller flow area to improve liquid lift. These reeled strings are normally 23/8“, 27/8” or 31/2” OD and are run and hung off on a wireline lock, tubing packer, or similar device.  The tubing is snubbed into the Well by normal CT methods from large reels. When the correct length of tubing is in the Well and has been attached to the lock mandrel, it is run to setting depth and set on regular size CT.  The main disadvantage with this solution is the high weight of such large reels, which is often above the lifting capacity of some offshore installations. Smaller, more manageable, reel sizes entail more undesirable offshore connections to make up the full length of tubing required. These problems, however, are outweighed when set against the costs of a full programme to re-complete.  An artificial lift system is usually required in any low permeability Well to give adequate production rates. A work programme to re-complete this type of Well is required once the Well flow has reached the minimum economic acceptable natural flow. If the Well has already been on gas lift and it is no longer efficient, then the design should be reviewed to optimise the existing gas lift mandrel spacing against re-completing with the optimum mandrel depths.

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5.4 MECHANICAL FAILURE Well service operations to repair mechanical completion failures are still relatively common in old Wells, however in new Wells less servicing is required due to the increasing reliability of modern completion equipment. In the past, one of the most common reasons for working over a Well was to replace downhole safety valves that had failed. For this reason, engineers were inclined to install wireline retrievable valves as they could easily be replaced using live Well interventions by wireline methods, hence avoiding the need to pull tubing. Nowadays, this is no longer the case as the reliability of tubing retrievable valves has increased substantially where it is now the most commonly used valve. Probably the most common reason for remedial mechanical operations today is tubing failure due to erosion or corrosion. Some completion failures can be repaired by wireline or CT methods but, in some circumstances, a full workover programme to pull the tubing is necessary. Typical failures are:        

Downhole safety valve mechanical failure or leak. Casing, packer or tubing leaks. Casing collapse. Tubing collapse. Cement failure. Gas lift failure or inefficiency. ESP or hydraulic pump failure. Recover fish unable to be recovered by intervention methods.

A full workover programme usually entails the placement of an overbalance kill fluid against the formation, unless it can be isolated using a plug. For example, a Wireline plug in a permanent packer tailpipe, or setting of a through tubing plug in the casing above the producing zone(s).

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Figure 5.4 - Increasing Gas Cap During Oil Production

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Figure 5.3 - Water Production by Coning

5.3.2 Control of Gas Production

The most common reason for excessive gas production is the growth of the gas cap as oil is produced, (refer to Figure 5.4). A gas/oil contact will gradually move downward causing an increase in the production of gas. The common method of remedying excessive gas coning is to squeeze the gas producing zone and deepen the well by re-perforating (converse to water coning). An alternative is to conduct a workover where the well is plugged back and side-tracked with the new hole drilled horizontally through the lower part of the reservoir avoiding the gas cap. In a layered reservoir, gas producing zones can also usually be effectively squeezed off with cement. Again, most cement squeezes can be accomplished with CT methods using throughtubing tools.

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Figure 5.1 - Water Fingering Due to Heterogeneity’s

Figure 5.2 - Advancing Oil/Water Contact

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Sand placement in the sump may solve the problem in circumstances where there is a sufficient height of sand as the vertical permeability of a column of sand is high and blocks water flow. Cement squeezes have probably been the commonest means of plugging off water producing zones in the past utilising workover methods. This often requires killing the Well, pulling the completion, cementing and re-completing. High production liner or monobore type completions have been specifically designed for through tubing operations. This enables water control by simply installing a through tubing bridge plug by wireline or CT, after which cement can be squeezed, if necessary. Cement squeezing by CT below regular packer style completions using modern through tubing tooling, is now also common practice. Water blocking by creating a gel in the formation is a much more recent development. This entails pumping chemicals to the formation, which react after a pre-determined period of time to form a gel. The viscosity of the gel is so high that it remains in the formation pores, blocking the flow of water trapped behind the gel. This method is usually expensive due to high chemical costs. Plugging back of water producing zones may on occasions require the Well to be re-completed if the packer has to be moved, or if shallower zones need to be perforated and brought on stream.

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5.3 CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION As an oil zone is depleted, the gas/oil or water/oil interfaces will move vertically in the formation. This may result in increasing undesired water or gas production. Excessive gas production leads to a premature decrease in reservoir pressure, hence reducing the energy available to move the oil into the well bore, and ultimately reduces the quantity of gas necessary to lift the oil to surface. When excessive water is produced, it leads to reduced oil production due to; the increased hydrostatic head in the tubing acting against the formation pressure, increased risk of corrosion and production problems in handling and disposing of the water. It may also cause sand production that can lead to erosion of completion and production equipment. These problems can be controlled by the appropriate well intervention measures, as described below. 5.3.1 Control of Water Production

There are different reasons for water problems: Firstly, fingering of water in stratified or layered reservoirs where the water production is essentially from one zone. Refer to Figure 5.1 Secondly, advancing water level due to oil depletion. Refer to Figure 5.2 Thirdly; water coning in reservoirs where there is appreciable vertical permeability. Refer to Figure 5.3 Once a rock becomes more saturated with water, the relative permeability to water increases in regard to that of the other fluids. This leads to a self-aggravating cycle of increasing water flow and increasing relative permeability to water. Prior to running or planning operations for water control, production logs must be run which will identify the zones from which water is being produced. Once identified, this can usually be controlled by a number of differing methods depending upon the specific well design and well conditions:    

Sand placement in the sump Setting a through tubing bridge plug Cement squeezing Chemical treatment to produce a gel block.

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5.2 TUBING BLOCKAGE Tubing blockage is generally caused by sand, wax and asphalt production, or scale build-up. It can usually be remedied with a Well clean out operation. Some of these can be prevented, or at least alleviated, by treating the formation with regular chemical inhibition treatments, pumped into the formation from the surface. With regard to injection Wells, severe formation scaling can occur if injection water is not treated to be compatible with the formation fluids. Tubing blockage is one of the most commonly experienced production problems and is remedied by clean out operations conducted by snubbing or coiled tubing (CT) intervention, although dead Well workover may also be considered. The use of snubbing or CT is more desirable as they can be carried out without killing the Well. CT is preferred as it is relatively low cost, is easily organised and very effective when used in conjunction with modern jetting or clean-out tools (especially with the larger CT sizes which allow higher pump rates). In most circumstances, flowing of the Well helps with the efficiency of the clean out. Wax build-up can be removed by an operation termed ‘Hot Oiling’. This is a simple treatment consisting of pumping heated oil from surface at a temperature sufficiently high enough to melt the wax. This can also be done by circulation of the hot oil through CT, which is preferred, as it prevents any fluids being pumped to the formation. Asphalt can also be removed similarly by pumping solvents rather than hot oil. Some well clean outs may be accomplished with wireline methods using tools such as gauge cutters which can remove wax from tubing walls, and bailing to remove sand or other blockages, provided the amount to be removed is relatively small. It is often easier to use wireline, even if it may be less efficient, as many platforms are already equipped with permanent wireline units or they can be easily mobilised. CT takes longer to rig up and deploy. These are considerations which need to be taken into account during the evaluation process. However in general, most operations can more efficiently be accomplished using CT, and it is sometimes the only option if the Well is high angle or horizontal. The general limit for wireline operations is circa 70° from vertical but this may vary according to Well build up angles and the types of tools to be run. Snubbing using a Hydraulic Work Over unit (HWO) may also be considered but it is generally slower and therefore more costly in comparison with CT. However, in some circumstances, e.g. where there is not enough space for a CT injector, or the large reel size, or where large size pipe is required for work on horizontal wells, Hydraulic Snubbing may be the alternative.

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5 REASONS FOR WELL INTERVENTIONS 5.1 GENERAL Many servicing operations can be conducted by rig workovers, however live well intervention is preferred as killing a well risks fluid invasion of the formation, thereby causing potential formation damage. The primary objective of Well intervention operations is the management of Wells to provide optimum Well production. This is achieved by conducting live Well remedial operations, obtaining downhole reservoir data or preparation of the Well for a dead Well workover (if live Well servicing cannot solve a problem). Occasionally, gathering of downhole reservoir data is a secondary objective only opportunistically taken when an intervention is planned for other reasons. This data are usually to provide Well information on lateral and vertical movement, current location of oil, water and gas and identifying and producing the zones. There are many reasons for remedial live Well intervention, Well operations, most notably to:    

Remove obstructions to flow such as tubing blockage with sand, wax or asphalt. Eliminate excessive water or gas production. Repair mechanical failure. Improve production through well stimulation, re-completions or multiple completions on low productivity Wells.  Enhance production by conducting Well stimulation such as hydraulic fractures on high productivity Wells.  Increase production by bringing other additional potentially productive zones on stream. Before a well is entered, a complete analysis must be made of the current Well status, the reasons for work carefully established, the associated risks identified and appropriate contingency measures planned in the event of operational failure. All oil and gas Wells will encounter some impairment to production during it’s producing life and Well service operations need to be planned either, to rectify, or improve, the conditions within the Wellbore. Therefore, common servicing operations such as cleaning out fill, re-perforating, chemical treating, acidising, fracturing or a combination of these techniques are routinely carried out to enhance production. A description of these main Well problems is discussed in the following sections.

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SECTION 5 REASONS FOR WELL INTERVENTIONS

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COMMON CALCULATIONS

ANNULUS FLUID

=

usually in pounds per gallon (ppg)

Calculation = ppg x 0.052 x depth

=

Annulus hydrostatic pressure

GAS COLUMN PRESSURE

=

must find Conversion factor (Gas Table)

Find depth of Gas Column, (Left hand side of table on Gas Table) Find Gas Gravity (at top of table) then cross-reference Correction factor x SITHP (Shut in tubing head pressure) = Press. At bottom of gas column i.e. Well depth 4000’ - Gas Gravity 0.7 - SITHP 2500psi = Correction Factor 1.102 x 2500(SITHP) = 2755psi OR : Gas Gradient x Depth of Gas Column = Pressure at depth of Gas Column i.e. - 0.2psi/ft x 5000ft = 1000psi (At bottom of Gas Column) API OIL - TO FIND THE GRADIENT (Constant) = Specific Gravity (SG) Specific Gravity x Gradient of Fresh Water = Gradient of Oil i.e. 32 API Oil =

=

= 0.865 SG x 0.433 = 0.375 (Oil Gradient)

Gradient of Oil x Depth of Oil column = Pressure at bottom of column (Hydrostatic)

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Capacities and Pumping

CASING CAPACITY

=

Amount of Fluid in Casing

TUBING CAPACITY

=

Amount of Fluid in Tubing

TUBING DISPLACEMENT

=

Amount of Fluid Displaced from the Casing when the Tubing is installed.

