section 6 snubbing

Power Pack FailureThe failure of a power pack during operations should not cause a well control problem. All functions on the unit are fail safe or there are manual locks and brakes that can be applied. The BOP’s do not require the power pack running to operate them because they use, as with any BOP system, stored pressure in an accumulator. It is true that a large quad may require more fluid to operate all four rams than is available from the accumulator. It is exceedingly unlikely that this would be a requirement during a power pack failure. Some units are fitted with large capacity accumulators to enable the full operation of a quad without relying on the power pack. Nearly all accumulators have a secondary power source (usually air or a hand pump) and so the rams can be operated using this power source.

www.ERTIKA.com.lyDrilling Courses in Libya

SECTION SIX

Snubbing


6. SnubbingThe Snubbing/Hydraulic Workover Unit (HWO) can be utilised for Snubbing operations or dead well intervention. Snubbing is the process of tripping pipe into a well which has a surface pressure great enough to eject the pipe if no restraining force is applied, this condition is termed Pipe Light mode.

Stripping is the term used for moving pipe through a rubber element whether in the pipe light mode or pipe heavy mode i.e. when the pipe is too heavy to be ejected by wellhead pressure. In practice, snubbing has become the term for all operations conducted using Snubbing units and HWO equipment.

The HWO unit is often used in place of a conventional drilling or workover rig for dead well intervention since it is cheaper and easier to mobilise than a rig.

Snubbing is performed by introducing an internally plugged pipe into a live well using BOP’s to obtain an external seal around the pipe. The pipe is filled with fluid during RIH to prevent pipe collapse. The top of the pipe is run open ended.

Snubbing is used for a variety of operations when it is not possible to kill the well, including but not limited to:-

• Pulling and running completion strings

• Running concentric completions inside existing production strings (sometimes called insert strings or velocity strings)

• Milling and washing below production tailpipe

• Through-tubing gravel packs

• Cleaning out proppants after frac jobs

• Fishing stuck or lost tools, DHSVs, coiled tubing

• Spotting and pumping acid and cement

• Clearing obstructions from tubing, casing, drill pipe Well control problems on drilling and workover operations

• Perforating and re-perforating - particularly using very long TCP guns

• Running and pulling wireline and other mechanical tools - particularly in highly deviated wells

• Wells that cannot be killed because of heavy cross-flow between zones or other downhole problems that cause inability to hold a full column of fluid

• Underground gas storage caverns. These man made holes in the ground full of gas cannot be killed

Snubbing operations use BOP’s singly or in pairs for primary well control depending on the wellhead pressure, well conditions, pipe used and the nature of work being undertaken.


On high pressure wells, provision may be made for backup and BOP’s would be provided for each size of pipe if a tapered workstring is to be used. This can lead to up to 10 BOP’s being used.

Snubbing unit configurations are very flexible and are tailored to the individual requirements for each job.

Since the snubbing unit jack is positioned above all the pressure containment devices, the BOP’s must be rated for the particular task to be undertaken (5,000 psi, 10,000 psi, 15,000 psi etc.). Of the 60 or so snubbing units outside of North America nearly all are different in size and make etc., and there is no such thing as a standard unit.

6.1HWO

Hydraulic Workover operations are conducted in the same manner as snubbing operations although fewer BOP’s are used since the primary well control uses kill fluid and/or mechanical plugs.

In all operational aspects, the snubbing unit performing HWO operations is a portable workover rig and normal well control procedures apply.

A typical rig up would include:-

• Blind/Shear rams

• Pipe rams

• Annular BOP

HWO operations are undertaken for a variety of reasons such as at remote locations where a conventional derrick is impossible to obtain, expensive or difficult to rig up or transport

HWO operations can include:

• Full workovers

• Well Clean-out

• Squeeze-off

• Re-perforating

• Deepening etc., in the production zone• Running or pulling ESP completions and control lines

that cannot be done on a live well as the closure of any BOP’s would damage them


The first snubbing units were designed in the 1920s by Mr. H. Otis to enable a drilling rig to “snub” pipe into a well under pressure. These mechanical or rig assist units are still used in North America.

Rig Assist units are rigged up on the rig floor and are only for use in “pipe light” conditions. When enough pipe weight has been gained, the rig assist is rigged down and the job continued with the rig stripping the rest of the pipe into the well.

The rig assist unit is operated by 2 cables attached to the travelling block of the host drilling rig with each end of the cables passing around pulleys on the base platform (or stationary head) of the unit and attached to the travelling snubbers (slips). The travelling snubbers are kept in position by repositioning cables that pass around sheaves attached to the derrick structure and which have counterweights attached to them. These weights are sufficient to hold the travelling snubbers aloft and to maintain some tension on the main snub cables.

The stationary head is attached to the BOP stack of the drilling rig that may have extra BOP’s for snubbing use.

Rig assist units have been built to enable rigs to trip pipe during underbalanced drilling operations. They look like small, remotely operated, short stroke units and are installed below the rig floor on top of the rig’s BOP stack. They are only used for the first or last few stands of drill pipe when the upward force from the well pressure is greater than the force from the pipe weight (light pipe). This force is trying to blow the pipe out of the well.


