Coiled Tubing Operations

A tool for workover,drilling,and completion Services.

Coiled tubing is a continuous string of tubing, rolled onto a spool. It is made from rolling strip material into a tubular form and resistance welding along its length. Coiled-Tubing (CT) continues to grow as an enabling technology that provides cost economy and time efficiency for the oil and gas industry. It has gained wider acceptance in all operations involved in oil and gas exploration.

Also, see a video on a coil tubing job walk through.

Introduction

Coiled tubing has been used since 1960’s for simple pumping operations such as nitrogen kickoffs. During the early development, CT suffered a poor service quality due to tubing failures at the well site. In the mid 1980s, there was a dramatic improvement in the quality of the CT with the availability of improved materials. As the reliability of CT increased, new CT applications have developed which are more demanding on CT than the simple pumping operations mentioned above.

CT has become an integral component of many work over and well intervention operations (During production phase of the oil well, there are a number of problems that can occur which will negatively affect operations, production and ultimately revenue generated, such as failure of mechanical equipment, changes in production characteristics, plugging and increases in injection pressure., these events may occur, requiring modification of the well in order to achieve optimal production).

While well service/work over applications still account for more than 75% of CT use, technical advancements have increased the utilization of CT in wide applications like drilling, completion operations, sand cleanouts, acidizing, fracturing, well testing, perforating, and other remediation activities are combined with the speed and convenience of CT to provide even more benefit to well productivity.

According to industry experts, CT use continues to grow at an average rate of 10% per year, and many oil and gas producers routinely use CT techniques not only to remediate failing wells but also to complete new wells in a cost-effective manner. Many companies are aggressively developing equipment that leverages the multiple benefits of such activities and provides oil and gas producers with cost-effective alternatives.

What is Coiled Tubing?

Coiled tubing is exactly what it sounds like: a continuous string of tubing, rolled onto a spool. It is made from rolling strip material into a tubular form and resistance welding along its length. Upon its manufacturing, the tubing is rolled onto large spools with core diameters ranging from 8 – 12 feet. The strip material is joined together using carefully controlled bias welding processes, such that the final string has no visible butt welds. Strings as long as 26,000 feet have been fabricated.

Tubing outer diameters range from 0.75-in to as great as 4.5-in. It is fabricated in a variety of material grades, characterized by minimum monotonic yield strengths of 60, 70, 80, 90, 100, 110 and 120 ksi. The material is essentially carbon steel, modified for grain size refinement. The grain size of typical coiled tubing material is extremely fine; so fine it lies outside the range recognized by ASTM’s standard series of photomicrographs. The finest grain size recognized has an ASTM number of "10" while coiled tubing extrapolates to a grain size number of about 12.

Coil tubing Surface Equipments

Following diagram shows all the individual surface equipments in the coil tubing unit.

The coiled tubing is a continuous length of steel or composite tubing that is flexible enough to be wound on a large reel for transportation.

The coiled tubing unit is composed:

• Reel - for storage and transport of the coiled tubing.
• Injector Head - to provide the surface drive force to run and retrieve the coiled tubing.
• Control Cabin - from which the equipment operator monitors and controls the coiled tubing.
• Power Pack - to generate hydraulic and pneumatic power required to operate the coiled tubing unit.

Reel

The Reel is for storage and transport of the Coiled Tubing. The reel uses an offset open spoke type of construction with square and rectangular steel tubing. The core consists of a rolled steel tube and lateral cross support beams. The tubing reel is mounted on heavy duty roller bearings in a steel frame that is moved transversely by hydraulic cylinders to spool the tubing evenly.

The reel is driven by a chain and sprocket assembly powered by a hydraulic motor. Reel braking is accomplished through a self aligning air operated brake caliper and a flange mounted disk. The coiled tubing is connected to the reel shaft inside the reel core area. A high pressure ball valve is installed between the coiled tubing and the reel shaft.

• Direct drive and chain driven models.
• Tubing guide with diamond lead screw, level wind assembly and tubing oiler.
• Tubing sizes include 1, 1 ¼, 1 ½, 1 ¾ and 2 inch diameters.
• All units designed for rapid loading and unloading.
• Counters calibrated in feet or meters and are available with digital readout.
• High pressure swivels with hammer on unions.
• Reels may also be truck or trailer mounted.
• 15,000 working PSI rotating joint
• 48,000 ft of 1-1/4"
• 24,000 ft of 1-3/4"
• 18,000 ft of 2"
• Tubing Reel speed @ 28 GPM/2500 PSIG
• Speed, Max first layer (bare reel): 326 ft/min (99 m/min)
• Pulling force, max first layer (bare reel): 3,250 lb (1,474 kg)

BOP Stack

BOP's are available with internal or external hydraulics in bore sizes from 2-9/16" to 6-3/8" and working pressures from 5,000 PSI to 15,000 PSI for standard or sour service.