PUMP DISPLACEMENT

=

Amount of Fluid Displaced for each Pump Stroke

TUBING SHOE

=

Bottom end of Tubing i.e. Wireline Re-entry Guide

Tubing Capacity

=

0.00829 bbl/ft (Barrels per foot) x 9000 = 75bbls

Pump Displacement

=

0.0899 bbl/stroke

Tubing Shoe at

=

9000ft MD (Measured Depth for Volume Calculation)

Example:

To Calculate Number of Pump Strokes to Displace Tubing Volume =

Tubing Capacity

Pump Displacement x Tubing Shoe Depth (MD) i.e. 0.00829 0.0899 = 0.0922 x 9000 = 830 strokes BARRELS PER MINUTE Pump Rate

=

Barrels Pumped each Minute

Tubing Capacity

=

75 bbls - Pump Rate = 1.25 bpm (Barrels per minute)

Example:

75 1.25 = 60 minutes

TO FIND WELL KILL FLUID DENSITY Formation Gradient

0.570 0.052 = Kill Fluid (ppg) Example :

= 10.96 ppg

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DICTIONARY

MD

= MEASURED DEPTH – (for calculating volumes)

RVD

= TRUE VERTICAL DEPTH – (for calculating pressure)

FORMATION PRESSURE

= Bottom hole pressure (at formation)

FORMATION GRADIENT

= Average weight of all fluid & gas in the well

HYDROSTATIC HEAD

= Weight of fluid/Gas column (At bottom of column)

UNDERBALANCE

= Hydrostatic head is “LESS” than Formation Pressure

OVERBALANCE

= Hydrostatic head is “MORE” than Formation Pressure

KILL FLUID

= Calculated hydrostatic pressure equal to bottom hole pressure

PUMP BOTTOMS UP

= Pump down tubing and return fluid from the bottom of the Well, up the annulus to the surface (Drilling Term requiring Annulus Volume calculation)

VOLUME OF WELL

= Total fluid in annulus and tubing

COMPLETION FLUID

= Fluid in the Well during completion (usually left in annulus)

COMPLETION FLUID DENSITY = Weight of completion fluid per gallon OIL DENSITY

= Weight of oil per gallon

SIWHP

= Shut in well head pressure

SITHP

= Shut in tubing head pressure (Same meaning as above)

CIWHP

= Closed in tubing head pressure (Same as above)

CITHP

= Closed in tubing head pressure (Same as above)

FORWARD CIRCULATION

= Down tubing/up annulus

REVERSE CIRCULATING

= Down annulus/up tubing

BULLHEADING

= Pumping down tubing into formation

THIEF ZONE

= A zone/formation that takes fluid

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VOLUMES

It is important that Well Services personnel are able to calculate volumes as well as pressures. This is important for any pumping or killing operations undertaken. Where pressure calculations are calculated using ‘TVD’, calculations for volume must use ‘MD’ (Measured Depth). If the appropriate tables are not available, i.e. Baker Tech Facts or Halliburton Red Book, then the following Calculations can be used: The capacity of a section of pipe in bbl/ft. Is: C =

Where D = diameter in inches

The capacity of an annular space in bbl/ft. Is: C =

Where OD & ID are diameters in inches

Having obtained the capacity of a length of pipe from tables or from calculation, the total fluid volume can be Easily calculated by: Fluid volume = capacity x length (i.e. MD measured depth)

Where fluid volume is in bbl. Capacity is in bbl/ft Length is in bbls/ft - (USE MD NOT TVD) It’s probable that a calculation will be required for the time it will take to pump the fluid volume Time to pump = Where time is in minutes Volume is in bbls. Pump rate is in bbls/min. (bpm) Pumps are also used which are given in strokes per minute. With this type of rig pump the output, (bbls/stroke) this will be known, and is usually approx. 0.117 strokes depending on liner size. Therefore at 40spm (strokes/min) this gives 40 x 0.117 = 4.68 bpm

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HP of brine in annulus at circulation device: =

10.29ppg x 0.052 x 8,200ft

=

4,387psi

HP of gas cap: =

=

1.087 (from table) x 600psi

652psi

HP of oil column Oil SG= =

141.5 131.5  32 0.865

HP of oil column =

=

0.865 SG x 0.433psi/ft x (8,200 - 4,000)ft

1,573psi

Total HP in tubing =

HP of gas + HP of oil

=

652psi + 1,573psi

=

2,225psi

Differential pressure across circulation device =

HP of annulus - HP of tubing

=

4,387psi - 2,225psi

=

2,162psi from annulus to tubing

If the circulation device were to be opened, then the opening toolstring would be exposed to 2,162psi differential pressure. If using wireline, this pressure differential will need to be equalised before opening the device, otherwise, there is a high risk of having the toolstring ‘blown up the hole’.

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Figure 4.2 - Example of Production Well

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Well Depth

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Correction Factors(Gravity) 0.6

0.7

0.8

0.9

3,000

1.064

1.075

1.087

1.098

3,500

1.075

1.089

1.102

1.115

4,000

1.087

1.102

1.117

1.133

4,500

1.098

1.115

1.133

1.151

5,000

1.110

1.129

1.149

1.169

5,500

1.121

1.143

1.165

1.187

6,000

1.133

1.157

1.181

1.206

6,500

1.145

1.171

1.197

1.224

7,000

1.157

1.185

1.214

1.244

7,500

1.169

1.204

1.232

1.264

8,000

1.181

1.214

1.248

1.282

8,500

1.193

1.239

1.266

1.304

9,000

1.206

1.244

1.282

1.324

9,500

1.218

1.259

1.302

1.345

10,000

1.232

1.275

1.320

1.366

10,500

1.244

1.289

1.338

1.388

11,000

1.257

1.306

1.357

1.410

11,500

1.270

1.322

1.376

1.433

12,000

1.282

1.338

1.395

1.455

12,500

1.297

1.354

1.415

1.477

13,000

1.311

1.371

1.434

1.500

13,500

1.324

1.388

1.455

1.523

14,000

1.338

1.405

1.475

1.548

14,500

1.352

1.422

1.495

1.573

15,000

1.366

1.438

1.515

1.596

Table 4.1 - Gas Correction Factors

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Using the calculations already given in earlier sections and the gas correction factors, hydrostatic pressures in relatively complicated systems can now be determined. Example What is the differential pressure between the annulus and tubing at a circulation device installed at a depth of 8,200ft TVD in the tubing string?     

The following are the well conditions: The tubing/casing annulus is filled with a10.29ppg brine. The well is shut in at surface with a CITHP of 600psi There is a gas cap of 0.6SG gas from 4,000ft There is 32API oil from 4,000ft to 12,000ft

To help in the calculation, it is sometimes better to make a sketch. (Refer to Figure 4.1).

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Example A 10,500ft TVD well has two fluids in the well, a 15 ppg fluid from TD to 7,125ft and 8.33ppg fluid to surface, what is the HP at the bottom of the well ? HP of 15ppg fluid

=

15ppg x 0.052 x (10,500 - 7,125)ft

=

15ppg x 0.052 x 3,375ft

=

2,633psi

HP of 8.33ppg fluid = =

3,086psi

Total HP =

8.33ppg x 0.052 x 7,125ft

=

2,633psi + 3,086psi

5,719psi

4.1.5 Gas Correction Factors

Most well servicing operations entails working with live wells whether using a through-tubing method or rig intervention. Even with a rig operation, the well must be prepared by being killed prior to the intervention. This involves dealing with gas in the well. Production wells with gas in the fluids will exert a static surface pressure equal to the formation pressure less the hydrostatic pressure in the production bore. The gas entrained in the production fluids will segregate from the liquids as shown in Figure 4.. In a static situation, the closed in tubing head pressure (CITHP) and hydrostatic pressure will balance the formation pressure. As discussed earlier, gas is also a fluid and exerts a hydrostatic pressure. Being compressible, pressure affects the density of the gas. A set of correction factors are used to calculate hydrostatic pressures at varying TVDs with a range of gas gravities (refer to Table 4.). The correction factor, according to the TVD of the gas column and the gas gravity, is multiplied by the CITHP: HP

=

Correction factor x CITHP

Example What is the HP of a 5,000ft TVD column of 0.7 SG (Correction factor i.e. 1.129 see table) gas with a closed in tubing head pressure of 1,650psi HP of gas =

= 1,863psi

1.129 x 1,650psi

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Figure 4.2 - Measured Depth verses True Vertical Depth

Example What is the Hydrostatic Pressure of a 500ft TVD column of fresh water? HP

= 0.433psi/ft x 500ft = 216.5psi

Example: What is the hydrostatic pressure of a 6,750ft well, filled with a 0.478psi/ft pressure gradient fluid, which has a TVD of 6,130ft? HP

= 0.478psi/ft x 6,130ft = 2,930psi

Example A 12,764ft TVD well is filled with a 15ppg fluid, what is the BHP. HP

= 15ppg x 0.052 x 12,764ft = 9,956psi

Equipped with this knowledge, it is now easy to calculate the hydrostatic pressure with two or more fluids in a well provided the depths (TVD) of the fluid interfaces are known. Using the same formula, the HP for each fluid section is calculated in the same way and the sum of the individual calculations gives the HP at the bottom hole or well.

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4.1.3 API Gravity

API gravity is another value used to express relative weight of fluids, and was introduced by the American Petroleum Institute to standardise the weight of oilfield fluids at a base temperature of 60° F. Water in this case was also used as the standard and assigned the value of 10API gravity. To convert from API gravity to specific gravity, the following formula is used. 141.5 SG = 131.5 + API Example: What is the SG of 30° API oil.

141.5 o SG = 131.5  30

=

0.876

4.1.4 Hydrostatic Pressure

Hydrostatic pressure (HP) is the pressure developed by a fluid at a given true vertical depth in a well irrespective of the measured depth (Refer to Figure 4.2). ‘Hydro’ means water, or fluids, which exert pressure and ‘static’ means motionless. So hydrostatic pressure is the pressure created by a stationary column of fluid. The hydrostatic pressure of any fluid can be calculated at any true vertical depth (TVD) provided the pressure gradient of the fluid is known. The previous calculations have dealt with fluid pressure with a gradient of one foot depth but it is now simple to determine the pressure exerted by a fluid at any true vertical depth by multiplying that pressure gradient by the true vertical height of the column in feet. The true vertical height of the column is the important factor in the equation, as its volume or shape is irrelevant. The equation is: HP = PG x TVD where: HP

=

Hydrostatic pressure

PG

=

Pressure gradient

TVD =

True Vertical Depth

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A cubic foot of fresh water weighs 62.4 pounds therefore the weight per gallon is 62.4/7.48 = 8.33ppg. Therefore the gradient of fresh water is 8.33ppg x 0.052 = 0.433psi/ft Example: The pressure gradient of a 10 ppg fluid = 10 ppg x 0.052 = 0.52psi/ft Example: Find the weight of a fluid, which has a gradient of 0.465psi/ft 0.465 psi / ft 0.052

=

8.94ppg.