Rig Assist Snubbing Unit


During the 1950s, hydraulically operated snubbing units were designed and consisted of two basic types -

• The Long Stroke unit• The Short Stroke unit

The operating principles of the two types are broadly the same in that one or more hydraulic cylinders move a plate upon which there are one or two sets of slips (travelling slips). There is also a pair of fixed slips (stationary slips). It is possible to work the pipe into or out of the well using first one set and then the other.

The Long Stroke unit consists of a frame (either attached to a skid, carrier or trailer) which contains all the working parts of the unit itself. At its base, it is attached to the BOP stack and within the frame there is typically one 18 ft. stroke hydraulic cylinder. Using a system of cables and sheaves, this is multiplied to give 36 ft. of stroke on the travelling head.

Typical capacities of the units are 120,000 lbs. lift with 60,000 lbs. snub.

Advantages of the Long Stroke

• Faster rig up and tripping times

• Minimum crane requirements• Ability to rack pipe in singles or doubles on some units

Disadvantages

• Individual component lifts are heavier

• Lower lift and snub capacity

The Short Stroke unit is the most common type of unit in use due in part to its versatility and ease of transport and use. At present, in the North Sea and onshore Continental Europe, this is the type of unit that is available.

The Short Stroke unit consists of one or more, (usually 4) hydraulic cylinders (or jacks) attached to a frame. At the base of the frame are the stationary slips and attached to the top of the cylinders is the travelling head and the travelling slips.

By cycling the cylinders up and down, the pipe can be transferred from slip set to slip set and jacked into or out of the well. The unit is completely self contained during operations and is designed to pick up and lay down joints of pipe using the winches and the gin pole. A crew of 3 or 4 is located in the workbasket at the top of the unit.


Advantages of the Short Stroke

• High lift and snub capacities

• Higher rotary torque values

• BOP stack heights are not restricted

• Compact unitary construction for ease of rig up in confined spaces

• Shipping package weights small• Very limited deck loading imposed after rig up and only

shipping package weights need be considered

The short stroke unit requires a suitable crane for rigging up on the tree/wellhead and all the loads of the unit and the tubing forces are taken on the tree/wellhead. It is extremely rare to find a wellhead which cannot take the imposed loads during a snubbing job and it is more common to find a platform deck with weight restrictions. It is very nearly always possible to engineer the work for any given well/platform.

The crew are located in the workbasket from where, normally, one man operates the counterbalance winches and one man works the hydraulic controls for the jack (the chief operator) and a third man operates the tongs and manoeuvres the pipe.

Snubbing units vary from 75,000 lbs. lift capacity (35,000 lbs. snub force) with a through bore of 41/16 inch up to 600,000 lbs. lift capacity (300,000 lbs. snub force) with a through bore of 11". Depth limitations are normally determined by the available workstring sizes.

Rotary capacities are at present no more than 6,000 ft-lbs, which is usually more than enough to over-torque a workstring. For higher downhole torque, mud motors are used.

The available area below a jack leg piston is approximately twice that available above the piston due to the rod. This, therefore, roughly halves the available force on the downward or snub stroke.

Current trends are for larger capacity units for heavier work previously performed by coiled tubing units and some of the post drilling work previously done by drilling rigs.


Running completions after the rig has drilled, cemented casing and moved are now common in certain areas. Similarly, perforating new wells without a drilling rig is routinely done by some operators. Other more recent developments are:-

• Work in highly deviated and horizontal wells beyond the scope of coiled tubing

• Running and pulling very long TCP gun assemblies up to 1500m without the need for drilling large rat holes (particularly in horizontal wells where Coiled Tubing has problems)

• Well/platform abandonment on platforms with no derricks or derricks that would require large amounts of money to refurbish and re-certify for use

• Under-balanced and slim hole multi lateral drilling using small drill pipe

There is a new generation of units using a long stroke unit built into a standard workover rig so as to give it a snubbing capability. There are also plans to change the style of the short stroke unit for Norway to remove the need for the crew to work in the workbasket. The units will have joy stick control from ground level with automated pipe handling and make up. These units are now starting to come into service.

Snubbing units are rigged up directly onto the Xmas tree for through-tubing work, or onto the wellhead, after removal of the Xmas tree, if completion components are to be pulled or run. They can be rigged up on drill pipe if required.

The equipment is rigged up as individual lifts or sub-assemblies and nippled directly onto the tree/wellhead or previous component. The normal maximum lift is of the order of 6 tonnes for a larger jack and does not usually cause problems. If a very tall rig up is required due to the number of BOP’s in use, there are occasionally problems with the maximum reach of a platform crane. Where this is the case, it is sometimes necessary to take a portable rig up crane with the unit although this adds to the rig up time and costs.

The equipment is transported in baskets or on skids and a full short stroke unit, including all its auxiliary components, for North Sea use can fully occupy the deck of a supply ship.


