Coiled tubing operations and HSE considerations

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1 Service selection

The selection of the well intervention method for a particular task should consider:

  • Geographic location: The location determines accessibility, weight/size/configuration restrictions and service availability (e.g. skid mounted vs. truck mounted units), so as not to exceed platform capacities (eg. offshore lifting capacities) or prevent well access.
  • Well design: The depth of the well, whether it is deviated or a horizontal completion, and the installed hardware and sizes (e.g. coiled tubing vs. wireline workstring) need to be evaluated in conjunction with the workstring ratings and pumping capacities where appropriate.
  • Well operation: Whether the well is live, the pressures and temperatures, and fluid parameters (e.g. hoist vs. coiled tubing operations). For many of the activities it is preferable to work within the well without having to resort to kill fluid. The application of kill fluid (or loss circulation fluid) to the reservoir can in many cases permanently damage the well productivity. Additionally the ability to operate safely without kill fluid saves considerable material (brine salts, etc.), pumping costs and possible workover fluid losses to the formation.
  • Capital cost (recompletions): The capital cost of permanently installed equipment versus the equipment reliability and well intervention costs and safety issues (e.g. installation of PDGs versus BHP surveys).
  • Service costs: Operating costs versus the expected task duration and associated risk of downhole problems (e.g. selecting nitrogen lift versus swabbing).
  • Experience/competence: The degree of experience in the use of various techniques and competence of the activity executors (e.g. large integrated contractor versus independent specialist contractor).
  • HSE performance: The HSE and task related performance of the service providers in relation with specific activities.

2 Planning and equipment selection

A key aspect of any coiled tubing operation is the initial planning stage. There is no substitute for thorough planning. Most well intervention problems can be detected and avoided during the planning phase. All information should be considered, including mechanical, well, production, reservoir and associated historical well intervention data. Offset data can often be invaluable when evaluating the task.

Some points to consider when carrying out the assessment are as follows:

2.1 Scope of work

An agreed scope of work must be produced covering the following details:

  • Objectives to be achieved.
  • Feasibility of achieving the objectives taking account of any previous experience and computer force/stress analysis.
  • Detailed well parameters, including computer simulation if necessary, to aid equipment selection.
  • Estimation of timescale to complete the programme.
  • Contingency planning.

2.2 Pre-job analysis

2.2.1 Computer simulation

Development of these systems help answer questions about downhole flow and pressure conditions during coiled tubing operations. Utilising accepted fluid rheology models and proven correlations for two-phase flow, thermodynamic properties and friction gradients, accurate analysis of flow conditions can be achieved.

Coiled tubing force and stress analysis features have also been developed to assist preventing downhole failures. The computer systems consider specific well geometry, contact friction and coiled tubing material strengths in the determination of the stress conditions and also take into account circulation effects.

As the profile of the well becomes deviated and/or horizontal, each of these areas of analysis require various modifications. Fluid velocities and two-phase liquid slip effects change as the direction of gravity changes relative to the flow path. Force analysis has to incorporate additional effects such as contact friction and helical buckling.

Computer simulation should be considered essential for highly deviated or deep operation and when coiled tubing operations involve any of the following:

·Wellhead pressure in excess of 500 psi (35 bar).

  • Deviation angles greater than 70 degrees.
  • Long or heavy toolstrings.
  • Running deeper than 10,000 ft (3,000 metres).
  • Tapered coiled tubing strings.
  • Stiff wireline operations.
  • Cementing through coiled tubing.
  • Any operation which requires overpull to release from the BHA.
  • Any operation which requires set down of weight onto the BH.
  • Reverse circulation operations.
  • Any operation where a collapse pressure may be present during the operation.

The following highlights a number of critical characteristics which should not be overlooked

  • Fatigue damage: the amount and areas of fatigue damage likely to be incurred by the coiled tubing during the job should be estimated to ensure that no particular part of the coiled tubing string will be overworked.
  • Materials capability: consider effects on the coiled tubing and components produced by the well fluids and treatment fluids, i.e.:
  1. Sweet or sour conditions, H2S, CO2.
  2. Elastomer seal behaviour.
  3. Chemical activity between metals and treatment fluids.
  • Fluids compatibility: the effects produced when well fluids and treatment fluids are mixed in the reservoir and wellbore.
  • Laboratory analysis: to confirm the properties of cements, gels and unusual chemicals which are to be used in the coiled tubing
  • Fluid flow analysis: should confirm that flowrates and pressures necessary to achieve the objectives are attainable within the limitations of the coiled tubing or the well.
  • Force and stress analysis: should be carried out on any coiled tubing operation to confirm that the objectives can be achieved within the safe operating limits of the coiled tubing and associated equipment/tools.