This constant is probably the most useful constant used in calculations. 4.1.2 Specific Gravity

Many fluids in the oilfield are also expressed in specific gravity (SG) as well as weight in ppg. It is also necessary to be able to convert SG to pressure gradient in order to calculate hydrostatic pressures. SG is the ratio of the weight of a fluid (liquid) to the weight of fresh water. Fresh water weighs 8.33 ppg and salt water is nominally valued at 10 ppg. Therefore, the SG of salt water is: 10 ppg SG of Salt Water = 8.33 ppg

= 1.2

The SG of fresh water is 1.0. As the gradient of fresh water is known to be 0.433psi/ft, to obtain the gradient of a fluid, it is simply necessary to multiply its SG by 0.433psi/ft Example: What is the hydrostatic pressure (HP) exerted by a true vertical 5,000ft column of brine with a SG of 1.17. HP of brine = 1.17 x 0.433psi/ft x 5,000ft =

2,533psi

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Figure 4.1 - Fluid Pressure Diagram

A cubic foot contains

7.48US gallons.

Therefore if the cube was filled with a fluid weighing 1ppg, the cube would weigh 7.48lbs The pressure exerted on the base (area) is: 7.48 lbs 1ft 2

=

7.48lbs/ft2

1ft2 = 12” x 12” area = 144sq inches, therefore the pressure per squared inches is 7.48 lbs 144

=

0.052psi

This relationship between a fluid weight in ppg and gradient pressure in psi/ft is always the same therefore, 0.052 is a constant.

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PRESSURE BASICS

4.1 FUNDAMENTALS OF FLUIDS AND PRESSURE Understanding pressures and pressure relationships is important in understanding well control. Pressure is defined as the force per unit area exerted by a fluid i.e.: Pressure

=

Force Area

Therefore, the formula can be changed to calculate the force from a given pressure and a unit area: Force

=

Pressure x Area

Pressure is usually expressed as the pounds of force that is applied against a one square inch area, i.e. pounds per square inch (psi). Therefore, when a gas is placed in a pressure tight container, it exerts a pressure on all sides of the container. If the gas pressure is 100psi, it exerts a force of 100lbs on each square inch of the container area. Similarly, if a liquid is placed in a can, it exerts a pressure on the sides and bottom of the container due to the weight of the liquid, which is also expressed as psi. In well control, both of these effects are of the utmost importance. Pressure can be expressed as absolute or as gauge pressure. Absolute pressure includes atmospheric pressure that is also applied due to the weight of the atmosphere and is 14.7psi. Some gauges, especially BHP gauges, are calibrated in absolute terms, but regular gauges showing psig indicate they have been calibrated at atmospheric pressure, and the 14.7psi is excluded. Although this is a relatively small amount and can be ignored in most instances, it is important when gathering data for reservoir analysis. 4.1.1 Fluid Pressure

A fluid is any substance that is not solid and can flow. Liquids like water and oil are fluids. Gas is also a fluid. Under certain conditions, salt, steel and rock can become fluid and in fact almost any solid can become fluid under extreme pressure and temperature. In well control, fluids such as gas, oil, water and completion fluids, brines and mud are encountered. Fluids exert pressure that is caused by the density, or weight of the fluid. This is normally expressed in pounds per gallon (ppg) or pounds per cubic foot (lbs/ft3). Other abbreviations for these are lbs/gal and ppf3. As the pressure developed by a fluid is relative to the true vertical depth, it is often expressed as psi per foot (psi/ft). This is termed the fluid’s pressure gradient. The pressure gradient for a fluid is relative to the fluid’s weight or density. The higher the density, the higher the pressure gradient. To understand this relationship, it is helpful to visualise a cubic foot of fluid. (refer to Figure 4.1).

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SECTION 4 PRESSURE BASICS

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NOTES PAGE

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NOTES PAGE

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If there is a failure or wear to the primary barrier system, two barriers must be closed around the pipe to make repairs, but not necessarily the secondary safeties, e.g.  If the stripper rubber is leaking, both the stripper rams can be closed or a combination of strippers and safeties.  If the top stripper ram is leaking, the lower stripper can be closed along with a safety or both safeties.  Etc. As with any primary barrier, if the internal check valves leak, the string must be pulled to repair the valves before operations can be recommenced. The stab-on safety valve (stabbing valve or kelly cock), is an inside secondary barrier used solely as a temporary arrangement to allow dropping of the plug into the secondary downhole barrier landing nipple.

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Normal pressure control for parallel strings is shown below: External pressure control is provided by: Primary  Stripper BOPs, or stripper rubber or annular preventer.  Two Xmas tree valves when rigging up and starting to snub the BHA into the Well. Secondary  Two safety (pipe) BOP rams or one safety with an annular preventer.  SCSSV, if pipe is above it. Tertiary  BOP shear and blind rams, or a shear/seal valve or BOP incorporated into the BOP stack or directly on top of the Xmas tree. Internal pressure control is provided by: Primary  Two check-valves installed in the BHA. Secondary  Stab-on safety valve (always ready and located in the workbasket).  Wireline plug installed in the BHA by dropping it into the workstring. Tertiary  A shear/seal valve or BOP.  Kill pump facility to install an overbalance fluid. When running a tapered string, either two sets of safety rams are required or variable rams are used.

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Internal pressure control is provided by: Primary  Two check-valves in the BHA. Secondary  Shear and Blind rams incorporated within the BOP. Tertiary  Shear/seal BOP mounted directly on top of the Xmas tree. In the North Sea region, it has almost become obligatory to use shear/seal BOPs due to a number of instances where primary and secondary barrier systems failed to deal with some particular well control occurrences. When conducting operations, a failure of the inside primary well control barrier will entail cessation of activity and retrieval of the BHA for repair to the barrier system. NOTE:

Some well interventions are conducted without BHA check valves as it is necessary to reverse circulate. In these cases the primary inside well control is the BOP shear rams and a shear/seal BOP becomes the secondary.

3.4.4 Snubbing

There are a number of snubbing BOP arrangements for different pressure regimes, running parallel or tapered strings or deploying long BHAs. A stripper rubber can be used when well pressures are less than 3,000psi, dependent upon the material used and the size, although stripper BOPs are always installed regardless of the well pressure as contingency. Annular preventers are used in two situations, when long toolstrings are to be deployed which can close on various diameters or for quick shut-in on pipe with upset or collared connections to prevent moving the pipe. The latter is usually dictated by company policy.

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3.4.2 Braided Line

The system for braided line is very similar to slickline. Pressure control is provided by: Primary  Greasehead seal and lubricator system.  Check valve if the wire breaks and is ejected from the lubricator.  Xmas tree valves when installing into, or removing tools from, the riser. Secondary  Two wireline BOP rams (in conjunction with a grease pump) that can close and seal around the wire.  Xmas tree upper master, if the wire is broken and ejected.  SCSSV, if toolstring is above it. Tertiary  Wireline cutting valve (usually UMV designed for Wire cutting).  Shear/seal valve or BOP installed directly onto the top of the Xmas tree. In general, tertiary barriers are rarely used unless a heavy-duty wireline operation is being carried out. 3.4.3 Coiled Tubing

Coiled tubing well control equipment is similar to wireline but also includes internal workstring barrier systems as well as external. External pressure control is provided by: Primary  Stripper.  Xmas tree valves when installing into, or removing tools from, the riser. Secondary  Pipe and Slip Rams incorporated within the BOP.  SCSSV, if the tubing is not straddling it. Tertiary  Shear and Blind Rams incorporated within the BOP.  Shear/seal BOP mounted directly on top of the Xmas tree.

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3.4 WELL INTERVENTION PRESSURE CONTROL In live well interventions, it is not generally necessary to provide kill facilities unless there is higher risk due to extreme high pressure or the presence of high concentrations of H2S. In many applications, pumping services may be on hand for other operations such as well clean-outs and stimulations. These may double as a kill facility provided there is an adequate supply of kill fluid with handling facilities. 3.4.1 Wireline Slickline

Wireline relies entirely on the lubricator system to provide primary pressure control. Secondary pressure control is provided by the wireline BOPs, and tertiary Well control may be available in the form of another wireline cutting valve. This is either contained in the Xmas tree (usually UMV), or as a shear/seal valve or BOP installed on top of the Xmas tree. The various pressure control barrier systems are: Primary  Stuffing box and lubricator system.  Check valve if the wireline breaks and is ejected from the lubricator.  Xmas tree valves when installing into, or removing tools from, the lubricator. Secondary  Wireline BOP rams/valve which can close and seal around the wire.  Xmas tree upper master, if the wire is broken and ejected.  SCSSV, if toolstring is above it. The BOP rams can be used for stripping wire out of a well but only when absolutely necessary. Stripping through the BOPs is only carried out to find the free end of the wire to enable wireline recovery. Tertiary  Wireline cutting valve (Usually UMV designed to cut wire)  BOP/Shear Seal Valve installed directly on top of the Xmas Tree.  Xmas tree valve, if absolutely necessary. In the event of primary and secondary failure with no tertiary barriers available, a Xmas tree valve may be used to sever the wire, as they can usually cut wireline, although the valve seat may be damaged. The valve used for this should be the upper master for two reasons:  If the lower master is used and damaged, it requires the well to be plugged before repair.  If the swab is used and damaged the well cannot be used for production as there is no longer double barrier protection from the production fluid. In the event of the upper master being used to cut Wireline, the valve should be inspected and relevant parts repaired/replaced at the earliest convenience.

