What is Snubbing
History of Snubbing
The Advantages of Rig Assist Snubbing
Pre-Job Calculation Worksheet
Snubbing Rules of Thumb
Oil & Gas Information
What is Snubbing?
Snubbing is a method for inserting tools and tubulars into wells under pressure that ensures that wells can be safely serviced without having to use kill weight with fluids. The process of snubbing involves the tripping of pipe into and out of a well with surface pressure.
Snubbing –when the surface pressure and the work string combination is such that, if unrestrained, the pipe would be ejected from the well, moving the pipe is termed snubbing. The common term used in the field to describe this situation is “pipe light”.
Stripping –when the weight of the pipe becomes greater than the force of pressure acting on the cross sectional area of the pipe, the pipe will fall into the well bore by gravity. This procedure is termed “stripping”. The common term used in the field to describe this situation is “pipe heavy”.
During snubbing or stripping operations, a combination of the surface BOPs, wireline plugs or string floats, and hydrostatic pressure may be used to control the well. The surface BOPs are in constant use and are the primary form of well control. Snubbing is mainly used on projects where it is desirable to maintain the well in underbalanced conditions at all times. Many oil companies use snubbing on projects ranging from simple completions to high pressure workovers to underbalanced drilling situations.
Hydraulic rig assist units are the most common style of snubbing units in use today. They are highly mobile and typically truck mounted. The unique, short design of the unit, is the result of an innovation that places the BOPs inside the hydraulic jack making the rig assist unit highly compatible with all sizes of service and drilling rigs.
History of Snubbing
1928. The process of snubbing was first developed in the United States with a cable and sheave system that used the drilling rig draw works as the prime force to “snub” the pipe into the well by moving the traveling block up. Needless to say this early technology was time consuming and cumbersome causing it to be used as a “disaster service” for well blow-outs or as a last resort when all else failed.
1960. The hydraulic jack was added to the design allowing the snubbing operator control over the insertion and removal of tubing thus creating the first self-contained modular unit. As a result, safety, speed and efficiency were markedly improved making snubbing more and more popular as a production tool in the oil and gas industry.
1973. The first hydraulic Snubbing Unit brought into Canada, was a trailer mounted style. Unfortunately the technology was not as developed as today making these units slow, cumbersome and expensive. So companies still preferred derricks.
1980. Al Vallet, a member of the Snubco management team, was the first Canadian to be trained in snubbing and became a pioneer in the Snubbing Industry by developing the first truck mounted hydraulic “Rig-Assist” Snubbing Unit in the world.
The Canadian “Rig-Assist” innovations included:
- One piece lift directly rigging onto the service rig BOP (blow-out preventer)
- High mobility – truck mounted
- Unique short design that places BOPs inside the hydraulic jack making the rig assist unit highly compatible to all sizes of service and drilling rigs
- An annular control system that allows for the stripping of collared tubing, thereby eliminating the need for pipe rams to strip collars at moderate to low pressure
- The unit retains the ability to trip pipe, ram to annular or ram to ram when the situation requires
Today. Rig assist has become common procedure on rigs throughout Canada.
Common Applications for Snubbing
- Jointed pipe operations
- Asphaltene, paraffin, and scale removal
- Completions, single and dual string
- High pressure workovers
- Deploying and retrieving packers, bridge plugs and other down-hole equipment
- Hydrate washing
- Installing sand screens
- Deploying and retrieving acidizing tools
- Fishing lost tools
- Milling operations
- Under-balanced drilling
- Blow-out control and re-entry work
- Deploying and retrieving tubing conveyed perforating guns
- Jointed pipe operations under pressure when a coil tubing unit is beyond it’s design parameters
With proper planning, virtually any application undertaken by a conventional work-over or drilling rig can be accomplished with snubbing.
The Advantages of Snubbing
More and more companies are using snubbing as routine procedure for completions and workovers. There is no need to kill a well, when snubbing offers a safe and easy alternative. Other advantages include:
- Eliminates the need for kill fluids
- No need for toxic kill fluids thereby saving time and money associated with buying, transporting and disposal of kill fluids. No need to use rig time to kill wells or recover the kill fluids to bring the wells back to a producing capability.
- Greatly reduces the need to handle fluids, thus reduces the chance of spills. Disposal of contaminated kill fluids in environmentally sensitive areas is not a concern.
