Coil Tubing Unit- A Second Generation Work over Rig

INTRODUCTION

The Coiled Tubing (CT) is a second-generation hydraulic system for well servicing under pressure. It is a versatile tool and its use has many advantages such as:

1. Allows live well servicing.

2. Since kill fluid is not used, there is no formation damage

3. Allows circulation while RIH & POOH

4. Faster method with maximum handling speed of 250 ft/min.

5. Only method for packer completed wells.

6. Logging & perforating of highly deviated wells.

Coiled Tubing Applications:

Use of coil tubing for well servicing or others can be classified in two groups:

A. Conventional CT operationsB. Advance CT operations

A. Conventional CT Operations :

A.1. Jetting for production/activation:

Years ago when most drilling was performed in virgin reservoirs, initiating flow was not a problem. Most reservoirs had enough pressure to unload the completion fluid without any artificial help. However, with declining reservoir pressure, an external aid is often required to initiate flow.

Until recently, swabbing was very commonly practiced method to unload the well. But swabbing is very slow and can be very dangerous. With the advent of CTU, many operators gave up swabbing.

The CTU is rigged up on the well. There should be an adjustable choke in the flow downstream of the wing valve or a choke body that could be used if needed. The

flow-line must be secured to prevent movement, should high volume flow occur. All surface equipment should be pressure tested prior to going in the hole.

The normal procedure when jetting for production is to circulate gaseous nitrogen through CT as soon as it RIH and return is monitored. Well is unloaded up to desired/designed depth or till the well is active.

If the well could potentially exceed 5,000 psi at surface, the CT is POOH before the well has a chance to reach that pressure.

Fig. 1: Jetting for production

It is a fast, controlled and economical means of relieving the hydrostatic weight of well bore fluids. In certain cases like deeper wells or packer completed wells it’s the only choice.There are basically no calculations to be performed when jetting for production. The nitrogen injection rate required is dependent on pipe sizes and depth. For most tubular a rate of 150 to 350 SCFM is usually adequate.

A.2. Jetting for under balance perforation:

Often a well to be completed is to be perforated in a reservoir of known pressure. Since the reservoir pressure is known, the hydrostatic weight of the well-bore fluids can be adjusted to give a positive differential pressure towards the well bore when the zone is perforated. This differential is thought to be very advantageous to many people. The theory is that with the pressure differential towards the well-bore, when the zone is perforated, junk from the perforating gun and any solids around the well-bore will be pushed into the well-bore rather than into the formation. Also, this prevents any of the well-bore fluids from entering the formation.

Jetting to achieve a pressure differential is very simple. The CTU should be rigged up and tested as if jetting for production. However, the depth needed to run the CT is predetermined. The tubing is RIH while circulating nitrogen. After the desired depth is reached and the well blows dry, the CT is POOH and rigged down.

As an example consider a well 10,000 feet deep with 9 PPG fluid in the well bore and having a bottom hole pressure of 2000 psi. The hydrostatic weight of the well-bore fluid would be 10,000 x .052 x 9 = 4680 psi. Obviously, there is a great pressure differential towards the formation. If a 500 psi differential is desired towards the well bore, the depth (X) to which we would have to jet would be as follows:

(10,000-X) x 9 x 0.52 = 1500

Or 10,000-X = 3205

Or X = 6795 feet

If all the fluid up to 6795 feet from surface were jetted from the well bore, there would be 1500 psi. Hydrostatic weight, which would equal a 500 psi. Differential towards the well bore.

A.3. Jetting for zone evaluation:

After a well is drilled to a predetermined depth and open hole logs are run the well may be found to contain several possible productive zones. Especially if the well is in unknown area, the operator may want to evaluate each zone. He can get some

information on a zone’s potential from a drill stem test or a wire line formation tester, but for an accurate zone evaluation, the zone must be produced.