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3.3 BARRIER CLASSIFICATION This section describes the classification of each common barrier grouping definitions used. Note: these may not be generic to the industry world-wide. 3.3.1 Primary Pressure Control

Primary pressure control is the system, which provides the first line of defence from an uncontrolled well flow. In each of the well servicing intervention methods it is provided by different mechanical systems. On a wireline rig up it is simply the stuffing box and lubricator envelope, however on a CT or snubbing rig up, it consists of the stripper, riser pressure envelope and internal workstring check valves. 3.3.2 Secondary Pressure Control

Secondary pressure control is the system, which provides the second line of defence, in the event that primary well control cannot be properly maintained. This is generally provided by the BOP system. If pumping facilities are available, although undesirable, a hydrostatic fluid barrier can be placed in the wellbore as a secondary barrier when both the primary or original secondary barrier has failed and there is no tertiary barrier. 3.3.3 Tertiary Pressure Control

Tertiary pressure control is not always available but may be an additional third and final line of defence in the event that secondary well control cannot be properly maintained. This is usually a shear seal valve or BOP system. This may be an integral part of the Xmas tree (e.g. a wireline or coiled tubing cutting actuator), or installed directly on top of the tree immediately before operations commence. With regard to snubbing, the tertiary barrier system is usually integrated within the secondary safety BOP system to provide the means to cut and seal the pipe while still allowing kill fluid to be pumped through the choke or kill line. (Refer to section 3.4.4.) 3.3.4 Sequence of Barrier Operation

The sequence of barrier operation is determined from the designation. The primary barrier is the first line of defence and on live Wells is usually in continuous operation. If there is a failure or potential failure of the primary barrier, the secondary barrier is brought into operation. The tertiary barrier is the last line of defence and it usually severs the wireline or pipe, and is the last resort. With particular regard to snubbing operations which uses similar pipe rams for primary and secondary barrier systems, combinations of the rams can be used to provide a minimum of two barriers when repairing the primary barrier system, (refer to section 3.4.4).

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3.2.2 Hydrostatic Barriers

Liquids provide hydrostatic barriers. A liquid is only a barrier when the hydrostatic head of pressure is greater than the formation pore pressure at the top of the producing interval and when the fluid level and condition (i.e. weight) can be monitored. The specific gravity of the fluid to be used as a barrier may be difficult to predict without good formation pressure data. The hydrostatic overbalance provided should be circa 200psi. but may be adjusted to counter for high losses in wells which cannot support this differential, especially troublesome when using solids free brines. A fluid can only be confirmed as a barrier after diligent monitoring of the well over a specified period of time, to ensure that any thermal expansion contraction effects have ceased. Typical fluid barriers are:    

Drilling muds Completion brines Seawater Fresh water.

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Additional barriers can be installed downhole, as a back up to a failed primary or secondary barrier or to allow removal of the Xmas tree for repair or for installation of workover BOPs. These barriers may be:     

Wireline plugs Bridge plugs Cement plugs. Ice plugs Overbalanced hydrostatic fluid

Common Barrier Definitions

Some other commonly used barrier definitions are given below: Leak-tight

No observable flow or pressure change.

Fail-safe

A device, which returns to the closed position on loss of the control function.

Fail to Test

Failure of a barrier to meet test criteria.

Fail to Close

Inability of a device to move to the closed position.

Positive Plug

Holds pressure from above and below.

Barrier Integrity

Mechanical barriers must be tested, preferably from the direction of flow. Tests on closed type barriers should be leak tight. The leakage rate on closable barriers such as Xmas tree valves etc. should be the API leakage criteria: 400cc/min or 900scf/hr with the exception of sub-surface safety valves used in well plugging (refer to note above in list of closable barriers). Each operator should develop procedures for testing Xmas tree and sub-surface safety valves to meet this criterion. This is problematic in subsea completions where there are long undulating production flowlines and riser systems which makes it difficult to calculate leakage rates for various well GORs and downstream volumes; however to help, formulae are provided in API 14A.

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Barriers are conveniently arranged into three main categories of pressure control, namely:  Primary  Secondary  Tertiary. Each of these consists of at least one, or a combination of mechanical barriers described below. The categorisations or classifications are described in section 3.3. NOTE:

These categories may not be the terms used in some areas of the world, especially where the common language is not English.

3.2.1 Mechanical Barriers

Mechanical barriers may be described as an individual item but in reality includes all the elements between itself and the next barrier in line. These systems including all associated elements are commonly referred to as envelopes. Mechanical barriers can be either closed barrier systems such as a wireline lubricator system complete with a stuffing box, i.e. the complete surface pressure envelope or closable barrier systems which are held open to allow well entry, but available and ready to be closed at any time on demand. Various types of closed and closable barriers are listed below. Types of closed barriers typically are:     

Wireline stuffing box (or grease control head)/lubricator/riser pressure envelopes. Coiled Tubing stripper/riser pressure envelopes. Snubbing strippers (or annular preventers)/riser pressure envelopes. Coiled tubing check valves. Snubbing work-string check-valves.

Types of closable barriers are:     

BOP rams Xmas tree valves. Subsurface safety valves * Shear/seal valves/BOPs Annular preventers.

* Sub-surface safety valves are acceptable as barriers during normal operations if they are tested in accordance with the test criteria given below, however, to be used for well plugging, i.e. for Xmas tree removal before a rig operation, it must be leak tight.

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WELL CONTROL METHODS

3.1 GENERAL This section describes the well control methods and practices employed on the various well intervention servicing methods and includes a section to explain barrier theory. The most significant factor to consider is whether they are live well or dead well interventions as this will have an impact on the equipment required and methods of well control employed. Dead well interventions, in terms of the IWCF, are classified as workovers and well control methods for these are covered in the IWCF drilling test. The methods addressed in this course are those used specifically in live well interventions. There is a distinct difference between rig workover operations and live well interventions. Workover well control uses a combination of barriers and procedures in a systematic method to contain pressure downhole whereas live well interventions use a system of barriers to contain pressure at surface. Barrier theory and these systems are described in the following sections.

3.2 BARRIER THEORY Definition:

A barrier is any device, fluid or substance that prevents the flow of well bore fluids.

There are two types of barriers:  Mechanical  Hydrostatic. A rule common to well intervention activities worldwide regarding pressure control is that a minimum of two independent and tested barriers shall be available at all times. In any circumstance where either of the barriers has failed, or there are indications that it is likely to fail, immediate action must be taken to re-instate or supplement that barrier and return the well to double barrier protection. The ‘primary barrier’ is the term used to describe the first line system of pressure containment and ‘secondary barrier’ the next line of defence. Nowadays, it is common, especially in highpressure wells, to install a third line of defence or a ‘tertiary’ barrier. The particular status of a well, for given operations and well circumstances, will have different barriers in place. For instance, the completion provides barriers in the form of individual Xmas tree valves and a sub-surface safety valve*, however, when running coiled tubing or a snubbing workstring, these cannot be closed and, therefore, are not available barriers until the BHA is above them.

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SECTION 3 WELL CONTROL METHODS

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2.2 IWCF TERMINOLOGY Definitions: Workover

– Well Servicing Operations conducted on dead Wells. (Usually with a rig and BOP’s in stalled on the wellhead).

Well Intervention

– Well Servicing operations conducted on live Wells.

Workover

– Well Control

Well Intervention

– Pressure Control

Barrier Theory

– A Barrier is any device, fluid or substance that prevents the flow of Wellbore Fluid.

Double Barrier Protection

– A minimum of Two Tested Barriers should be available at all times

Not Barriers

– Any mechanical device cannot be considered a Barrier if it has a toolstring through it.

Types of Barriers

– Primary, Secondary and Tertiary.

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Underground Blowout An uncontrolled flow of formation fluids from a sub-surface zone into a second subsurface zone. Underbalance The amount by which formation pressure exceeds pressure exerted by the hydrostatic head of fluid in the wellbore. Valve, Float A device that is positioned as either open or closed, depending on the position of a lever connected to a buoyant material sitting in the fluid to be monitored. Valve, Poppet The opening and closing device in a line of flow that restricts flow, by lowering a piston type plunger into the valve passageway. Valve, Relief A valve that opens at a present pressure to relieve excessive pressures within a vessel or line whose primary function is to limit system pressure. Valve, Shut-off A valve which operates fully open or fully closed to control the flow through a conduit. Valve, Sub Surface Safety A completion safety valve installed at a depth below the surface according to various criteria. Viscosity A measure of the internal friction or the resistance of a fluid to flow. Watt A unit of electromotive force. Wireline BOP (valve) Preventers installed on top of the well or drill string as a precautionary measure while running wirelines. The preventer packing will close around the wireline. Xmas Tree The head terminating a completion with a set of valves to control well flow and well servicing activities.

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Secondary Barrier Is the second line of defence from an uncontrolled well flow. It is usually brought into use when the primary barrier has failed or requires repair. Shear Rams Blowout preventer rams with a built in cutting edge that will shear tubulars that may be in the hole. Shear/Seal BOP The name used for a device used as a tertiary barrier on well interventions, which has the ability to cut wire or pipe and seal. Snubbing The process of installing pipe into a well where the well pressure is greater than that of the weight of pipe in the hole. It has also come to mean any of the live well interventions carried out by a hydraulic workover unit. Snubbers mode.

Term used to describe inverted slips used when the snubbing unit is in pipe light

Soft Close In To close in a well by closing a blowout preventer with the choke and choke line valve open, then closing the choke while monitoring the casing pressure gauge for maximum allowable casing pressure. Sour Gas

Natural gas containing hydrogen sulphide.

Space Out Procedure conducted to position a predetermined length of tubing/drill pipe, so that no connection or tool joint is opposite a set of preventer rams. Space-Out Joint The joint of tubing/drill pipe which is used to hang off operations so that no tool joint is opposite a set of preventer rams. Squeezing

Pumping fluid into a formation.

Stack The assembly of well control equipment including preventers, spools, valves, and nipples connected to the top of the casing head. Stripper A device which packs-off around wire or pipe run into the well and seals. They may be self energised or hydraulically activated. Stripping The process of running pipe through a stripper with or without pressure in the well. Swabbing The lowering of the hydrostatic pressure in the wellbore due to upward movement of tubulars and/or tools. Tertiary Barrier Is a third line of defence against an uncontrolled well flow, and in well interventions is usually a device, but may also be an overbalanced fluid. Is only used when the primary and secondary barriers have failed or been compromised. Transducer The device located in the solenoid valve box that is actuated by hydraulic pressure, and converts the force to an electrical signal for indication on a meter. The electrical output signal is in proportion to the hydraulic input pressure. Tubulars

Drill pipe, drill collars, tubing, and casing.