2.2.2 Location preparation

The physical well location, as well as access roads/canals, should be checked well before activity start date. Specific items may include canal dredging and equipment (e.g. flowline) isolation and removal from the location. The time lag/cost factors for certain preparation work should not be underestimated.

2.2.3 Weather

Severe or abnormal weather can often disrupt activities. Weather forecasts should be reviewed for weather critical activities.

Seasonal weather conditions should be taken into consideration during the planning/scheduling period and weather windows utilised as appropriate.

2.3 Equipment selection

Selection of the required coiled tubing equipment should be made in conjunction with the pre-job analysis. The following criteria should be considered:

  • Fluid type and pump rate required will be a factor in deciding the size of coiled tubing.

Different casing configurations will require different pump capacities for similar lifting capabilities.

  • Well depth, deviation and geometry will affect the choice of tubing size, length of tubing on the reel, wall thickness and make up of the tubing string, i.e. whether tapered or not.
  • Well completion size and geometry may have an impact on the size of tubing to be used due to annular velocities and access into the well.
  • Material to be pumped can be a factor in deciding the size of tubing due to increased weight, i.e. heavy cements.
  • Location of the job and space available will determine the type of equipment to be used such as support and lifting frames.
  • Location of the job and space available will also govern the size of gooseneck. At all times the largest sized gooseneck should be used to minimise fatigue damage to the tubing.
  • The required coiled tubing operating pressure and the amount of cycling at any one particular point.
  • Existing fatigue life of the coiled tubing strings which may be used on the job. The CT management system should provide details of the CT fatigue life, such as:
  1. Running length on the coil and a definition of how it is determined.
  2. Number of cycles on the coil, and a definition of how it is determined (pressures, etc.).
  3. The type and number of jobs the coil has been involved in.
  4. Diameter and ovality tests.
  5. The number and location of welds on the coil since the pipe was delivered from the factory. Also a record of the X-ray and hardness test performed on the welded area, as well as the ball size pumped through the coiled tubing after the weld.
  • Two physical barriers are required between surface and wellbore pressures.
  • The operating envelope of the tool string, selected tools and accessories.
  • Tool dimensions. The bottom hole assembly (BHA) should be drawn, with dimensions, and each component labelled. This will assist with site make-up, act as a fishing guide and help to ensure that the dimensions of the BHA are compatible with the wellbore and height of the riser.

2.4 Equipment layout

It is appreciated that owing to the variety of locations, such as land, well jackets, open/closed platforms, no hard and fast rules can be formulated as to equipment layout. However, it is extremely important, when planning any coiled tubing operation, that everyone concerned is aware of the basic safety standards, such as hazardous zones, fire precautions and emergency procedures.

The layout of surface equipment must take account of hazardous areas and allow safe access and egress for personnel during normal and emergency situations. It should be noted that if the work program includes hydrocarbon production through the coiled tubing, the hazardous area drawing needs to be modified accordingly to include the coiled tubing reel and production equipment. Although the nitrogen tanks do not contain flammable gas or vapour, the hazards associated with pressurised gas should not be overlooked in the equipment layout for protection of personnel and nearby facilities.

Layout drawings showing the position of each piece of equipment will ensure that there is adequate space to locate all equipment. With particular reference to offshore locations, a detailed drawing showing dimensions of the well, riser, BOPs, crossovers, pup joints and injector head will ensure that the necessary height requirement is available.

The coiled tubing contractor must ensure that the space between the tubing reel and the well does not restrict the angle of the tubing from the reel to the gooseneck, taking account of the injector head height above the reel.

2.5 Critical safety activity analysis/safety case

To ensure a safe operation, all hazardous activities associated with the operation need to have been identified and adequate controls and contingency measures put in place to manage the associated risks.

3 Pre-job checks

It should be confirmed that the following checks have been made when the coiled tubing equipment is on site.

  1. All equipment checked for damage during transit.
  2. Equipment operation, typically limited to checking power pack drivers, spare parts, tools etc. without rig-up.
  3. The wellhead crossover has been physically checked and is fully serviceable.
  4. All relevant contractor equipment documentation is available. This will vary dependant on location but should include:
  • Pressure containing equipment certification
  • Pressure test charts
  • Chemical hazard data sheets
  • Chemical tank certification
  • Lifting equipment certification
  • Coiled tubing reel unit log book/CT management system

4 Pre-job meeting

4.1 Operations

Prior to the commencement of any coiled tubing operation, a pre-job meeting must be held to familiarise all parties involved in the job programme. A copy of the proposed coiled tubing programme should be available to all present.