- Reduces formation damage
- No need to introduce non-native fluids into the producing formation. Reservoirs are not subjected to overbalanced hydrostatic pressure and fluid losses into the formations are not encountered. Reduced production due to swelled clays or other water sensitive damage is eliminated.
- The same completion and workover tasks can be performed while maintaining a situation beneficial to the formation, usually resulting in increased production.
- Saves time and money
- The well can be tested to quickly determine the production capability of a zone being drilled into or worked on during a completion or workover. In some situations the well may be produced during the snubbing workover.
- Elimination of the time required swabbing or unloading the well with a boost gas in order to bring it back on line after a workover.
- The ability to rotate the work string while under pressure as opposed to coiled tubing technology.
- Compact and relatively light, the rig up and down time is typically less than an hour.
- Small crew size; fast tripping time.
- Retaining, in most cases, the ability to stand pipe in the derrick of the rig.
- Two separate BOP accumulator systems available for the well control equipment.
- The well operator can utilize the rig assist only for the portions of the well program that require snubbing.
- Lower day rates compared to other snubbing platforms.
- Environment friendly
- Produces a safer environment on wells with low formation pressure that will not support a column of fluid.
- Compact and portable equipment that has minimal impact on roads in environmentally sensitive areas.
- Eliminates the need to take water from rivers, creeks or other surface sources, or to take water from subsurface aquifers in areas where water is not abundant.
Annular BOP: A Bop with a full opening elastomer element that has the ability to seal on virtually any shape, as well as seal on itself in and emergency situation.
Balance Point: This term refers to the condition during a trip in or out of the hole where the pipe weight and the lift force exerted by the well acting on the cross-sectional area of the pipe being tripped is at or near equal.
BHA: Bottom hole assembly. Describes the production or workover tools used for completion or workover operations. (i.e. packers, bridge plugs, fishing tools, etc).
BOP stack: A series of blow out preventers stacked together using an equalizing and bleed of spool. Stack normally consists of an annular; equalize spool and a set of stripping rams. In snubbing operations the BOP stack is considered a secondary BOP. When working in conjunction with a workover, service or drilling rig the rig supplies the primary BOP’s.
Counter Balance Winches: A winch that can hydraulically counter balance the weight it is picking up. This give the winch the ability to automatically feed off should the load placed upon it become greater than the actual weight being held via the hydraulics. Typically the snubbing unit will have two of these winches.
Equalize line: High pressure line pipe, chick sans (swivels) and valves for use during a snubbing operation to equalize or bleed off pressures within different chambers in a snubbing BOP stack.
Equalize spool: A ported spool for use in a snubbing operations allowing the operator the ability to equalize or bleed off certain sections of the BOP stack.
Gas well snubbing: Workover or completion work on a gas well which is either live or underbalanced with a rig assist or self contained snubbing unit. Many gas well formations are fluid sensitive making a snubbing operation ideal for maximum production of the well. Eliminates the need for expensive kill fluids.
Guide Tube: Any arrangement of support system that prevents columnar buckling of the pipe being snubbed. Typical arrangements can be telescopic or static depending on the design of the snubbing unit structure.
Hydraulic Workover Unit: A unit that competes directly with conventional work over rigs. By utilizing hydraulic cylinders instead of a traditional draw-works arrangement, the unit maintains a small footprint allowing rig up in tight areas such as on offshore platforms.
Knockout plug: Same as a TEP
Live well completions: A well condition where tubulars and tools are pulled or inserted into a well with the use of a rig assist snubbing unit or self contained snubbing unit. The well has surface pressure from the down hole formations. Wells can be either gas or oil.
Live well workovers: Describes the condition of a gas or oil well is in when tubulars are snubbed in or out of well. There is pressure at surface in these wells making them ideal candidates for snubbing operations.
Lower snubbing basket: The work floor area which allows access to the snubbing crew to the BOP stack components and stationary snubbing and heavy slips.
Passive Rotary: A turn-table integrally mounted in the snubbing unit traveling plate which allows the rotation of the string with the slips closed on the pipe in either the snub mode or pipe heavy mode. This rotary must be driven with an external force be it by hand or with a power swivel rigged above the unit.
Pipe Heavy: In regards to snubbing, this is a pipe condition in which the tubing has sufficient string weight to overcome the forces acting on its cross-sectional area. Once the weight is sufficient, it overcomes the force applied by the pressure in the well and will fall under its own weight into the well.
Pipe Light: In regards to snubbing this is a term which describes the condition when the well bore forces acting on the cross-sectional area of the pipe being snubbed are greater than string weight and if tubing was not controlled with a snubbing unit would eject itself from the well.