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

Packing Rubber elements used in wireline stuffing boxes to seal around slick wirelines. Pack-off or Stripper Rubber A device with an elastomer packing element that depends on pressure below the packing to effect a seal in the annulus. Used primarily to run or pull pipe under low or moderate pressures. Pipe Rams Rams whose ends are contoured to seal around pipe to close the annular space. Separate rams are necessary for each size (outside diameter) pipe in use. Plug Valve A valve whose mechanism consists of a plug with a hole through it on the same axis as the direction of fluid flow. Turning the plug 180° opens or closes the valve. The valve may or may not be full-opening. Pore Pressure Pressure exerted by the fluids within the pore space of a formation. Potable A liquid that is suitable for drinking. Pressure Gradient, Normal The normal pressure divided by true vertical depth. Pressure Integrity Test (PIT) Application of pressure by superimposing a surface pressure on a fluid column, in order to determine the pressure at which the well can withstand before a well intervention. This test is less than formation fracture pressure to prevent formation damage. Pressure Transmitter Device that sends a pressure signal to be converted, and calibrated to register the equal pressure reading on a gauge. The air output pressure in proportion to the hydraulic input pressure. Primary Pressure Control The primary well control system or device on the wellhead. Pump A device that increases the pressure of a fluid, and moves it to a higher level using compression force from a chamber and piston that is driven by a power source. Ram The closing and sealing component on a blowout preventer. One of three types - blind, pipe, or shear - may be installed in several preventers, mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drillpipe and then form a seal. Recorder A device that records outputs of pressure, temperature, continually on a chart to provide continuous reading. Regulator A device that varies and controls the pressure of a liquid or gas that passes through its chamber. Replacement The process whereby a volume of fluid, equal to the volume of steel in tubulars, and tools withdrawn from the wellbore is returned to the wellbore. Reservoir The container for storage of a liquid. The reservoir houses hydraulic fluid at atmospheric pressure as the supply for fluid power. Rupture Disc A device whose breaking strength (the point at which it physically bursts) works to relieve pressure in a system. Safety Factor A margin added to a figure or value purely for safety.

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IWCF – Well Intervention Pressure Control

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Kick Intrusion of formation fluids into a wellbore containing kill or drilling fluid. Kill Fluid Density The unit weight e.g. pounds per gallon (lbs/gal), selected for the fluid to be used to contain formation pressure. Kill Line A high-pressure fluid line connecting the mud pump and the wellhead. This line allows fluids to be pumped into the well or annulus with the blowout preventer closed to control a threatened blowout. Kill Rate A predetermined fluid circulating rate, expressed in fluid volume per unit time, which is to be used to kill the well. Kill Rate Circulating Pressure Pump pressure required to circulate kill rate volume. Leak-off Test Application of pressure by superimposing a surface pressure on a fluid column, in order to determine the pressure at which the exposed formation accepts whole fluid. Lights A name used in snubbing operations to describe snubbers or inverted slips. Lost Circulation (Lost Returns) The loss of whole well control fluid to the wellbore. Lost Returns See Lost Circulation. Lubrication Alternately pumping a relatively small volume of fluid into a closed wellbore system, and waiting for the fluid to fall toward the bottom of the well. Lubricator The pressure containing tubulars mounted above the Xmas tree for installing wireline or coiled tubing toolstrings in live wellbores. Manifold Header The piping system that serves to divide a flow through several possible outlets. Meter An instrument, operated by an electrical signal that indicates a measurement of pressure. Micron A millionth of a metre or about 0.0004”. The measuring unit of the porosity of filter elements. Minimum Internal Yield Pressure The lowest pressure at which permanent deformation will occur in metals. Needle Valve A shut-off two-way valve that incorporates a needle point to allow fine adjustments in flow. Normal Pressure Formation pressure equal to the pressure exerted by a vertical column of water, with salinity normal for the geographic area. Opening Ratio preventer.

The ratio of the well pressure to the pressure required to open the blowout

Overbalance The amount by which pressure exerted by the hydrostatic head of fluid in the wellbore exceeds formation pressure. Overburden The pressure on a formation due to the weight of the earth material above that formation. For practical purposes, this pressure can be estimated at 1psi/ft of depth.

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IWCF – Well Intervention Pressure Control

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Formation Integrity Test Application of pressure by superimposing a surface pressure on a fluid column, in order to determine ability of a subsurface zone to withstand a certain hydrostatic pressure. Formation Pressure (Pore Pressure) Pressure exerted by fluids within the pores of the formation (See Pore Pressure). Flowline Sensor A device to monitor rate of fluid flow from the annulus. Fracture Gradient The pressure gradient (psi/ft) at which the formation accepts whole fluid from the wellbore. Function The term given to the duty of operating a control device. Gate Valve A valve that employs a sliding gate to open or close the flow passage. The valve may or may not be full-opening. Gauge An instrument for measuring fluid pressure that usually registers the difference between atmospheric pressure, and the pressure of the fluid, by indicating the effect of such pressure on a measuring element (as a column of liquid, a bourdon tube, a weighted piston, a diaphragm, or other pressure-sensitive devices). Gland The metal item that energises stuffing box packing from force applied manually or hydraulically. H2S

Periodic abbreviation for hydrogen sulphide gas.

Hard Close In To close in a well by closing a blowout preventer with the choke and/or choke line valve closed. Heavies A title used in snubbing operations to describe slips. Hydrostatic Relating to the pressure that fluids exert due to their weight. Hydrostatic Head

The true vertical length of fluid column, normally in feet.

Hydrostatic Pressure The pressure that exists at any point in the wellbore due to the weight of the vertical column of fluid above. Inflow See Feed-in. Influx See Feed-in. Initial Circulating Pressure Pressure required to circulate initially at the selected kill rate, while holding back pressure at the closed-in value; numerically equal to kill rate circulating pressure plus closed-in pressure. Inside Blowout Preventer A device that can be installed in the drill string that acts as a check valve, allowing drilling fluid to be circulated down the string but prevents back flow. Inspection Port The plugged openings on the sides of the fluid reservoir of a device which can be opened to view the interior fluid level and return lines from the relief, bleeder, control valves, and regulators.

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IWCF – Well Intervention Pressure Control

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Closing Unit The assembly of pumps, valves, lines, accumulators and other items necessary to open and close the blowout preventer equipment. Closing Ratio The ratio of the wellhead pressure to the pressure required to close the blowout preventer. Control Panel, Remote A panel containing a series of controls that will operate the valves on the control manifold from a remote point. Corrosion Inhibitor Any substance which slows or prevents the chemical reactions of corrosion. Cut Fluid Well control fluid, which has been reduced in density or unit weight as a result of entrainment of less dense formation fluids or air. Displacement The volume of steel in the tubulars and devices inserted and/or withdrawn from the wellbore. Fluid Weight Recorder density.

An instrument in the fluid system that continuously measures fluid

Tubing Safety Valve An essentially full-opening valve located on the rig floor with threads to match the tubing in use. This valve is used to close off the tubing to prevent flow. Drill Stem Test (DST) A test conducted to determine production flow rate and/or formation pressure prior to completing the well. Equivalent Circulating Density (ECD) The sum of pressure exerted by hydrostatic head of fluid, drilled solids, and friction pressure losses in the annulus divided by depth of interest and by 0.052, if ECD is to be expressed in pounds per gallon (lbs/gal). Feed-in (Influx, Inflow) The flow of fluids from the formation into the wellbore. Filter A device whose function is the retention of insoluble contaminants from a fluid. Flow Meter A device that indicates either flow rate, total flow, or a combination of both, that travels through a conductor such as pipe or tubing. Flow Rate The volume, mass, or weight of a fluid passing through any conductor, such as pipe or tubing, per unit of time. Flow Target A bull plug or blind flange at the end of a T to prevent erosion at a point where change in flow direction occurs. Fluid A substance that flows and yields to any force tending to change its shape. Liquids and gases are fluids. Fluid Density The unit weight of fluid; e.g., pounds per gallon (lbs/gal). Formation Breakdown An event occurring when bottomhole pressure is of sufficient magnitude that the formation accepts fluid from the hole. Formation Integrity The ability of the formation to withstand applied pressure.

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

Blow-out Preventer The equipment installed at the wellhead to prevent damage at the surface, in the event of blow-out, while restoring primary well control. The BOP allows the well to be sealed to confine the well fluids and prevent the escape of pressure. Blowout Preventer Drill A training procedure to determine that rig crews are completely familiar with correct operating practices to be followed in the use of blowout prevention equipment. A dry run of blowout preventive action. Blowout Preventer Operating Control System The assembly of pumps, valves, lines, accumulators and other items necessary to open and close the blowout preventer equipment. Blowout Preventer Stack The assembly of well control equipment including preventers, spools, valves and nipples connected to the top of the wellhead or Xmas tree. Blowout Preventer Test Tool A tool to allow pressure testing of drilling or workover blowout preventer stacks and accessory equipment, by sealing the wellbore immediately below the stack. Bleed Off Valve An opening and closing device for removal of pressurised fluid. Bottomhole Pressure Depending upon context, either a pressure exerted by a column of fluid contained in the wellbore, or the formation pressure at the depth of interest. Bottoms-up Is the term describing the time at which fluid that was at the bottom of the hole reaches surface. Bullheading A term to denote pumping well fluids back into a formation in a well kill operation. Casing Head/Spool The part of the wellhead to which drilling or workover blowout preventer stack is connected. Casing Pressure

See Back-Pressure.

Casing Seat Test A procedure whereby the formation immediately below the casing shoe is subjected to a pressure equal to the pressure expected to be exerted later by a higher drilling fluid density, or by the sum of a higher drilling fluid density and back pressure created by a kick. Check Valve A valve that permits flow in only one direction. Choke A diameter orifice (fixed or variable) installed in a line through which high pressure well fluids can be restricted or released at a controlled rate. Circuit Breaker An electrical switching device able to carry an electrical current, and automatically break the current, to interrupt the electrical circuit if adverse conditions such as shorts or overloads occur. Circulating Head A device attached to the top of drill pipe or tubing to allow pumping into the well without use of the Kelly. Clamp Connection A pressure sealing device used to join two items without using conventional bolted flange joints. The two items to be sealed are prepared with clamp hubs. A clamp containing two to four bolts holds these hubs together.

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IWCF – Well Intervention Pressure Control

2

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GLOSSARY FOR WELL CONTROL OPERATIONS

2.1 COMMONLY USED WELL CONTROL TERMS Abnormal Pressure Pore pressure, in excess of that pressure resulting from the hydrostatic pressure exerted by a vertical column of water salinity, normal for the geographic area. Accumulator A vessel containing both hydraulic fluid and gas stored under pressure, as a source of fluid power to operate opening and closing of blowout preventer rams, and annular preventer elements. Accumulators supply energy for connectors and valves remotely controlled. Accumulator Bank Isolator Valve The opening and closing device located upstream of the accumulators in the accumulator piping, which stops flow of fluids and pressure in the piping. Accumulator Relief Valve The automatic device located in the accumulator piping, that opens when the pre-set pressure limit has been reached, which releases the excess pressure, and protects the accumulators. Air Regulator The adjusting device to vary the amount of air pressure entering piping lines. Ambient Temperature given area.