The meeting should cover the following topics:

4.1.1 Objectives

The coiled tubing programme should be presented and each operation discussed.

4.1.2 Well Information

The following aspects relevant to the well should be discussed:

  • Well history.
  • Tubular information (weights, grades, sizes, etc.).
  • Directional profile of the well.
  • Fluids in the well.
  • Any obstructions or known problems (fish, leaks etc.).
  • All other pertinent depths, equipment and information.
  • Pertinent drilling, production and other workover history.
  • Well pressure (shut-in tubing pressure, flowing tubing head pressure, casing pressures).
  • Any corrosion, erosion, and scale problems and their possible impact on operations.
  • Other rig/concurrent activity.
  • Required equipment rig-up.
  • Any other significant information.

4.1.3 Operation control and communications

To ensure the safe and efficient completion of each stage of the programme the following must be established:

  • Well Handover Acceptance (Simultaneous/Concurrent/Work Permit requirements). Often overlooked are the implications of well intervention activities with adjacent producing wells. Certain constraints may be imposed, which need to be addressed at the planning stage. Permits should be applied for before equipment mobilisation.
  • Responsibilities of Personnel
  • Lines of Communications. Concise and frequent communication between the phases from job objective setting to completion can avoid countless problems and unnecessary activity. A detailed procedure and well schematic should be prepared, reviewed and agreed by all parties well before the task to be performed. Should it become necessary to deviate from the approved procedure, adequate consideration should be given to the consequent implications and adequate time allowed for review and approval.
  • Actions in the event of rig, platform or site emergency or warning alarms.
  • Actions related to test facility utilisation or clean up/returns via exiting production facilities.

4.1.4 Hazards associated with the job

  • Well control.
  • Pressure testing.
  • Downhole equipment testing.
  • Chemical treatments.
  • Nitrogen operations.
  • Any other "what if" scenarios.
  • Oil spillage/chemical spillage, etc.

4.2 Safety

It is essential that prior to any coiled tubing operation the safety issues are addressed.

At the safety meeting all aspects of the coiled tubing operation and detailed contingency plans should be discussed. Coiled tubing emergency procedures will form the basis of these contingency plans. Of particular importance are the aspects of Well Control Procedures, which are complicated by the large inventory of fluid contained within the reel of coiled tubing. This requires various actions dependent on the point of failure, specific fluid conditions, etc. in the event of a barrier failure.

Specific safety requirements for the site should be discussed and should include the following:

  • Work permit and any concurrent operational requirements for the site.
  • Wearing of protective clothing.
  • Fire extinguisher use and locations.
  • Gas and other monitoring requirements.
  • Precautions for working in an H2S location, including allocation and location of breathing apparatus.
  • Allocation of personnel for opening and closing of X-mas tree valves.
  • Chemical hazards with action to be taken in the event of spillage or personnel contamination.
  • Restriction of non essential personnel to the well site, wellhead area, rig floor and vicinity of coiled tubing equipment. This is especially important around the tubing reel.
  • Cranes should not be allowed to lift loads across the tubing or in the vicinity of the tubing reel.
  • Securing of the reel to load bearing points if possible. Coiled tubing units must be adequately anchored regardless of unit size or the operation being performed.
  • Contingency in case of an acid spill.
  • Contingency in case of an oil spill.

Under no circumstances should safety be compromised. Procedures should be observed, work permits strictly adhered to, and equipment operated within designed parameters.

5 Testing requirements

Prior to being despatched, coiled tubing and nitrogen equipment supplied by the contractor must have been maintained and tested in accordance with recognised industry standards. The coiled tubing reel should be blown dry with nitrogen prior to being despatched to the location.

A copy of all the relevant certification should be available, as well as the history of the coiled tubing (CT log book/CT management report).

On arrival on site all coiled tubing and components must be pressure tested. Each pressure test should be individually recorded on charts which are signed on satisfactory completion.

In general, all coiled tubing and auxiliary equipment will be subjected to the following pressure tests:

  • Full workshop pressure testing, this is a test to verify the material strength.

At present there is no API recommended test pressure for coiled tubing. In the absence of such a figure, 1.5 times the manufacturers maximum working pressure should be used.

  • On-site pressure testing. This should be a hydrostatic test to the maximum expected CITHP to verify pressure integrity every time the equipment is rigged up. This test must be maintained for a minimum period of 15 minutes after stabilisation.