Power-Pack: This is the prime mover that provides the force needed to turn hydraulic pumps which allow the operation of the snubbing jack and BOP systems. Diesel engines are the most common form, although electric drives are also utilized in special circumstances.
Powered Rotary: A turn-table integrally mounted in the snubbing unit traveling plate which allows the rotation of the string with the slips closed on the pipe in either the snub mode or pipe heavy mode. This rotary is driven with hydraulic motors allowing the unit to perform string rotation without external support equipment.
Power Tongs: Hydraulically actuated equipment used in the snubbing operation to make or break connections in the tubing string.
QRC: Cameron stripping BOP. QRC stands for quick ram change
Rig assist snubbing: A mobile snubbing unit either truck mounted or skid mounted that works in conjunction with a workover, service or drilling rig for workover or completions work on a live well or underbalanced well. Unit is capable or running or pulling tubulars and tools under pressure.
Scalloped spool: A spacer spool modified for snubbing to allow well bore pressures to equalize or bleed off around the tubing hanger when landing or pulling the hanger.
Self contained snubbing: A snubbing unit which stands alone by itself with no need of a service, workover or drilling rig. A self contained unit is capable of workover or completion work on a live well or underbalanced well or in direct.
Snubbing: A procedure in which tubing is ran or pulled from a well which is in an underbalanced or live well condition. Snubbing units have specialized pressure control devices which permit them to deliver drilling, completion and workover services while there is pressure in the wellbore. Snubbing units eliminate the need to neutralize well pressure prior to servicing and therefore avoid the formation damage which neutralizing pressure can have on a well’s ability to produce.
Snubbing Assistant: This person’s position is primarily focused on taking direction from the Snubbing operator, and entails routine maintenance, pipe handling and power tong operation.
Snubbing jack: The structure of the unit designed to withstand engineered ratings for both the pipe weight and the force applied by the unit’s hydraulic cylinders. The hydraulically operated equipment which enables crews to work on underbalanced or live well.
Snubbing Operator: Equivalent to a driller position, the snubbing operator physically operates the snubbing unit and takes direction from the Snubbing Supervisor. The operator is responsible for managing the daily activities of the rest of the snubbing crew, and ensuring that the equipment is functioning as designed.
Snubbing slips: A set of hydraulically actuated slips which can be run either inverted or right side up to control the movements of pipe in conjunction with a snubbing jack to insert or extract tubulars under live well or underbalanced conditions.
Snubbing Supervisor: Equivalent to a rig manager or tool push, the snubbing supervisor is responsible for all aspects of the snubbing unit and its operations. He/She is the direct liaison to the oil company representative he/she is working for. All members of the snubbing crew are subordinate to the snubbing supervisor. Typically the supervisor will have in excess of 10 years experience in snubbing operations.
Snubbing unit: A hydraulically actuated unit with slips, BOP stack and hydraulic jack for inserting or pulling tubing and BHA’s from underbalanced or live well conditions.
Staging tubing: Is the process of moving tubing into or out of a live or underbalanced well by using different sections of the BOP stack to insert or extract tubing connections or larger diameter tool assemblies. I.e. annular and a set of stripping pipe rams or two sets of stripping rams. The preventers are closed and opened in sequence allowing for tubing connections or larger diameter tools to be staged in with at least one preventer being closed to contain well bore pressures.
Stand alone snubbing (see self contained unit): Use of a snubbing unit by itself without the aid of a service, workover or drilling rig. Unit is capable of workover or completion work on a live well or underbalanced well.
Stationary heavy slips: Typically a set of slips which are mounted on a BOP stack which will control the movement of heavy pipe.
Stationary snubbing slips: A set of snubbing slips that are typically mounted on top of a BOP stack which will hold pipe that is in a pipe light or neutral state.
Stripping: During snubbing operations this is the procedure where you move pipe thru a closed preventer (pipe rams or annular) on a live or underbalanced well containing pressure from the well bore with a closed preventer.
Stripping on: The procedure in which a snubbing unit is rigged onto a service, workover or drilling rig which is holding the pipe heavy tubing string with their tubing slips and not with a tubing hanger landed.
Stripping Ram: A hydraulically operated Ram style BOP used during snubbing and stripping operations. Typically the ram front insert is a sacrificial material that is easily replaced for extended stripping. Materials for the inserts can be custom ordered for the application at hand.