The temperature of the entire encompassing atmosphere within a

Ampere The unit used for measuring the quantity of an electric current flow. One ampere represents a flow of one coulomb per second. Annular Preventer A device which can seal around any object in the wellbore or upon itself. Compression of a reinforced elastomer packing element by hydraulic pressure affects the seal. Annular Regulator The device located in the annular manifold header, to enable adjustment of pressure levels, which will control the amount of closure of the annular preventer. Annulus The annular space between two tubulars (i.e. tubing and drill string or tubing and production casing). Annulus Friction Pressure Circulating pressure loss inherent in annulus between the drill string and casing or open hole. Back Pressure (Casing, Choke Pressure) The pressure existing at the surface on the casing side of the drill pipe/annulus flow system. Bleeding Controlled release of fluids from a closed and pressurised system in order to reduce the pressure. Blind Rams (Blank, Master) Rams whose ends are not intended to seal against any drill pipe, tubing or casing. They seal against each other to effectively close the hole. Blind/Shear Rams Blind rams with a built-in cutting edge that will shear tubulars that may be in the hole, thus allowing the blind rams to seal the hole. Used primarily in subsea systems or Dual and Treble combination BOPs. Blow-out An uncontrolled flow of gas, oil, or other well fluids into the atmosphere.

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

SECTION 2 GLOSSARY FOR WELL CONTROL OPERATIONS

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

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IWCF – Well Intervention Pressure Control

Square inch

= 6.452 square centimetres

Square kilometre

= 0.3861 square mile

Square metre

= 10.76 square feet

Square mile

= 2.590 square kilometres

Temp Centigrade

= 5/9 (Temp °F - 32)

Temp Fahrenheit

= 9/5 (Temp °C) + 32

Temp Absolute (Kelvin)

= Temp °C + 273

Temp Absolute (Rankine)

= Temp °F + 460

Ton (long)

= 2,240 pounds

Ton (metric)

= 2,205 pounds

Ton (short or net)

= 2,000 pounds

Ton (metric)

= 1.102 tons (short or net)

Ton (metric)

= 1,000 kilograms

Client: WATTAYA TRAINING SERVICES

= 6.297 barrels of water @ 60°F = 7.454 barrels (36° API) Ton (short or net)

= 0.907 ton (metric)

Watt per hour

= 3.415 BTUs

Yard

= 0.9144 metre

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IWCF – Well Intervention Pressure Control

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Inch of water @ 60°F

= 0.0361 pound per square inch

Kilogram

= 2.2046 pounds

Kilogram calorie

= 3.968 British Thermal Units

Kilogram per square centimetre

= 14.223 pounds per square inch = Kg/cm2 x 98.1 gives Pascals (KPa)

Kilometre

= 3,281 feet = 0.6214 mile

Kilo Pascal

= 0.145 pounds per square inch

Kilowatt

= 1.341 horse power

Litre

= 0.2462 gallon = 1.0567 quarts

Mega Pascal

= 145.03 pound per square inch

Metre

= 3.281 feet = 39.37 inches

Part per million

= 0.05835 grain per gallon = 8.345 pounds per million gallons

Pascal

= 0.000145 pound per square inch

Pound

= 7,000 grains = 0.4536 kilogram

Pound per square inch

= 2.309 feet of water @ 60°F = 2.0353 inches of mercury = 51.697 millimetres of mercury = 0.703 kilograms per square centimetre = 0.0689 bar = 0.006895 mega Pascal (MPa) = 6.895 kilo Pascal (KPa) = 6895 Pascal (Pa)

Pressure

=psi x 6.895 gives Kilo Pascals (KPa)

Sack cement (Set)

= 1.1 cubic feet

Square centimetre

= 0.1550 square inch

Square foot

= 0.929 square metre

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IWCF – Well Intervention Pressure Control

Cubic metre

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= 6.2897 barrels (US) = 35.314 cubic feet = 264.20 gallon (US)

Cubic yard

= 4.8089 barrels = 46,656 cubic inches = 0.7646 cubic metre

Feet

= 30.48 centimetres = 0.3048 meters

Feet of water @ 60oF

= 0.4331 pound per square inch

Feet per second

= 0.68182 mile per hour

Foot pound

= 0.001286 British Thermal Unit

Foot pound per second

= 0.001818 horse power

Gallon (US)

= 0.2318 barrel = 0.1337 cubic feet = 231.00 cubic inches = 3.785 litres = 0.003785 cubic metres

Gallon (Imperial)

= 1.2009 gallons (US) = 277.274 cubic inches

Gallon per minute

= 1.429 barrels per hour = 34.286 barrels per day

Gram

= 0.03527 ounce

Horsepower

= 42.44 BTUs per minute = 33,000 feet/pounds per minute = 550 feet/pounds per second = 1.014 horsepower (metric) = 0.7457 kilowatt

Horsepower hour

= 2,547 British Thermal Units

Inch

= 2.540 centimetres

Inch of mercury

= 1.134 feet of water = 0.4912 pound per square inch

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IWCF – Well Intervention Pressure Control

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1.1 CONVERSION FACTORS Atmosphere

= 33.94 feet of water = 29.92 inches of mercury = 760 millimetres of mercury = 14.70 pounds per square inch

Bar

= 14.504 pounds per square inch = 100 Kilo Pascal’s

Barrel

= 5.6146 cubic feet = 42 gallons (US) = 35 gallons (Imperial)

Barrel of water @ 60oF

= 0.1588 metric ton

Barrel (36° API)

= 0.1342 metric ton

Barrel per hour

= 0.0936 cubic feet per minute = 0.700 gallon per minute = 2.695 cubic inches per second

Barrel per day (bpd)

= 0.2917 gallon per minute

British Thermal Unit

= 0.2520 kilogram calorie = 0.2928 watt hour

BTU per minute

= 0.02356 horse power

Centimetre

= 0.3937 inch

Centimetre of mercury

= 0.1934 pound per square inch

Cubic centimetre

= 0.06102 cubic inch

Cubic foot

= 0.1781 barrel = 7.4805 gallons (US) = 0.02832 cubic metre = 0.9091 sacks cement (set)

Cubic foot per minute

= 10.686 barrels per hour = 28.800 cubic inches per second = 7.481 gallons per minute

Cubic inch

= 16.387 cubic centimetres

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IWCF – Well Intervention Pressure Control

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1 FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL Pressure Gradient psi/ft

Mud/Brine Weight ppg x 0.052

Mud/Brine Weight ppg

Pressure Gradient psi/ft ÷ 0.052

Hydrostatic Pressure psi

Mud/Brine Weight ppg x 0.052 x True Vertical Depth ft

Formation Pressure psi

Hydrostatic Pressure (in string & sump) psi + Shut In Tubing Head Pressure psi

Equivalent Mud Weight ppg

Pressure psi ÷ True vertical Depth ft ÷ 0.052

Pump Output bbls/min

Pump Output bbls/stk x Pump Speed spm

Annulus Velocity ft/min

Pump Output bbls/min ÷ Annulus Volume bbls/ft

Boyle’s Law

P1 V1  P2 V2

Conversion of diameter to bbls/ft Conversion of area to bbls/ft

pipe

annular

P2 

P1 V1 V2

V2 

V1 P1 P2

D2  bbls / ft 1,029.42 D2  d2 bbls / ft 1.029.42

IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

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IWCF – Well Intervention Pressure Control

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SECTION 1 FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL

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IWCF – Well Intervention Pressure Control

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IWCF – Well Intervention Pressure Control

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16 SUBSEA WELL INTERVENTIONS........................................................................................................................... 323 16.1 CONVENTIONAL SUBSEA WELL INTERVENTIONS ...................................................................................................................... 327 16.1.1 Spool Subsea Tree Interventions ............................................................................................................................. 327

17 HYDRATE FORMATION & PREVENTION .............................................................................................................. 331 17.1 17.2 17.3

FORMATION OF HYDRATES ................................................................................................................................................. 335 HYDRATE PREDICTION ....................................................................................................................................................... 336 HYDRATE PREVENTION ...................................................................................................................................................... 338

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IWCF – Well Intervention Pressure Control

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12.4 SNUBBING EQUIPMENT ..................................................................................................................................................... 255 12.4.1 Stripper BOPs .......................................................................................................................................................... 258 12.4.2 Well Shut-In............................................................................................................................................................. 261 12.4.3 Deployment of Long BHAs....................................................................................................................................... 261 12.4.4 Annular BOPs .......................................................................................................................................................... 261 12.4.5 Safety (Pipe) BOPs ................................................................................................................................................... 261 12.4.6 Tubing Hanger Flange ............................................................................................................................................. 262 12.4.7 Testing Requirements.............................................................................................................................................. 263 12.4.8 Snubbing BOP Arrangements 0-5,000psi WP.......................................................................................................... 264 12.4.9 Snubbing BOP Stack Arrangements 5,000-10,000psi WP ....................................................................................... 266 12.4.10 Snubbing BOP Stack Arrangements. Over 10,000psi WP ....................................................................................... 268 12.5 BOTTOMHOLE ASSEMBLIES................................................................................................................................................. 271 12.5.1 Snubbing BHA Arrangements.................................................................................................................................. 271 12.5.2 Deployment and Pressure Testing Procedures ........................................................................................................ 272 12.6 IDENTIFIED SNUBBING/HWO HAZARDS ...................................................................................................................... 274

13 EQUIPMENT SPECIFIC REQUIREMENTS .............................................................................................................. 277 13.1 FLANGED END AND OUTLET CONNECTIONS ................................................................................................................ 281 13.1.1 General - Flange Types and Uses............................................................................................................................. 281 13.1.2 Design...................................................................................................................................................................... 281 13.1.3 General.................................................................................................................................................................... 282

14 PREVENTERS ....................................................................................................................................................... 285 14.1 ANNULAR PREVENTERS ............................................................................................................................................... 289 14.1.1 Introduction............................................................................................................................................................. 289 14.1.2 Hydril ‘GK’ Annular Preventer ................................................................................................................................. 290 14.1.3 Hydril ‘GL’ Annular Preventer.................................................................................................................................. 292 14.1.4 Cameron Annular Preventers .................................................................................................................................. 295 14.1.5 Shaffer Annular Preventers ..................................................................................................................................... 297 14.1.6 Packing Element Selection....................................................................................................................................... 298 14.2 RAM PREVENTERS........................................................................................................................................................ 300 14.2.1 Cameron .................................................................................................................................................................. 300 14.2.2 Double ‘UII’.............................................................................................................................................................. 301 14.2.3 ‘SS’ Space Saver....................................................................................................................................................... 304 14.2.4 Shaffer BOPs............................................................................................................................................................ 305 14.2.5 Hydril Ram Preventer .............................................................................................................................................. 307 14.2.6 Ram Types ............................................................................................................................................................... 308 14.3 BOP CONTROL SYSTEMS .............................................................................................................................................. 313