Blind Rams: Made of material 17-4 PH, will seal against pressure from below, with nothing between the rams, or on single strand measuring lines.

Shear Rams: Made of material 17-4 PH, are designed to shear [Bluing (steel)|steel]] coiled tubing. They will also shear stranded or slick line wire line, either individually or in the coiled tubing.

• Typically this unit uses a 4-1/2” annular preventer.
• 5-1/8” Dual Hydraulic Combination
• 4 1/16”-5000wp Dual Hydraulic Combination
• 3-1/2” Dual Hydraulic Combination

Control panel

There is a control panel in the operator’s station control panel is fitted with the following:

• Throttle Control
• Hydraulic Controls
• Oil Pressure Gauge
• Emergency Shutdown Switch
• Engine Temperature Gauge
• Air Pressure Gauge
• Carrier/Pump Selector
• Work Lights

Tubing

• Steel pipe 1" OD to 3.5" OD
• Yield strengths of 70,000, 80,000, 90,000, 100,000 psi
• Relatively thin wall
• Finite life due to fatigue cycles (bending)
• Hydraulically powered counter rotating chains
• Gripper blocks mounted in chain assembly
• Injector designation based on maximum pull capability, e.g. 30K can pull 30,000 pounds

Injector

Coil Tubing Injector is designed for handling coiled tubing sizes from 1" OD trough 2-3/8" OD. It is designed for operation with both, open and closed loop hydraulic systems.

• 60,000 lbs. continuous pull capacity @ 4400 Psi
• Maximum speed 250 Feet/min (90 or 120 g/min)
• Snubbing capacity is 30,000 lbs.
• All structures and ancillary systems are designed to the 60000 lb tubing load limit, plus gross weight of injector (10000 lbs).
• Injector weight 3500 lbs
• Chain Tension Hydraulically Adjusted
• Skate Pressure Hydraulically Adjusted

Principal components of injector head: Drive and brake system, Chain assembly, Traction and tension system, Guide-arch assembly and Secondary or support systems: Weight indicator Depth sensor mounts Stripper mount.

Coiled Tubing Operations

Many times, remedial work constitutes employing a work over rig to repair the well. A work over rig is used to retrieve the sucker rod string, pump or production tubing from the well or run wire line cleaning and repair equipment into the well. It is important to note that with work over activities, production must be stopped and the pressure in the reservoir contained, a process known as “killing” the well. Coil tubing has also been used as a cheaper version of work-over operations.

Until recently, coiled tubing has primarily been used to convey fluids down hole in such services as well kickoff, cleanout, and spotting fluids. Now, with the increase in the number of high-angle and horizontal wells, in addition to the high cost of conventional walkovers’, coiled tubing is being used to convey and operate down hole mechanical tools it has the following applications.

Pumping Applications

• Removing sand or fill from a wellbore
• Fracturing/acidizing a formation
• Unloading a well with nitrogen
• Gravel packing
• Cutting tubular with fluid
• Pumping slurry plugs
• Zone isolation (to control flow profiles)
• Scale removal (hydraulic)
• Removal of wax, hydrocarbon, or hydrate plugs

Mechanical Applications

• Setting a plug or packer
• Fishing
• Perforating
• Logging
• Scale removal (mechanical)
• Cutting tubular (mechanical)
• Sliding sleeve operation
• Running a completion
• Straddles for zonal isolation
• Drilling

General Operations for Flowing Wells

Here are the few important and general operations which are performed regularly are discussed here in detail. These can be applied in flowing wells.

Unloading a Well with Nitrogen

Liquid loading is a common problem in many gas wells. The well can be loaded by work over or completion fluids following a work over or completion job. Wellbores can also be loaded with produced liquid (such as water or hydrocarbon condensate in the late life of a gas well) when the reservoir pressure has decreased. In either case, the accumulated wellbore liquid needs to be removed, i.e., the well needs to be unloaded to restore the well’s production. There have been a number of unloading techniques used for liquid unloading, for example, plunger lift, velocity string, surfactants, intermittent gas lift, swabbing, etc.

Unloading gas wells with nitrogen (N2) are one of the most common applications of coiled tubing (CT). The unique feature of CT unloading, as compared to conventional gas lift, is that the gas injection depth can be changed continuously. Despite the large number of CT unloading jobs performed annually, the fundamental and frequently-asked questions such as optimum N2 rate and optimum gas injection depths as well as CT run into hole (RIH) speed remain.