During testing, all non-essential personnel must be cleared from the area and operators implementing the test must be screened from the danger of flying debris should the equipment under test fail. Testing should always be carried out hydraulically and not with gas.

Regular non-destructive testing (NDT) and inspection of the coiled tubing equipment is carried out in the field.

6 Operating practices

6.1 General

Potentially most coiled tubing operational failures will occur when running coiled tubing in the hole. The most common problem is buckling when the tubing hits some object or catches on a change of borehole diameter. The potential for buckling is a function of the coiled tubing wall thickness, diameter, and the size of the tubing or casing that the coiled tubing is being run into.

Prior to running in the hole the following information should be available on site:

  • Wellbore profile or completion diagram and well history.
  • Deviation profile of wellbore.
  • Computer simulation operating limit predictions.
  • In the absence of a computer operating limit prediction, the maximum allowable pressure rating of the tubing and the maximum allowable pull.
  • Diagram of bottom hole assembly giving tool dimensions.
  • Details of any wireline drift run prior to coiled tubing operations.

The control of remotely actuated Xmas tree and subsurface safety valves must be isolated while coiled tubing is being run in a well. Wellhead valves may either be locked open or control transferred to a separate control skid. Sub surface safety valves may be removed and sleeved, sleeved only, or control transferred to a separate control skid. They should not be held open by locking in hydraulic control pressure at the wellhead as pressure can bleed off over time and allow the valve to close.

The wellbore fluid and rheology must always be considered before any coiled tubing operation. The size of the bottom hole assembly in relation to the completion diameter can have a significant effect on the running in and pulling out weight. In the case of large bottom hole assemblies in relatively small tubulars, the annular clearance can be such that significant pistoning effects can occur which resist the movement of the coiled tubing and can cause swabbing of the well. High viscosity fluids in the annulus can also cause this effect.

High wellhead pressures cause a significant up thrust on coiled tubing, dependent on the cross sectional area of the tubing. This means that in high pressure wells the weight indicator will read negative until sufficient weight of coiled tubing is in the well to overcome the effect of pressure. In these situations the injector head requires a large amount of hydraulic thrust to "snub" the tubing in the well.

The thrust required from the injector reduces as more tubing is in the well, thus it is important to reduce the thrust setting on the injector as the tubing is run, to reduce the possibility of buckling the tubing.

It is recommended to circulate through the coiled tubing while running in hole. Should buckling occur while running in hole the pipe will form a kink that will in effect prevent circulation. If pumping liquid, this will be noticed by a rapid increase in circulating pressure. In many instances of buckling, the tubing has been folded over repeatedly before the injector has been stopped, resulting in a difficult operation to retrieve the coiled tubing.

6.2 Running speeds

In general the following practices are recommended: A maximum running speed in hole for normal operation of 50 feet per minute (15 m/minute). This may be increased, for operations such as PLTs, if the hole section has been previously traversed to ensure that no restrictions are evident.

A maximum running speed of 10 feet per minute (3 m/minute), when running through restrictions such as sliding side doors, nipples and gas lift mandrels. This reduced running speed should be applied for 50 feet (15 m) before and 50 feet (15 m) after the position of the downhole obstruction to allow for any discrepancies in the depth readings.

Pulling out of the hole (inside tubulars) the speed is not as critical, but should be limited to a maximum of 100 feet per minute (30 m/minute). The same speed reductions as above should be applied when pulling through well conduit restrictions or in open hole. In addition, on pulling out of the hole the speed should be reduced to 10 feet per minute (3 m/minute), when within 100 feet (30 m) of the wellhead or BOP.

6.3 Force considerations

Whilst running in or pulling out of the well, the safe stress/operating limits (predicted by computer simulation) must not be exceeded. If a computer prediction is not available to the operator, the following limits are recommended:

  • While running in the well the maximum instantaneous weight loss must not exceed 2,000 pounds less than the running weight.
  • While pulling out of the well the maximum pull must not exceed the lesser of:
  • 80% of the coiled tubing yield load, as determined by a triaxial equivalent stress analysis.
  • The setting of any over-pull safety joint contained in the BHA. (Computer prediction is required to determine the corresponding weight indicator readings in most cases).

In the event of any of these limits being reached, the reasons for the weight indicator readings must be determined before proceeding further.

6.4 Circulation rates

Circulation rates are dependant on the type of application and operation to be performed, e.g. solids removal during pressure jetting, motor operation, etc.

Relevant burst and collapse pressures must be known to ensure that the required circulation rate does not exceed the tubing operating envelope.