Snubbing Unit Rig Up


6.2SURFACE EQUIPMENT

6.2.1HYDRAULIC JACKThe jack is an assembly of hydraulic cylinders and slip bowls that enables the pipe to be moved in or out of the well. The workbasket is located at the top of the assembly. The power tong arm, tongs, gin pole and counterbalance winch are attached to the workbasket.

On the top of the cylinders is the travelling head that carries two slip bowls and the rotary. The hydraulic circuits can be set up to provide different speeds and power levels for the travelling head. The hydraulic fluid can be directed into all 4 cylinders or into only 2. On some units it is possible to select which two opposing legs whereas on others, there is no choice. This is called 4-leg and 2-leg operation. It is also possible to select whether the hydraulic fluid being returned from the un-pressurised side of the cylinders is directed back to the tank or added to the fluid going to do the work in the pressurised side. This is called regeneration and is equivalent to high and low gearing.

There are thus 4 operating modes:-

• 2 leg high (with regeneration) Fastest but lowest power

• 2 leg low

• 4 leg high (with regeneration)

• 4 leg low Slowest with highest power

It is normal to start the job in 2 legs high and, as the pipe weight increases, change into the other modes as required. It is a very simple job of turning a valve or two in the workbasket to change from one mode to another.

The stroke of a jack depends on the make, but most in the North Sea have a 10 ft. working stroke.

6.2.2GUIDE TUBESThe higher the well pressure, the greater the force pushing up on a given piece of pipe being snubbed into or out of the well. Since the pipe coming up through the window and the jack is only restrained at a distance from the stripper bowl, there is a problem with potential buckling of the pipe out of the side of the window or jack. For this reason, in higher pressure wells, guide tubes are placed in the window and in the jack. These restrain the pipe and stop it being buckled out of the side. The guide tubes can be easily inserted or removed and the one through the jack is in two pieces. One piece is sitting in the jack, hanging from a level with the top of the legs, and the other (inner) piece is hanging from the travelling head and sliding up and down inside the lower section.

6.2.3ACCESS WINDOWThe window is a large heavily constructed item consisting of two heavy plates with solid steel legs spacing them apart. There are usually 4 legs and a window is always rated to the full load capacity of the unit. Traditionally 4 ft., 6 ft., 10 ft. or occasionally 15 ft. long, the window are used to enable


large OD items of BHA, completions, etc. to be run or pulled without having to pass them through the slightly restricted ID of the slip bowls. With a hole through the top and bottom plates of usually 111/16 inch or 135/8 inch, they are bolted directly to the top of the stripper rubber and the jack is bolted to the top of the window. If rigged up on a Xmas tree and using a small diameter washout string, a window may not be required. For many jobs, such as running completions they are a much safer option than working a large OD component down through the slip bowls, having first split them open.

Some windows are equipped with a beam at the top to enable a torque turn equipped back up tong to be hung in the window for making up the completion assemblies.

6.2.4SLIPSTravelling slips are attached to the travelling head and consist of one bowl for pipe heavy and one bowl for pipe light. Almost always hydraulically operated, the two bowls are the same with the pipe light bowl facing down. Similarly, the stationary slips are attached near the bottom of the jack, but do not move. In high pressure wells, it is normal to use an extra set of stationary snubbers for safety.


Slip Operating Sequence (Light Pipe Running In)


6.2.5ROTARY TABLEThe rotary table is attached to the travelling head. This means that it is possible to rotate the pipe while moving the pipe in or out of the well. At present, most rotary capacities are about 6000 ft-lb. maximum. This is usually more that a work string tool joint can safely take.

Because the rotary is on top of the head, it can be a maximum of 10 to 12 ft. above the top of the cylinders at full stroke. Therefore, current rotary capacities are about the maximum that the design can achieve. Much higher capacity rotary's' are now installed in the windows of the latest North Sea short stroke units. This however greatly reduces the capacity to rotate whilst running in/pulling out.

6.2.6WORK BASKETThe workbasket is attached to the top of the jack and provides the workstations for the crew who operate the controls for all the snubbing unit functions from here. The pipe is made up using the power tongs.

A standpipe is attached up the outside of the unit and terminates at this level. Attached to it are a circulating hose and swivel with a connection to the pipe being run. By attaching the circulating hose to a joint of pipe either in the hole or about to be run in the hole, it is possible to circulate whilst pulling up a joint of pipe or running it.

At the operator’s console, there are two weight indicators, one for heavy pipe and one for light pipe. These weight indicators are reading the hydraulic pressure in the jack circuits and so do not show any readings when the weight of the pipe is in the stationary slips.

6.2.7COUNTER BALANCE The winches for raising and lowering pipe are called counterbalance winches because they are hydraulically balanced to hold the weight of any particular object being lifted. With an individual load rating of between 1500 lbs. and 2000 lbs. usually, they are each controlled from the BOP console by means of a separate hydraulic valve. Through this system, the force applied to each hydraulic winch is controlled so that when it is enough to just lift the joint of pipe, the remaining hydraulic fluid diverting back to tank. A good operator can set the valve such that the joint of pipe will be stationary, with the pin end in his hand, but he is able to raise or lower it by as much as he wants just by pulling up or pushing down on the joint with his hand.