The zones in a well may be tested either in open hole or after casing has been set. If they are tested in open hole, the zone to be tested is isolated by means of packers. If tested after casing has been set, only one zone is perforated, thereby isolating it.

Whether tested open hole or through casing, there is normally a rig on the well. After the coiled tubing unit is rigged up, the coiled tubing is lowered into the hole while circulating nitrogen as if jetting for production.

After flow has been initiated or the zone proves to be non-productive, the tubing is pulled out of the hole and the unit rigged down. If another zone is to be tested soon, the injector may be set to one side on the rig floor.

Zone evaluation using CT and nitrogen is advantageous is many ways. It is fast, thereby saving on costly rig time. It is controlled on the return line by means of choke and valve and on the CT by means of hydraulic stripper rubber and blow out preventer. It is economical--often the most economical method that can be used.

A.4. Jetting to back-flush disposal or Injection well:

Almost all disposal and injection wells experience high pump in pressure at some time. These high injection pressures may be caused by several things: (A) Bacteria; (B) introduction of hydrocarbons through pump plungers or other means; (C) ferrous salts; (D) clay swelling; (E) foreign fluid filtrates; and (F) emulsions; Regardless of the cause, it is of the utmost importance to remove the damage and not enhance the problem by displacing it further back in the reservoir.

Back-flushing the reservoir will usually remove most of the damaging elements. Back flushing is accomplished by relieving the hydrostatic weight of the well-bore fluid and allowing the formation to feed into the reservoir.

The CTU is rigged up on the well and tubing injected into the well while circulating nitrogen. The CT is lowered to a depth at which flow stabilized or to bottom, whatever requested by the indentor. The returns should be monitored closely and the tubing be moved accordingly as these wells usually give up large quantities of sand and solids. The flow line should be checked periodically for leaks, as the sand solids will wear away the metal on elbows and bends. The well is normally jetted until the returns are free of sand or solids. The coiled tubing can be picked up and the nitrogen stopped and supply water turned into the well to observe injection pressure. If pressure is too high, the well can be jetted longer. In some formations it may be necessary to bleed the nitrogen off completely before injecting fluid into the formation.

Some reservoirs may not quit giving up sand. They may be so unconsolidated as to flow with the formation water. On these wells injections must begin before flow ceases. These forces the sand in suspension in the well bore back into the formation. If flow is allowed to cease, the sand in suspension will fall out and bridge in the well bore.

Back-flushing a formation utilizing CT and nitrogen is a fast, effective, and economical method of lowering injection pressures. This technique cleans the area around the well bore, which is where the majority of the problems occur.

The nitrogen injection rate is dependent upon pipe size and depth of formation. The desired rate would be one that would give a constant flow without excess gas or spray.

A.5. Sand washing with Water:

Sand in the well bore of any type well can be a problem. Sand may fill up to a point that it totally blocks production or injection. This sand may be formation sand, fracturing sand, or sand from injection fluids depending on the formation completed in and types of well. In nearly all cases the sand presents a problem and must be removed from the well bore.

There are several methods used to remove the sand, including bailing and circulating. Probably the most common method is to circulate water to wash the sand from the well bore. Until recent years the only way to do this was to run concentric tubing into the well bore to circulate through.

The introduction of CT was a boon to the oil and gas industry. CT provides quick, efficient, and economical means of cleaning sand and other solids from a well bore. The design of the CT allows circulation of fluids or gases while the pipe is being lowered or raised regardless of depth. With concentric tubing circulation must be stopped while adding or removing a joint of tubing.

CTU should be rigged up on the well to be washed in the normal manner. Flow lines should be checked to make sure they are secured. The choke should be of proper size for well conditions. The CT and all related surface equipment should be pressure tested before job. The fluid pump should be hooked up and enough water on hand. The fluid pump operator should know the maximum pressure allowed on the CT.