15 CHOKES ............................................................................................................................................................... 315 15.1.1 HP Production Chokes ............................................................................................................................................. 319

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IWCF – Well Intervention Pressure Control

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11.3 OPERATIONAL PLANNING AND SAFETY ........................................................................................................................... 237 11.3.1 Introduction............................................................................................................................................................. 237 11.3.2 Operational Considerations..................................................................................................................................... 237 11.3.3 Working Location .................................................................................................................................................... 237 11.3.4 Rig Floor Equipment ................................................................................................................................................ 238 11.3.5 Pressure Control Equipment Considerations ........................................................................................................... 239 11.4 EMERGENCY PROCEDURES.......................................................................................................................................... 240 11.4.1 Platform Shutdown ................................................................................................................................................. 240 11.4.2 Stripper/Packer Element Leak ................................................................................................................................. 240 11.4.3 Leak between the Top of the Tree and the Stripper/Packer.................................................................................... 240 11.4.4 Tubing Pinhole Leak ................................................................................................................................................ 241 11.4.5 Tubing Ruptures ...................................................................................................................................................... 241 11.4.6 Tubing Separates Downhole ................................................................................................................................... 241

12 SNUBBING OPERATIONS..................................................................................................................................... 243 12.1.1 Pressure Control Requirements ............................................................................................................................... 247 12.2 BARRIER PRINCIPLES.................................................................................................................................................... 248 12.2.1 Snubbing Arrangements.......................................................................................................................................... 248 12.3 SNUBBING/HYDRAULIC WORKOVER UNITS (HWO) ..................................................................................................... 249 12.3.1 Hydraulic Jack Assembly.......................................................................................................................................... 250 12.3.2 Guide Tube .............................................................................................................................................................. 250 12.3.3 Splined Tube ............................................................................................................................................................ 251 12.3.4 Access Window........................................................................................................................................................ 251 12.3.5 Travelling Slips......................................................................................................................................................... 251 12.3.6 Travelling Snubbers ................................................................................................................................................. 251 12.3.7 Stationary Slips........................................................................................................................................................ 251 12.3.8 Stationary Snubbers ................................................................................................................................................ 251 12.3.9 Power Swivel ........................................................................................................................................................... 251 12.3.10 Power Tongs............................................................................................................................................................ 251 12.3.11 Work Basket ............................................................................................................................................................ 251 12.3.12 Control Panels ......................................................................................................................................................... 252 12.3.13 Power Pack.............................................................................................................................................................. 252 12.3.14 Hose Package .......................................................................................................................................................... 252 12.3.15 BOP System ............................................................................................................................................................. 252 12.3.16 Equalising Loop ....................................................................................................................................................... 252 12.3.17 Bleed-Off Line .......................................................................................................................................................... 252 12.3.18 Strippers .................................................................................................................................................................. 253 12.3.19 Circulating System................................................................................................................................................... 253 12.3.20 The Snubbing Process.............................................................................................................................................. 255

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IWCF – Well Intervention Pressure Control

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10 WIRELINE OPERATIONS ...................................................................................................................................... 174 10.1 INTRODUCTION ........................................................................................................................................................... 174 10.2 WIRELINE UNIT ............................................................................................................................................................ 174 10.2.1 Wireline Units.......................................................................................................................................................... 175 10.2.2 Power Pack.............................................................................................................................................................. 176 10.2.3 Operator’s/Engineer’s Cabin ................................................................................................................................... 176 10.2.4 Winch ...................................................................................................................................................................... 176 10.2.5 Spooling Head ......................................................................................................................................................... 176 10.2.6 Weight Indicator and Hay Pulley............................................................................................................................. 176 10.2.7 Types of Wireline..................................................................................................................................................... 178 10.3 WELLHEAD PRESSURE CONTROL EQUIPMENT............................................................................................................. 179 10.3.1 Wireline Lubricators and Accessories...................................................................................................................... 179 10.3.2 Wellhead Adapter (Tree Adapter) ........................................................................................................................... 180 10.3.3 Pump-in Tee ............................................................................................................................................................ 181 10.3.4 Wireline Valve (BOP) ............................................................................................................................................... 182 10.3.5 Quick Unions ........................................................................................................................................................... 187 10.3.6 Stuffing Box ............................................................................................................................................................. 191 10.3.7 Hydraulic Packing Nut ............................................................................................................................................. 193 10.3.8 Slickline Lubricator/Single BOP Stack Arrangement................................................................................................ 194 10.3.9 Slickline Lubricator/Dual BOP Stack Arrangement.................................................................................................. 196 10.3.10 Braided Line Lubricator/Dual BOP Stack Arrangement........................................................................................... 199 10.3.11 Grease Injection System .......................................................................................................................................... 205 10.3.12 Safety Check Union.................................................................................................................................................. 208

11 COILED TUBING OPERATIONS............................................................................................................................. 214 11.1 COILED TUBING UNITS ................................................................................................................................................. 215 11.1.1 Operators Control Cabin.......................................................................................................................................... 216 11.1.2 Tubing Reel.............................................................................................................................................................. 216 11.1.3 Power pack.............................................................................................................................................................. 216 11.1.4 Goose Neck.............................................................................................................................................................. 216 11.1.5 Injector .................................................................................................................................................................... 218 11.1.6 Stripper/Packer ....................................................................................................................................................... 218 11.1.7 BOP System ............................................................................................................................................................. 223 11.1.8 Shear/Seal ............................................................................................................................................................... 228 11.1.9 Tubing ..................................................................................................................................................................... 231 11.2 PRESSURE CONTROL EQUIPMENT ......................................................................................................................................... 232 11.2.1 Check valves ............................................................................................................................................................ 232 11.2.2 Coiled Tubing Tooling .............................................................................................................................................. 233 11.2.3 Coiled Tubing Standard BOP Configuration ............................................................................................................ 234 11.2.4 Coiled Tubing BOP Configuration with Shear/Seal BOP .......................................................................................... 234

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

8 COMPLETION EQUIPMENT ................................................................................................................................. 110 8.1 WIRELINE RE-ENTRY GUIDE ......................................................................................................................................... 116 8.1.1 Mule-Shoe ............................................................................................................................................................... 116 8.1.2 Bell Guide ................................................................................................................................................................ 116 8.2 TUBING PROTECTION JOINT ........................................................................................................................................ 117 8.3 WIRELINE LANDING NIPPLES ....................................................................................................................................... 117 8.3.1 No-Go or Non-Selective ........................................................................................................................................... 117 8.3.2 Selective .................................................................................................................................................................. 117 8.4 PERFORATED JOINTS.................................................................................................................................................... 119 8.5 PACKERS ...................................................................................................................................................................... 119 8.5.1 Setting Methods ...................................................................................................................................................... 124 8.5.2 Retrievable Packer Accessories ............................................................................................................................... 125 8.5.3 Permanent Packer Accessories................................................................................................................................ 126 8.6 SLIDING SIDE DOORS ................................................................................................................................................... 130 8.7 FLOW COUPLINGS........................................................................................................................................................ 130 8.8 BLAST JOINTS ............................................................................................................................................................... 131 8.9 SIDE POCKET MANDRELS ............................................................................................................................................. 133 8.9.1 Gas Lift Valves ......................................................................................................................................................... 133 8.9.2 Dummy Valves......................................................................................................................................................... 133 8.9.3 Chemical Injection Valves........................................................................................................................................ 133 8.9.4 Circulating Valves.................................................................................................................................................... 134 8.9.5 Differential Dump Kill Valves................................................................................................................................... 134 8.9.6 Equalising Dummy Valves ....................................................................................................................................... 134 8.10 SUB-SURFACE SAFETY VALVES (SSSV) .......................................................................................................................... 137 8.10.1 Types of Sub-Surface Safety Valves......................................................................................................................... 138 8.10.2 Sub-Surface Controlled Sub-Surface Safety Valves.................................................................................................. 141 8.10.3 Surface Controlled Sub-Surface Safety Valves......................................................................................................... 143 8.10.4 Safety Valve Leak Testing........................................................................................................................................ 148 8.10.5 Annulus Safety Valves ............................................................................................................................................. 149 8.10.6 Surface Control Manifolds....................................................................................................................................... 151 8.10.7 Control Lines............................................................................................................................................................ 152 8.10.8 Tubing ..................................................................................................................................................................... 152 8.10.9 Tubing Hangers ....................................................................................................................................................... 153 8.11 WELLHEADS ................................................................................................................................................................. 159 8.11.1 Tubing Heads........................................................................................................................................................... 159 8.12 XMAS TREES................................................................................................................................................................. 161

9 WELL INTERVENTION SERVICES .......................................................................................................................... 164 9.1

GENERAL...................................................................................................................................................................... 168

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

6 PREVENTION OF FORMATION DAMAGE............................................................................................................... 80 6.1 FORMATION DAMAGE................................................................................................................................................... 84 6.1.1 Drilling/Casing........................................................................................................................................................... 85 6.1.2 Completing ................................................................................................................................................................ 85 6.1.3 Producing .................................................................................................................................................................. 86 6.1.4 Well Intervention....................................................................................................................................................... 87 6.2 DAMAGE PREVENTION .................................................................................................................................................. 88 6.2.1 Well Plugging ............................................................................................................................................................ 88 6.2.2 Workover Fluids......................................................................................................................................................... 88 6.2.3 Clear Fluids ................................................................................................................................................................ 89 6.2.4 Composition of Brines ............................................................................................................................................... 90 6.2.5 Brine Selection........................................................................................................................................................... 90 6.2.6 Preparation of Brines ................................................................................................................................................ 91 6.2.7 Filtration and Cleanliness .......................................................................................................................................... 91 6.2.8 Health and Safety...................................................................................................................................................... 91 6.2.9 Pollution Control........................................................................................................................................................ 91 6.3 FORMATION PRESSURE ................................................................................................................................................. 92 6.3.1 Normal and Abnormal Formation Pore Pressures..................................................................................................... 92 6.3.2 Normal Pressure ........................................................................................................................................................ 92 6.3.3 Abnormal Pressure .................................................................................................................................................... 92 6.3.4 Subnormal Pressures ................................................................................................................................................. 93 6.3.5 Pressure Gradients .................................................................................................................................................... 93 6.4 FORMATION FRACTURE PRESSURE................................................................................................................................ 94 6.5 FORMATION INTEGRITY TESTS....................................................................................................................................... 95 6.5.1 Leak-Off Test ............................................................................................................................................................. 95 6.5.2 Formation Integrity Test............................................................................................................................................ 97 6.6 MAXIMUM ALLOWABLE ANNULUS SURFACE PRESSURE - MAASP ................................................................................ 98 6.7 CIRCULATING PRESSURE LOSSES ................................................................................................................................... 99