6.2.8POWER PACKMost power packs are powered by diesel engines driving multiple hydraulic pumps. All functions of the unit are able to be supplied from the one power pack although normally when using torque turn equipped back up tongs, the casing running contractor will use his own power pack for his tongs. The primary power for the BOP control panel is from this main power pack.


6.2.9POWER TONGSTongs are normally hung from the tong arm attached to the side of the work basket. If small tubing is being run through an existing completion then the tongs will probably be from the snubbing contractor and will be powered from the main power pack. Some units have the ability to hang tongs in the window for making up completion assemblies.

6.2.10GUY WIRESAll HWO/snubbing units require guy wires to hold the units vertical. This is because some wellheads with clamp type connections are not strong when bending moments are applied. The positioning of the guy wires is dependant upon the rig up height of the unit and the expected wind loading. This is very much greater with enclosed workbaskets that act as a sail at the top of the rig up. Four guy wires are always attached at the top of the jack and may well also be attached at the base of the jack and/or half way up the BOP’s. Firm anchors a suitable distance from the centre line of the rig up are required for the wires, suitably spread around the well.

6.2.11OTHER EQUIPMENTAll snubbing units have the ability to place hand operated slip bowls on the base plate of the window. These are used when it is necessary to ‘hang’ the pipe below the slip bowls so that both bowls can be opened or the pipe broken out or made up in the window. This could be when making up large OD items of BHA, completion assemblies, changing stripper rubbers, etc.

On some units, it is common practice to rig up a hanger flange in the stack. This is usually just below the stripper bowl or sometimes the annular. This is used for exactly the same purpose as the hand slip bowl. It is much slower in use as it requires each of the, usually, 8 dogs to be screwed in by hand. It can be very useful when shutting down for the night on a 12 hr/day operation if there is a worry about the pipe moving through the slip bowls when the unit is unattended. Care must always be taken with a small hanger flange to ensure that the forces acting on the pipe can be held by the dogs. In a small hanger flange, there might only be 4 or 6 dogs.

Because of the nature of the pipe upsets and the BOP’s, it is not normal practice for a snubbing unit to hang the pipe in the BOP’s. Also, a large proportion of a job can be spent with either negative weight or limited positive weight in the string.


6.3PRESSURE CONTROL EQUIPMENT

6.4STRIPPER BOWL

The stripper bowl assembly is a special device that is used for the following:-

• Primary well control with low wellhead pressure work (the primary barrier)

• Pipe cleaning when pulling out

• Prevents debris from dropping into the wellbore during tripping

Stripper bowls are available with single and dual elements. Dual element bowls are now becoming rare. They are rated to an absolute maximum of 3000 psi. although in practice the stripper rubber cannot be relied on as the primary well containment device at pressures above 2500 psi.

The use of the stripper bowl allows for the continuous handling of pipe with a tapered upset or no upset. It is normal to have to change the stripper rubber(s) during a job.

Wear on the rubbers is affected by:-

• Wellhead pressure

• Lubrication at the rubber

• External pipe roughness

Stripper Bowl6.4.1ANNULAR BOP

If deploying long BHA’s with varying diameters, it may not be possible to operate the stripper rubber or stripper rams due to the lack of distance between the wellhead and the strippers. In this situation, use of an annular BOP may be required.


The annular BOP is identical to a standard BOP used in drilling operations although normally of a smaller size. A typical BOP would be a Shaffer or Cameron 11" 10M or 71/16 inch 10M. The pressure rating is specified according to the wellhead pressure.

The annular BOP is used when normal ram-type BOP’s cannot seal around a large diameter, such as a side pocket mandrel, blast joint etc. slip joint. The Annular is a secondary barrier. There are many different makes and types and it should be noted that not all annulars will close and seal on open hole.


During snubbing operations, it is normal practice to have a 1 gal accumulator in the closing line hydraulic circuit to allow tool joints to be stripped through the annular, maintaining a steady hydraulic pressure on the closing line and preventing it from over-pressurising.

The Hydril “GS” is designed for snubbing operations. Made in various sizes and pressure ratings, the packing unit is designed for continuous use and wellbore assistance on closing is greater than in many Stripping BOP’s

6.4.2STRIPPING BOP’SStripping BOP’s are standard ram-type BOP’s as used in drilling operations with special elements to enable them to seal on moving pipe. There are many different makes and types of ram-type BOP’s. Bowen is probably the only company making a BOP specially for snubbing operations, having easily changeable ram bodies. A typical BOP stack for snubbing operations might be anything from 2.9/16” 20000 psi. to 13.5/8” 5000 psi.

As with all ram type BOP’s, they are designed to hold pressure from below only and the pressure across the inner seals must be equalised before attempting to open them.

A ram type BOP may be dressed as a stripping BOP or as a pipe ram (safety ram). The BOP itself is the same. They can also be dressed with variable rams, slip rams, blind rams or shear rams.


6.4.3STRIPPING RAM SEALSThese BOP’s are used as the primary well control when the wellhead pressure is greater than the stripper bowl can handle i.e. above 2500 to 3000 psi.