Circulation rates vary dependant on tubing size. A typical range of circulation rates are provided below, but in principle a computer simulation of the fluid dynamics will best predict required/safe circulation rates for the particular CT application:

Coiled tubing size(ins) / Circulation rate(bpm)

  • 1" / 0.75
  • 11/4" / 1.4
  • 11/2" / 2.0
  • 13/4" / 3.0

7 Hot work

Hot work (welding) during coiled tubing operations may only take place when authorised by a "Hot Work Permit", which is signed by both the person in charge of the coiled tubing activity and the responsible Production Operations Engineer. Operating procedures should address hot work requirement and need to be strictly adhered to. However, on site welding of coiled tubing is not recommended unless proper testing procedures can be adopted after the welding. In principle before starting a job there should be a spare CT reel as back up, particularly relevant for a 'critical' job at a remote location.

8 HSE policy guidelines

It is the policy of Shell companies to conduct their activities in such a way as to take foremost account of the health and safety of their employees and of other persons, and to give proper regard to the conservation of the environment. In implementing this policy Shell companies not only comply with the requirements of the relevant legislation but promote, in an appropriate manner, measures for the protection of health, safety and the environment for all who may be affected directly or indirectly by their activities.

Identified coiled tubing hazards

1 Tubing runs away into the well

  • Failure of injector head tension system - Overload of injector with weight of tubing and fluids

Pre-emptive:

  • Correct selection of injector for anticipated loads
  • Complete stress and force analysis of task programme prior to task initiation
  • Do not grease the injector head block chains

Reactive:

  • Reduce injector hydraulic pressure to zero, to cause safety brake in hydraulic motor to activate and stop the injector.

2 Tubing "shoots" out of the well

  • - Wellhead pressure greater than coiled tubing and fluid weight

Pre-emptive:

  • Correct selection of injector for anticipated loads
  • Injector gripper blocks fail to grip the tubing
  • Do not grease the injector head block chains

Reactive:

  • Increase injector hydraulic pressure to hold the tubing.

3 Tubing is pulled out of the stuffing box

  • BHA and end connector lost downhole

Pre-emptive:

  • Ensure tool string preparation is carried out correctly

Reactive:

  • Close blind rams
  • Stop injector before tubing passes through the chains

4 Tubing collapsed at surface

  • Tubing collapse pressure exceeded
  • Stuffing box leakage of wellbore fluids

Pre-emptive:

  • Confirm tubing collapse pressure limit prior to task initiation

Reactive:

  • Close blind rams

5 Coiled tubing reel drive fails

  • Cannot maintain back tension on tubing between injector head and the reel
  • Reel will unspool and tubing will attempt to unravel

Pre-emptive:

  • Ensure surface rig-up is carried out correctly

Reactive:

  • Remove personnel from immediate vicinity
  • Close blind rams

6 Coiled tubing stuck in the hole

  • Determine if the tubing itself is stuck or if the BHA being conveyed is stuck

Pre-emptive:

  • Determine emergency contingency prior to initiating task

Reactive:

  • Attempt to pull tubing out of the hole
  • Do not exceed a stress figure of 80% of the weak link release rating or 80% of the minimum yield rating for the coiled tubing being used

Note: Always use the lower of the two values- Kill the well- Run chemical cutter on electric line to release tubing/BHA

7 Power pack failure

  • Injector head ceases to function
  • Motor brakes will come on and hold the tubing

Pre-emptive:

  • Ensure that surface rig-up is carried out correctly

Reactive:

  • Ensure that coiled tubing is being held by the injector head
  • Investigate and rectify failure

8 Care to be taken when energising side door stuffing box stripper rubbers

  • Overpressurisation of these rubbers may lead to the collapse of the tubing

Pre-emptive:

  • Correct selection of stuffing box stripper rubbers for anticipated working pressures
  • Ensure rubber pressure limitations are known

Reactive:

  • Monitor side door pressure to ensure that overpressurisation does not take place

9 Negative weight recording

  • Coiled tubing end connector is pulled tight into the stuffing box

Pre-emptive:

  • Ensure that surface rig-up is carried out correctly

Reactive:

  • Lower the tool string slightly so that the end connector is out of the stuffing box

10 Suspect weight indication

Pre-emptive:

  • Ensure that Gooseneck is properly installed onto the injector head prior to initiating task

Reactive:

  • Ensure that all hinged rollers are closed on the injector head
  • Confirm that the tubing run follows the curve of the gooseneck as it approaches the top of the injector

11 Gun shear pins shear on firing

Pre-emptive:

  • Ensure that selected tool string does not include conventionally rated shear pins as the shock waves from firing the gun will easily shear the pins.

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