Using coiled tubing to unload a well with nitrogen is a quick and cost-effective method to remove the liquid load of the wellbore. During a coiled tubing unloading process, coiled tubing is run into the wellbore. Nitrogen can be pumped through the coiled tubing while CT is RIH or after CT has reached a certain depth. The nitrogen aerates the liquid column in the annulus. This reduces the hydrostatic pressure of fluid in the annulus; hence, the down hole pressure is reduced. When the down hole pressure is lower than the reservoir pressure, the reservoir fluid starts to flow into the wellbore. Since the reservoir fluid (gas for gas reservoirs) has a lower density than the loading liquid in the wellbore, the produced reservoir fluid helps to further reduce the bottom hole pressure. When the drawdown pressure is large enough to sustain steady flow from the reservoir, the pumping of nitrogen can be stopped and the CT can be pulled out of the hole. The well will continue to produce by itself.

Coil Tubing Drilling (CTD)

Coiled tubing drilling technology is gaining popularity and momentum as a significant and reliable method of drilling horizontal underbalanced wells, and is quickly moving into new frontiers.

Coiled tubing is an ideal technology for underbalanced drilling due to its absence of drill string connections resulting in continuous underbalanced capabilities, as well as its suitability for sour well drilling and live well intervention without surface releases of reservoir gas. Through the use of pressure deployment procedures it is possible to complete the drilling operation without need to kill the well, thereby maintaining underbalanced conditions right through to the production phase. The use of coiled tubing also provides the means for continuous wire line communication with downhole steering, logging and pressure recording devices.

BHA for CTD

Coiled tubing drilling rigs currently exist in several different forms and setups, but generally consist of a drilling coil, injector to feed the tubing into or out of the well, BOP system for well control and return fluid path, and a control cab and power unit. The coiled tubing drilling equipment consisted of either 60.3mm or 73.0mm (2.375 or 2.875 inch) coiled tubing and injector with a hydraulic power unit with control cabin and accumulator. A coiled tubing hybrid mast unit and substructure complete with V-door, catwalk and pipe racks was used. Pumping equipment included a fluid pumper capable of liquid rates of 0.10-1.5 m3/min (0.6 - 10 barrels per minute), nitrogen pumper capable of 10-120 m3/min (350 - 4250 standard cubic feet per minute), and a nitrogen bulk storage unit of 50,000 m3 (1.8 million standard cubic feet) capacity. When drilling sour gas formations, a chemical injection pump for corrosion inhibition may be used.

Of the two coils commonly available, 73.0 mm is the preferred size due to its added weight on bit, stiffness, increased annular velocity and decreased pump pressure compared to the 60.3mm coil. However, to remain transportable under local highway size and weight restrictions, length of 73.0mm coil is limited to approximately 3000m of useable coil. Wells deeper than 3000 mMD, or alternatively those requiring drilling through 114.3mm (4.5 inch) casings would require use of the 60.3mm size, with a depth restriction more in the order of 4200 mMD.

A relatively modern drilling technique involves using coiled tubing instead of conventional drill pipe. This has the advantage of requiring less effort to trip in and out of the well (the coil can simply be run in and pulled out while drill string must be assembled and dismantled joint by joint while tripping in and out). Instead of rotating the drill bit by using a rotary table or top drive at the surface, it is turned by a downhole motor, powered by the motion of drilling fluid pumped from surface. Drilling which is powered by a mud motor instead of a rotating pipe is generally called slide drilling.

Logging and perforating

These recent applications have led to a wider use of coiled tubing as a means of reservoir data acquisition as well as a means of reservoir management. Through coiled tubing, one is able to obtain most of the same logging (reservoir) data and bottom hole production data in horizontal wells that are possible in less deviated wells using conventional wire line methods. Coiled tubing provides the means of transverse highly deviated wells with downhole instrumentation packages in a controlled manner. Data acquisition can be in real-time by the use of through-tubing wire line or in post sequence time with memory packages. Much of the data obtained using coiled tubing does not have to be obtained in the real-time mode. An exception to this could be downhole depth control when perforating or setting plugs.

These tasks are by default the realm of wire line. Because coiled tubing is rigid, it can be pushed into the well from the surface. This is an advantage over wire line, which depends on the weight of the tool string to be lowered into the well. For highly deviated and horizontal wells, gravity may be insufficient for wire line logging. Roller stem and tractors can often overcome this disadvantage at greatly reduced cost, particularly on small platforms and subsea wells where coiled tubing would require mobilizing an expensive mobile drilling rig. The use of coiled tubing for these tasks is usually confined to occasions where it is already on site for another purpose, for example a logging run following a chemical wash.