TEP: A type of tubing plug developed for snubbing to control well bore pressures inside the tubing. Only viable for snubbing in operations. The plug is a machined collar with a removable disc and o ring. Once the tubing string has been snubbed in the disc can be knocked out by equalizing the tubing string and flowing the casing. Once an overbalanced condition has been achieved inside the tubing string the disc will fall out. Disc may also be removed by sand line or wire line tapping down on the disc once tubing string has been equalized with casing pressures.
Traveling heavy slips: Slips which are attached to the top of a snubbing units jack plate and control the movement of heavy pipe.
Traveling plate: The plate which connects the rods from the hydraulic cylinders together on a snubbing unit where the traveling and heavy slips are attached. There are many cylinder configurations and stroke lengths possible depending on job requirements.
Traveling snubbing slips: A set of slips mounted upside down on a snubbing jacks traveling plate which controls the movement of tubing in or out of a well. Slips will hold tubing only when tubing is in the pipe light state.
Underbalanced: A term to describe the pressure conditions in a well. Formation pressure is greater than the hydrostatic pressure of fluid, mud etc… exerted on the formation causing pressure to migrate to surface in a well. A well in an underbalanced state is a prime candidate for snubbing.
Underbalanced completions: The condition of a well when completion services such as snubbing are performed. Formation pressure is greater than the hydrostatic pressure inside the well bore causing pressure to be at surface in the well. Under balanced completions are prime candidates for snubbing. Typically wells have been perforated before snubbing unit arrives and the unit snubs in a production string to allow the well to be produced.
Underbalanced drilling: This term describes the condition of the well when drilling operations are on going. Snubbing units are used to snub out drill strings, i.e. bit changes and then snub in the drill string again or run productions strings.
Underbalanced workovers: The well is live with pressure to surface when workover operations are performed. Rig assist snubbing or self contained snubbing units are used for the running or pulling of tubulars and BHA’s. Typically the snubbing unit pulls pipe from the well, the original zone is worked over, abandoned, or a new zone perforated and the snubbing unit snubs the production string back into the well.
Upper snubbing basket: The work floor area on a snubbing unit which the snubbing crew stands and operates the snubbing jack.
Well control: In regards to snubbing, well control is the operation of containing well bore pressure with the use of a blow out preventer stack and tubing pressure by the use of a plugging system.
Snubbing Rules of Thumb
Force = Pressure X Area
Area = .7854 X Diameter X Diameter
- It takes one foot of tubing (nominal tubing sizes) to overcome each psi of wellbore pressure.
e.g. If well has 500 psi (3447 kpa) of surface pressure it will take 500 feet (152 m) of nominal size tubing to be inserted for the lift on the tubing to be overcome and the pipe to achieve a pipe neutral state.
(These calculations do not take into account buoyancy or friction forces working against tubing string. Also this rule thumb works for nominal weight tubing, not heavyweight tubing or drillpipe.)
- To calculate snub force: Snub force = Diameter X Diameter X Pressure X .7854
e.g. Wellbore pressure: 1000 psi (6894 kpa)
Tubing size: 2 3/8 J55 EUE (60.3mm)
Lift force = 2.375 X 2.375 X 1000 X .7854
Lift force = 4430 psi (30,544 kpa)
- To calculate amount of pipe to snub: Lift force ÷ Pipe Mass
Wellbore pressure: 1000 psi (6894 kpa)
Tubing size: 2 3/8 – 4.6 lbs/ft (60.3mm – 6.99 kg/m)
Lift force = 2.375 X 2.375 X 1000 X .7854
Lift force = 4430 psi (30,544 kpa)
Pipe to snub = Lift force ÷ Pipe mass
= 4430 ÷ 4.6 lbs / foot
= 963 feet (294m)
Thus 963 feet (294m) of tubing needs to be snubbed into the well to become pipe neutral.
An average joint is approximately 31 feet (9.56m) long so you would need 31 joints to become pipe neutral.
( These calculations do not take into account buoyancy or friction forces working against tubing string.)
- Lift force on a standard tubing hanger:
A tubing hanger has a diameter of 6.8125 (173.03 mm)
Tubing hanger area = .7854 X 6.8125 X 6.8125 (.7854 X 173.03 X 173.03)
= 36.54 square inches (23,514 mm squared)
If the wellbore pressure is 1000 psi (6894kpa) under the tubing hanger there will be a lift force of 36450 lbs (16212 dAn) against the tubing hanger.