The pressure rating and size are determined by the wellhead pressure and work to be undertaken. They are always used in pairs to enable a tool joint to be "worked" through while still retaining a seal around the pipe. It is normal practise to have to change stripping ram inner seals with their inserts during the course of a job.

The life of the inserts is affected by:-

• Pipe external condition

• Well pressure

• Speed of running of the pipe

It is normal practise when using stripping rams to also use a stripper bowl to provide:-

• Barrier for egress of hydrocarbons

• Pipe wiper

• Debris barrier


The spool between the strippers must be of sufficient length to allow the pipe to be pulled slowly through the BOP’s whilst sequentially opening and closing them. It is traditionally 4' to 6' long. The spool and equalising loop are of a fixed size on any particular unit and pipe pulling speed is reduced while the tool joint passes through the BOP’s. It is not necessary however to stop pulling for this operation.

Stripping Ram Sequence (Running In)


6.4.4EQUALISING LOOPThe equalising loop is used to equalise pressure across the lower stripper BOP’s.

Note: BOP rams should only be opened after the pressure has been equalised, otherwise, the ram seal may be damaged

The equalising loop connects from below the upper stripper to below the lower stripper ram. The remotely operated valves are controlled from the work basket 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 the repair of the remotely operated valves.

6.4.5BLEED OFF LINEThe bleed off line is used for bleeding off the pressure below the upper stripper ram so that the ram can be opened without damage.

6.4.6RAM TYPE BOP’S These are normal drilling type BOP’s and are used as pipe rams or as blind, shear or blind/shear rams. They can also be dressed as slip rams or variable bore rams.

It is necessary to have one BOP in the stack dressed for each size of pipe in use since there is no way to redress the rams during the job. For jobs involving tapered strings of pipe, pulling very long fish, etc., 2 or more safeties will be required. Often called the safety BOP’s (safeties), they are normally only used when changing elements in the stripping rams, annular or stripper bowl, or when the pipe is stationary for a period of time. The safeties are normally placed in the stack immediately below the stripping rams. Safeties are secondary barriers and shears are tertiary barriers.

Where separate blind and shear rams are used, the choice of where to place them is often dictated by well conditions or operator preference. For many snubbing jobs, the shear is placed below the blind since the pipe may well be trying to push out of the well bore at the time it is required to be cut.

Conventional shear rams may not always cut the workstring completely (for example if it is required to cut a BHA with a fish inside) and it may be necessary to RIH one or two joints before operating normal shear rams.

6.4.7CAMERON U BOPThe primary seal on the piston rod is a set of seals (and back up rings) around the piston rod/connecting rod. With most makes and types of ram type BOP’s, there is a secondary seal created by injected plastic packing. In the case of the Cameron U type this is on the intermediate flange. It is invariably on the outboard side of the primary seals.

The purpose of this secondary seal is to stop the wellbore fluids from escaping and/or contaminating the hydraulic fluid should the primary seals be leaking. Since there is no way of directly seeing if the primary seals are leaking, there is often a weep hole so that if the primary seals do leak, the fluid will drip out of the hole and can be seen. Should this happen, the BOP must be redressed as soon as operationally possible. With the Cameron U


type, the weep hole is on the bottom face of the intermediate flange).

6.4.8SHEAR AND SEAL BOP’SShear/Seal BOP’s (Safety heads) are used on jobs where it is necessary to have the ability to cut more than just the work string. Most shear/blind or shear rams will only cut the workstring and not BHA, fish, wire, etc., these BOP’s have extra large hydraulic cylinders and pistons to give a greater force to the cutting action. Like a shear/blind, they will seal off the hole after cutting. They are usually standard BOP’s with different bonnet assemblies to give the greater hydraulic force.

These BOP’s are placed as close to the wellhead as possible but below any riser on offshore installations for some regulatory bodies. These are tertiary barriers.

6.4.9RISERS AND CONNECTIONSThese form part of the pressure control equipment in that they contain wellbore fluids and pressure during a job, all the pressure equipment for snubbing work invariably has flanged connections. It is normal practice to have the shear/seal attached to the tree as closely as possible.

6.4.10BOP CONTROL SKIDAll North Sea HWO/Snubbing units have a BOP control skid separate from the main power pack. All BOP skids derive their primary power supply from the power pack and have a separate air or electric power supply as a back up. Basic controls are provided in the workbasket for most or all of the BOP functions. Some units do not have the Shear/Seal control in the basket. A duplicate set of controls is provided at the BOP control skid although this does not always include the stripper rams.

On some jobs, where the unit is rigged up alongside a drilling rig offshore, the operator may ask for a third (remote) panel for controlling the secondary and tertiary controls to be placed beside the rig’s remote panel at an escape route. All control skids contain banks of Nitrogen pre-charged accumulators. The number of accumulators will depend on the number of BOP’s being used and the local regulatory body requirements. The equipment varies from unit to unit, with many units having a simple BOP control skid taking its main power from the power pack skid and having a manual pump for back up.