7 PRODUCTION WELL KILL PROCEDURES .............................................................................................................. 100 7.1 7.2 7.3 7.4 7.5

WELL PREPARATION .................................................................................................................................................... 104 REVERSE CIRCULATION ................................................................................................................................................ 105 BULLHEADING (OR SQUEEZE KILL) ............................................................................................................................... 107 LUBRICATE AND BLEED ................................................................................................................................................ 108 PUMP REQUIREMENTS ................................................................................................................................................ 108

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IWCF – Well Intervention Pressure Control

Table of Contents

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Page

1 FORMULAE AND CONVERSION FACTORS COMMONLY USED IN WELL CONTROL ............................................... 16 1.1

CONVERSION FACTORS.................................................................................................................................................. 19

2 GLOSSARY FOR WELL CONTROL OPERATIONS ..................................................................................................... 24 2.1 2.2

COMMONLY USED WELL CONTROL TERMS ................................................................................................................... 26 IWCF TERMINOLOGY ..................................................................................................................................................... 34

3 WELL CONTROL METHODS ................................................................................................................................... 36 3.1 GENERAL........................................................................................................................................................................ 38 3.2 BARRIER THEORY ........................................................................................................................................................... 38 3.2.1 Mechanical Barriers .................................................................................................................................................. 39 3.2.2 Hydrostatic Barriers .................................................................................................................................................. 41 3.3 BARRIER CLASSIFICATION .............................................................................................................................................. 42 3.3.1 Primary Pressure Control........................................................................................................................................... 42 3.3.2 Secondary Pressure Control....................................................................................................................................... 42 3.3.3 Tertiary Pressure Control........................................................................................................................................... 42 3.3.4 Sequence of Barrier Operation .................................................................................................................................. 42 3.4 WELL INTERVENTION PRESSURE CONTROL ................................................................................................................... 43 3.4.1 Wireline Slickline ....................................................................................................................................................... 43 3.4.2 Braided Line............................................................................................................................................................... 44 3.4.3 Coiled Tubing............................................................................................................................................................. 44 3.4.4 Snubbing.................................................................................................................................................................... 45

4 PRESSURE BASICS.................................................................................................................................................. 48 4.1 FUNDAMENTALS OF FLUIDS AND PRESSURE ................................................................................................................. 52 4.1.1 Fluid Pressure ............................................................................................................................................................ 52 4.1.2 Specific Gravity.......................................................................................................................................................... 54 4.1.3 API Gravity................................................................................................................................................................. 55 4.1.4 Hydrostatic Pressure ................................................................................................................................................. 55 4.1.5 Gas Correction Factors .............................................................................................................................................. 57

5 REASONS FOR WELL INTERVENTIONS .................................................................................................................. 70 5.1 GENERAL........................................................................................................................................................................ 70 5.2 TUBING BLOCKAGE ........................................................................................................................................................ 71 5.3 CONTROL OF EXCESSIVE WATER OR GAS PRODUCTION ................................................................................................ 72 5.3.1 Control of Water Production ..................................................................................................................................... 72 5.3.2 Control of Gas Production ......................................................................................................................................... 75 5.4 MECHANICAL FAILURE................................................................................................................................................... 77 5.5 STIMULATION OF LOW PRODUCTIVITY WELLS .............................................................................................................. 78 5.6 PARTIALLY DEPLETED RESERVOIRS ................................................................................................................................ 79 5.7 SAND CONTROL ............................................................................................................................................................. 79

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

Client:

IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

g) The Invigilator, who has no knowledge of oilfield technology, mark the test paper from a standard key. Therefore if the answers you give on your test paper are ambiguous e.g.; you mark two answers when only one is requested or one answer when two are requested, or the calculation cannot be read, you will get zero points for that question: h) Please check your paper when you have finished – to ensure that all questions (on both sides of the pages) have been answered. 9. On Completion of the Test: When you have completed your paper, please hand it to the Invigilator with all your working paper and leave the room quietly. Do not remove any test material or notes made during the test from the room. Else your paper may be voided. 10. Results: The Certification Centre manager will give you your results. Do not wait around outside the test room or bother the Invigilator while he or she is grading the test papers.

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IWCF – Well Intervention Pressure Control

f)

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If you want to change an answer that you have marked or entered on the paper, draw two lines through the answer box – then tick the correct box or enter your new answer.

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

6. Before the Test: a) Candidates are required to bring their passport to the test centre on the morning of the test session. The invigilator will check the passport details against the personal details on the candidate’s registration form. b) Candidates will be given a registration form to complete before the test session commences. This must be completed in BLOCK letters (EN MAJUSCULES) (MIT GROSSEN BUCKSTABEN) using a pen or ballpoint. Please ensure that your name, date and place of birth are as stated on your passport. c)

7.

This is a ‘closed book’ exam; therefore brief cases, textbooks, calculation tables, and any other materials which candidates bring with them must be left outside the room before the test commences.

During the Examination: a) Candidates will require a calculator, pen and ruler to complete their written test papers. A candidate’s final answer(s) to each question must be clearly marked in pen or ballpoint.

8.

b)

The test centre will provide candidates with ‘Formula Sheets’ and blank working paper. All working papers must be handed to the invigilator with each completed test paper.

c)

Candidates may only leave the test room during the written tests with the Invigilator’s permission. Candidates are recommended to take a short break.

Examination Tips: a) Unless otherwise requested, you must only mark one answer for each question. b) If you are asked to select more than one answer, the precise number will be indicated in the question. c)

All multiple choice questions must be answered by placing an ‘X’ in the appropriate answer box.

d) The answer(s) to calculation questions must be written clearly in the space provided. The marking scheme provides sufficient margin to allow for rounding of calculations. e) You must answer all calculation questions based on the data given. Do not make assumptions about data that has not been provided. Do not assume that the data is incorrect and that you may change it before the calculation.

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IWCF – Well Intervention Pressure Control

Client: WATTAYA TRAINING SERVICES

NOTES FOR CANDIDATES Well Intervention Pressure Control Certification Programme 1. This Certification programme is available as four options: a) Well Intervention Coiled Tubing Operations. b) Well Intervention Wireline Operations. c)

Well Intervention Snubbing Operations.

d) Well Intervention ‘Combined Operations’. This Programme includes Coiled Tubing, Wireline and Snubbing Operations. 2. The Certification programme contains a minimum of three written test paper sections: a) A written test on Pressure Control Completion Equipment (compulsory for all candidates). b) A written test on Pressure Control Coiled Tubing or Wireline or Subbing Equipment. c)

A written test on Pressure Control Principle and Procedures.

d) A candidate nominated for the ‘Combined Operations’ programme must sit and pass all four equipment test papers and P & P paper to obtain a certificate. 3.

Each of the four programme options is available at Level 1. or Level 2. The different levels cannot be mixed.

4. Candidates or their employers are required to nominate the programme and test level to the Accredited Certification Centre. It is possible to sit both test levels at the same test session. 5. The time allowed for the written test papers in each programme is as follows: Level 1. and 2: i) Completion Equipment Test plus coiled Tubing, or Wireline or, Snubbing Equipment – 1 hour. ii) Principles & Procedure Paper – 1 ½ hours. iii) Combined Equipment test – 2 ½ hours.

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IWCF – Well Intervention Pressure Control

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AIMS AND OBJECTIVES

The overall aim of the course is to provide a delegate with the theoretical skills essential in applying well pressure control during well intervention and servicing operations with the objective of improving the individuals’ knowledge and level of competence. AIMS

The individual aims are to:  Improve the delegate's competence in well intervention pressure control.  Provide an appreciation of completion types, equipment, equipment functions and practices as recognised by the industry.  Establish an increased awareness of well intervention/servicing well control equipment, methods and practices.  Furnish a student with knowledge of pertinent legislative guidelines, standards and industry best practice.  Provide an awareness of how to discern well pressure control problems and apply solutions. OBJECTIVES

The individual objectives are to assist the delegate to:        

Identify various types of completions and their impact on well interventions. List the well parameters necessary to conduct a safe well intervention. List the parameters necessary to conduct a well kill operation. Identify well pressure control problems from available well data i.e. pressure, volume and flow characteristics. Identify possible problems and implement solutions to various well pressure control problems. Understand pertinent legislative guidelines, standards and best practices. Determine if pressure control equipment is fit for purpose. Obtain IWCF certification.

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IWCF – Well Intervention Pressure Control

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FOREWORD

Well pressure control is the most critical consideration in the planning and performing of any well servicing operation. The awareness of well pressure control in the prevention of injury to personnel, harm to the environment and potential loss of facilities must be fully appreciated by planning engineers and well site personnel. This appreciation must include personnel in having a sound knowledge of legislative requirements, completion equipment, pressure control equipment and operating practices and procedures. ‘Well Intervention’ and ‘Workover’ are commonly used terms to describe servicing operations on oil and gas wells and which have, in the past, had many different interpretations. However, in general, ‘Workover’ describes well service operations on dead wells in which the formation pressure is primarily controlled with hydrostatic pressure. Workover operations are carried out by a drilling rig, workover rig or Hydraulic Workover Unit (HWO) where the Xmas tree is removed from the wellhead and replaced by a blow out preventer (BOP) equipment. ‘Well Intervention’ is a term used to describe ‘through-tree’ live well operations during which the well pressure is contained with pressure control equipment. Well Interventions are conducted by wireline, coiled tubing or snubbing methods. Snubbing operations today are now usually conducted with HWO units. This S-D Consulting Course is designed to provide essential knowledge to delegates participating in Well Intervention Pressure Control. Well pressure control equipment used by wireline, coiled tubing and snubbing units is so termed as it must control well pressure during live well intervention operations. It significantly differs from BOP systems used on dead well workovers. As most well servicing is now conducted by live well intervention methods these are fully addressed as part of the course. The term Well Control specifically applicable to drilling or workover operations using hydrostatic pressure is not addressed in this manual. To have an understanding of well operations conducted by live well intervention methods and the associated pressure control equipment, it is first necessary to have, or obtain, a basic knowledge of completion designs, completion equipment, practices, well service methods and their applications. An overview of these is given in the early sections of the manual. Training in well intervention well pressure control is an essential part in ensuring the competence of personnel involved in the planning and carrying out of live well servicing operations. The S-D Consulting Oilfield Services WELL INTERVENTION WELL CONTROL TRAINING COURSE and course materials intend to provide this essential knowledge in order to help delegates to obtain an IWCF (International Well Control Forum) certificate in Well Intervention Pressure Control.

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