Removing Sand or Fill from a Wellbore

The removal of sand or fill from a wellbore is the most common CT operation performed in the field. The process has several names, including sand washing, sand jetting, sand cleanout, and fill removal. The objective of this process is to remove an accumulation of solid particles in the wellbore. These materials will act to impede fluid flow and reduce well productivity. In many cases CT is the only viable means of removing fill from a wellbore. Fill includes materials such as formation sand or fines, proppant flow back or fracture operation screen out, and gravel-pack failures.

The typical procedure involved in this application is to circulate a fluid through the CT while slowly penetrating the fill with an appropriate jetting nozzle attached to the end of the CT string. This action causes the fill material to become entrained in the circulating fluid flow, and is subsequently transported out of the wellbore through the CT/production tubing annulus. Where consolidated fill is present, the procedure may require the assistance of a downhole motor and bit or impact drill.

An alternative fill removal approach is to pump down the CT/production tubing annulus and allow the returns to be transported to surface within the CT string. This procedure, called reverse circulation, can be very useful for removing large quantities of particulate, such as frac sand, from the wellbore. It may also be applied when a particular wellbore configuration precludes annular velocities sufficient to lift the fill material. Reverse circulation is suitable only for dead wells.

Fracturing / Acidizing a Formation

This CT application has experienced significant growth in recent years, and provides several advantages versus conventional formation treatment techniques. In particular, CT provides the ability to quickly move in and out of the hole (or be quickly repositioned) when fracturing multiple zones in a single well. CT also provides the ability to facture or accurately spot the treatment fluid to ensure complete coverage of the zone of interest. When used in conjunction with an appropriate diversion technique, more uniform treating of long target zones can be achieved. This is particularly important in horizontal wellbores. At the end of the formation treating operation, CT can be used to remove any sand plugs used in the treating process, and to lift the well to be placed on production.

Acidizing involves the injection of chemicals to eat away at any skin damage, “cleaning up” the formation, thereby improving the flow of reservoir fluids. Acid can also be used to clean the wellbore of some scales that form mineral laden produced water.

Cementing

Cementing through conventional coiled tubing (CT) is becoming a common practice, even though still a challenging technique that requires a good preparation. Slurry design and job execution are the key factors for the success of conventional cementing through CT. The cement slurry must be carefully designed and tailored to the specific wellbore conditions and formation characteristics. The main properties to be closely monitored are slurry stability, rheology, fluid loss, and thickening time.

Slurry Design. Cement slurry density is a main consideration based on the reservoir or wellbore fluid density. It is also related to the wellbore hydraulic calculations and the reservoir gradient; the density is strongly related to the amount of bulk in the mixture volume. This slurry will require specific rheology to be able to be pumped through the coiled tubing pipe.

Advantages of Coil Tubing

CT operations have the following advantages:

• Self contained - rarely requires any additional services on site to perform job duties.
• Smaller footprint - One unit on location as compared to conventional service rig, leaving the location less disturbed.
• Speed - The amount of time required to complete or service the well is reduced with no connections required.
• Live well conditions - As coil tubing units are built to work on live well conditions, ensuring minimal damage to formation from use of liquids.
• Cost - Costs of coil tubing comparative to service rigs are substantially lower due to the amount of equipment, manpower, as well as the ability to haul its own pipe.
• Safety - As most accidents are human error having less personnel on location reduces chances of incident or accident happening.
• Ground Disturbance - As coil tubing units are free standing, ground disturbance (e.g. Anchors) is virtually eliminated.
• Versatile - coil tubing is very versatile in which we can work on a variety of well bore conditions as well as pump virtually anything through tubing from air to condensate

Coil tubing Capabilities

• Drill and trip under pressure.
• Fast trips.
• Continuous circulation while tripping pipe.
• Continuous, high-quality two-way telemetry between surface and down hole for real-time data and control.
• Slim hole capability.
• Small location size.
• Portability.

Coil tubing Limitations

Coil tubing being an emerging tool in the well intervention operations still this system have the following limitations:

• Cannot rotate.
• Limited fishing capabilities.
• Small diameters.
• Limited reach in horizontal laterals.
• Low circulating rates.
• High circulating pressures.
• Short tube life.
• High maintenance.
• High daily costs.
• Limited availability of high-capacity units.

World-wide Coil tubing records

Following shows different world records which are achieved by coil tubing equipments:

• Largest CT in Use: 3-1/2"
• Max Depth-24,000'
• Max Horizontal-17,000' (80 deg)-Wytch BP
• Longest BHA-1500' - perf guns - UK
• Longest Strings-23,000' of 2-3/8" & 28,000' of 1-1/2
• Max Wellhead Pressure- 9800 psi
• Max Deployment Press-4500 psi
• Max BH Temp700F - Mex, 780F Japan
• Max Acid at Temp-28% at 280F in Dubai
• CT in H2S-75% in Greece,98%/300F- Gulf of Mexico (string used one time).