6.5BARRIER PHILOSOPHY(SNUBBING)

6.5.1CONTAINMENT DEVICES IN THE WORKSTRINGThere are two main types that are commonly used:-

• Check valves

• Pump down plug and landing nippleCheck valve Since the pipe is open at all times to surface, two check valves or back pressure valves (BPV’s) are always placed at the bottom of the string, above the BHA. They allow fluid to be pumped down the string but stop flow up the pipe when pumping is stopped. Both ball and seat check valves and flapper valves are used. Flapper type check valves have the advantage of allowing balls to be pumped through them for operating tools in the BHA.

Since the flow area through these valves is fairly small, if there is any scale in the tubing it is quite easy for debris to plug them off. Two operations should be performed to minimise the risk of this happening:-

• Tubing is to be inspected and rattled immediately prior to going out.

• When filling up the string, pump one or two barrels through the valves every 10 or 20 joints, to prevent collapse of the pipe. This is to ensure they are still open and to clear out any build-up of debris

The check valves are the primary internal barriers.


BPV’s (Check Valves)

In jobs involving large amounts of pumping it is not uncommon for both back pressure valves (BPV’s) to be washed out. A small wireline type landing nipple is always placed above the BPV’s so that in the event of a leakage through the BPV’s, a plug can be seated in the nipple prior to pulling out with the pipe. The pulling of a wet string is a favourite time for snubbers although it is normal to pump the pipe full of water prior to pumping the plug so as to minimise pollution from hydrocarbons or corrosive brines. These back-up devices are the secondary internal barriers.


Pump down plug and landing nipple


6.5.2PUMP DOWN PLUG AND NIPPLEA very wide variety of BHA devices can be used as a means of internal primary well control including:-

• Pump out plugs or pump out BPV’s

• Sliding Side Doors or Sliding Sleeves coupled with positive plugs. This is mostly to allow reverse circulation.

Full Opening Safety Valve


Gray Inside BOP

This wide variety of devices can allow tools to be operated in the BHA by dropping balls (including release joints) and allows the string to be run-in in the normal manner with twin BPV’s, later converted to reverse circulate. After reversing, it is necessary to re-install a device to allow the string to be pulled out with full internal well control.

As well as these items on the bottom of the string, full opening safety valves (TIW valves), inside BOP’s or stabbing valves must always be available in the workbasket. These can be used in the event of a tubing/BHA break or leak in the tubing string to immediately close off any flow from the well.

6.5.3STABBING VALVE


The stabbing valve is normally a plug valve with a tubing thread connection below and a 2” Weco threaded connection for pumping above. Advantages:

• Light

• Easy to stab onto flowing pipe

• Inbuilt pumping connection

Disadvantages:• Small through bore

• Wireline cannot be used through it

6.5.4FULL OPENING SAFETY VALVEThe full opening safety valve is much bigger than a stabbing valve

Advantages:

• Larger bore

• Easy to stab onto flowing pipe• Allows wireline to be rigged up on top of valve

Disadvantages

• Heavy

• Requires additional X-over for top connection for pumping

6.5.5INSIDE BOPThe inside BOP was originally designed for stripping operations on a rig floor and has pipe connections at both ends.

Advantages:

• Can be RIH

Disadvantages:

• Heavy

• Very difficult to stab onto flowing pipe

• Wireline cannot be used through it

• Requires additional X-over for top connection for pumping


6.5.6SURFACE LINES AND MANIFOLDSThe requirements for pumping and circulating facilities are different for each job, but all operations require some form of pump to conduct the following type of operation:

• A complete mixing and killing facility on an offshore satellite.

• A hook up on an offshore platform direct to existing facilities

• A remote land job requiring basic pressure testing and pumping facilities only

On the choke, kill and bleed off lines the main pressure control is via hydraulically operated valves controlled from the workbasket, with a manual valve as a backup to each. The manual valve must be on the inboard side of the hydraulic valve and remains unused in the open position throughout the job. It is only used when work needs to be done on the hydraulic valve.

The kill line is connected to the kill wing of the tree.

On some dead well operations, trip tank and fill-up line connections are made to the top of the stack below the window for use while tripping.

For all snubbing jobs, a fluid pump (usually a cement or frac pump) is required. It is used for pressure testing, filling the pipe, displacing the pipe before pulling out to remove hydrocarbons and brines (which can be dangerous for the crew), through tubing pumping operations, etc.

6.6OPERATIONS

Snubbing is performed on live wells and uses BOP’s and other mechanical devices for well control. In this respect, the principles are exactly the same as with Coiled Tubing.

A typical scenario might be as follows:

The unit is rigged up on a large offshore platform beside a derrick doing a normal workover. It is required to wash out scale in the perforations and rat hole. The SIWHP prior to the well scaling up was 2850 psi.

The unit has been rigged up on top of the Xmas tree with, (from bottom to top) 1 blind/shear ram, 1 pipe ram, 2 stripping rams, 1 annular BOP and a single element stripper bowl. The riser between the Xmas tree and the BOP’s is long enough to accommodate the BHA comprising a mill/under reamer/mud motors and BPV’s.

The choke and kill lines are connected to the rig circulating system and cement pump via a choke manifold.

Whilst running in with the clean out string, the wellhead pressure is low enough to use the stripper bowl. The two BPV’s in the workstring prevent flow back up through the tubing.

Once below the tailpipe, the rig cement pump is used for circulation, under reaming down with returns taken to a degasser and separator before returning to the pits. Well control is initially achieved by use of the annular


and stripper bowl with the stripping BOP’s and stripper rubber being used when the rat-hole is reached.

Having finished washing out, it is discovered that the BPV’s are both leaking so the pump down plug is dropped and seated. With full wellhead pressure restored, the pipe is pulled using the stripping rams for well control.

The BOP’s are controlled from the workbasket, a set on the BOP skid and a third remote panel has also been set up beside the rig remote panel due to the concurrent nature of the work.

Due to the comparative complexity of the equipment and the requirement for an in-depth knowledge of the operation of the equipment on a live well, it is normal practise to have a snubbing supervisor (the equivalent of a toolpusher) on each snubbing crew.

It is his responsibility to ensure the safe and correct procedures are followed at all times and particularly when using stripping BOP’s, crossing the balance point, etc.

After the unit is rigged up on the well, all features are function tested. The stack is then pressure tested including all connections, lines, valves and manifolds. To test the rams it is necessary to pick up one or more joints of pipe and run them into the stack so that the BOP’s etc. can be tested. These joints will have the check valves (BPV’s) on the bottom, which also tests the BPV’s, and must be restrained from being pumped back out of the well as there will be considerable force generated beneath the closed check valves.

6.6.1OPENING THE WELLIntroducing the tool string into the wellhead is one of the most delicate phases of a snubbing operation. It is at this time that the string is at its lightest and upward forces are trying to eject or buckle the pipe.

Great care must be taken to ensure that the inverted, or snubbing, slips have taken a proper "bite" on the pipe, with the use of a clamp or dog collar below the slips is often required.

When introducing the pipe into the well, the stripper rubber is first inserted and secured. The BHA is then made up onto the first joint and pushed through the rubber. The ram(s) can then be closed and the well opened up after equalising across the closed tree valves.

It is normal practise to use one stripping BOP or the annular to centralise the BHA and stop it hanging up in the stack and tree.


6.6.2CROSSING THE BALANCE POINTIn theory, this is a single point but due to friction both down-hole and in the stack, this phase can last for several hundred feet. The technique used as the pipe nears the balance point is to make it heavy, quickly, by filling with fluid so that it can pass through the balance point.

During this phase it is very difficult to get the slips to "bite" on the pipe as the pipe appears to have no weight. The use of two stationary slips together (regular and inverted) or the use of two travelling slips together is to be avoided as this can lead to jamming of the pipe in the slips.

There are various methods of shortening and helping the balance point transition, but no matter what is done there will nearly always be a few tricky joints.

Pipe is usually filled (to prevent collapse) every ‘X’ joints depending on well and pipe conditions. The procedure for crossing the balance point running in is:-

• Stop

• Keep pipe "hanging" in travelling snubbers

• Close stationary heavies

• Fill pipe

Assuming the pipe has now crossed the balance point, change the travelling snubbers to regular slips and continue running in hole

In rare cases this will not have been enough to cross the balance point completely, in which case either:-

• Flow the well to reduce CITHP• Slug the pipe with a heavy fluid• Continue running in hole using dog collars

During pulling out the pipe is full of fluid and since it is not possible to empty the pipe to reduce its weight, the well pressure can be acted upon. Either:-

• Flow the well to increase the length of the "heavy" pipe phase and then shut in again. The balance point will have been passed

• If conditions permit, a slug of heavy fluid can be circulated round the outside of the string to reduce CITHP

In some circumstances, usually caused by pressure changes in the well, it may be found that once the balance point has been crossed it is found again after a few more joints and then finally for the third time. Each time the same procedures are adopted.


6.6.3PULLING OUT OF HOLEIt is important that as the last few joints being pulled are reached, there is an indicator in the tool string to warn the crew that the bottom of the string is approaching.

This is usually achieved by spacing out the landing nipple with a joint of pipe between it and the BPV’s so that when the nipple is at the work basket the master valve or blind ram can be closed and the stack de-pressurised.

If a very long BHA has been run or a fish has been caught, the landing nipple might be directly on top of the top BPV.

6.6.4JOB SUSPENSIONOn some jobs, only 12-hour operations are planned and the routine at night is usually as follows:-

• Install closed stabbing valve having filled tubing

• Close safety rams and manually lock

• Tighten dogs on hanger flange

6.7ESD SYSTEMS

It is to be noted that if the main hydraulic power pack on a snubbing unit is linked to any platform shutdown system more problems than advantages will occur.

It is imperative that the well is made safe in an emergency. Just as with a drilling rig, if the snubbing unit is linked to the ESD system, on a shutdown the pipe can be left up in the air with no way of closing it in. There is also the possibility that a joint of pipe hanging on the second winch will start to slip (it is a hydraulic winch) and could cause injury.

6.8DRY GAS WELLS

If a dry gas well is to be worked on, special consideration must be given to the hydraulic connections of the snubbing unit (of which there are many). Avoidance of any spillage is especially important as dry gas and hydraulic oil or grease/dope is a very volatile mixture. Any oil or dope building up around the stripper rubber or on top of the stripping rams soon becomes heavily contaminated with gas and is potentially dangerous.

These wells are fortunately rare and consideration is always given to injecting a small amount of liquid into the well prior to running the pipe.

It is important to keep the stripper rubber or stripping rams well lubricated to obtain a good seal around the pipe.


6.9COMBINED WIRELINE/SNUBBING OPERATIONS

Slickline or electric line operations can be conducted through the jack of a snubbing unit either by rigging up the wireline lubricator on the workstring or screwing an adapter into the stripper bowl and connecting a riser to the work basket.

In both cases normal wireline well control considerations apply, with either a master valve placed on top of the workstring or the snubbing unit blind ram used as a master valve.

6.9.1CONTINGENCIESIn the event of a well control problem occurring during operations, it is the responsibility of the equipment operators in the basket to shut the well in and make safe. The crew chief (chief operator, etc.) is usually working the jack controls and the second man is usually working the BOP/counterbalance panel. This can vary according to crew make-up, breaks, etc.

BOP Sealing Element LeakRam TypeThis can be considered as being in one of two categories:-

• BOP elements changed out as normal routine due to wear• Leaks around elements occurring unexpectedly

In the case of routine replacement due to wear (the stripping rams are susceptible to this), the inner seals can be changed by closing the safety rams, bleeding off above them and opening the stripping ram bonnets to change the inner seals. It would be normal practice to change the seals in both sets of stripping BOP’s at the same time.

In the case of unexpected leaks, all the BOP’s above the safeties can be repaired by closing the safeties, checking they are holding and then working on the stack. If possible, it is good practice to have two barriers by closing two BOPS' below the one that must be worked on.AnnularIn the case of a leaking annular, it would be necessary to pull back out of the hole, close the blind rams and rig the jack off the well before being able to open the bonnet of the annular. The annular should always start a new job with a fresh rubber and it is indeed a rare occurrence to have to change it during a job. If an annular rubber had to be changed during a job, it would be normal practice to come out of the hole, if at all possible, rather than open the annular with pipe in the hole.


Shear/SealIn the case of a leaking shear/seal, safety BOP or riser connection, the only choices are to pull back out of the hole and close or plug the wellhead or, if that is not possible to kill the well.

If the well being worked on is low pressure and the safeties will no longer hold pressure, the lower stripping BOP (which has seen little or no use) can be used as a replacement safety until the pipe is out of the hole.Check Valve FailureIt is not uncommon for the BPV’s to leak if a lot of pumping has taken place. The procedure in this case is to drop the pump down plug and pump it into its nipple. The plug can then be inflow tested and the pipe can be pulled out for a wet trip.Tubing PinholePrior to using a workstring it should be properly inspected and rattled to minimise the chance of pinholes and scale.

If work strings are not properly cared for, pinholes can develop. Usually pinholes are found when pipe is picked up for the first time. The crews will be looking out for them especially if the pipe quality looks poor.

As the pipe is run the operator can "feel" each tool joint, as it goes through the stripper rubber. As this is the start of a new joint, most operators' first reaction to a sudden egress of fluids out of the top of the pipe is to pull back to the tool joint and back it out. The stabbing valve or other device is then inserted and closed. It should now be possible to bleed down the tubing, which should show that the leak has stopped. Alternately, the tool joint can be run in further until a stabbing valve can be installed and closed.

If the above action does not cure the leak then it must have occurred downhole and the plug must be dropped and seated in the nipple to confirm whether it is the BHA or a tubing hole. If it is a tubing hole, it may be possible to run a wireline set bridge plug that could be used to plug the tubing above the hole and enable the pipe to be pulled otherwise the well will have to be killed.

Any sudden leak occurring before pulling out after washing operations could indicate a washout in the string or BHA (or other problem with the BHA) and will also require the same procedures.


Changing the Stripper RubberThis is a routine operation, but opens up the topmost containment device, and is performed as follows:-

• Close the annular and lower stripping ram and check they are holding

• Back out the retaining nut and pull out the rubber(s) with a tool joint

• Hang off the pipe and close the safety ram

• Bleed off below the annular through the bleed-off line

• Break the joint in the window

• Install the new rubber by placing on the box and screwing in the pin

• Make up the joint and take the weight of the string

• Open the safety ram and run in to seat the rubber

• Tighten the retaining nut

• Open the BOP’s and RIHLoss of PowerIn the event of a power loss to the snubbing unit, the BOP’s will not be affected as they are on an individual skid with two independent power supplies (e.g. diesel and air)

The worst time for a power loss to occur would be just after having made up a joint with most of it sticking up in the air above the workbasket. If the integrity of the BPV’s was in doubt the counterbalance winch can sometimes be rigged to run from the BOP skid and used to raise a man to install the stabbing valve.


section 6 snubbing

Documents