The tubing is RIH at thirty to forty feet per minute while circulating fluid at a slow rate. Maintaining circulation prevents the tubing from becoming plugged if it enters solid or plug. The addition of a good friction reducer to the water will allow circulation at a much better rate.

When the fill is tagged, circulation should be established to surface before washing down. At this point caution must be used not to wash down too fast. In 7 -in casing which holds 22 lbs. of sand per foot, circulation at a rate of 1/2 bpm, fluid would be laden with 1 lb. of sand per gallon if washing / penetration rate is 1 foot per minute. With limited velocity it is evident that a faster washing rate would be dangerous. If at any time fluid pump stops or circulation stops, the tubing should be POOH until pump resumes pumping or circulation is established.

The washing should be continued until the desired depth is reached. From bottom at least one well volume should be circulated to ensure removal of all solids. After returns clear up tag bottom again to make sure no fill has fallen back.

CTU is a safe, quick and versatile tool for cleaning out a wellbore. It is highly mobile and rigs up and down quickly. The smooth tubing with no collars is a distinct advantage when washing sand.

A.6. Sand washing with nitrified water:

Washing sand from well-bore using water as the circulating medium has been a standard operating procedure for many years. However, in recent years due to the decline in reservoir pressures, washing with a column of water is sometimes impossible, especially in deeper wells with low bottom hole pressures. Often the hydrostatic weight of the water will overcome the reservoir pressure making it impossible to circulate to surface.

There are several methods used to overcome the problem of lost circulation when washing sand. One method is to use a lost circulation material to plug the zone taking fluid. This will usually work, but often-irreparable damage is done to the formation. The best and safest method is to lighten the circulating fluid with gas to a degree that the hydrostatic weight of a column of the aerated fluid weighs less then the reservoir pressure.

The CTU unit is rigged up in the normal manner. The fluid pump and the nitrogen unit are connected together through ‘Y’ connection into the CTU reel. After the tubing unit and all surface equipment have been tested, the tubing is lowered in to the hole while circulating water and nitrogen. It is wise to circulate the aerated fluid from surface in order to have an aerated column once the fill is reached. After tagging the fill, the sand is washed, as would normally be done using water alone. Caution should be used not to wash too fast. Judgement must to used in determining wash rate with pipe size, water pump rate, and nitrogen pump rate considered.

The nitrogen to fluid ratio should be determined prior to starting a job. This ratio may be determined by using the fluid gradient charts. As an example let us assume a well

with 3000 psi reservoir pressure and washing with fresh water. From trial and error using different nitrogen to fluid ratios, we see that 200 scf per barrel will give us a hydrostatic weight of 2300 psi. Added to the hydrostatic weight will be approx. 500 psi friction pressure for a total circulating pressure of 2000 psi. This gives us a 200 psi well bore differential, which should be adequate.

After washing the fill out to the desired depth circulation should be maintained until the returns are clean. Bottom should be checked to be sure that no sand has fallen back into the hole. At this point, the hole may be unloaded by stopping the fluid, or it may be loaded by stopping the nitrogen. The CT may be POOH and rigged down.

Washing sand from well bore using CT as the work string and aerated water, as the circulating medium is a fast and economical technique in low BHP wells. The use of a low-pressure gradient fluid is far superior to using lost circulation materials.

A.7. Sand washing with foam:

The simplest method of washing sand from a well bore is to circulate water through CT. However, if the reservoir pressure is too low to support a column of water, the water must be lightened with gas. As aerated water system still may not be practical if the sand to be washed is at a great depth or is in large diameter pipe. The velocity achieved in large holes may not be sufficient to carry the sand from the well bore. The greater carrying capacity of foam may be required.

Foam has long been recognized as a low-pressure gradient fluid with a very good sand carrying capacity. Foam is a homogeneous mixture of gas in water emulsion comprised of 65% to 95% gases. Ideally the gas is nitrogen. Pumping a mixture of 99% water and 1% surfactant through an atomizer where it is mixed with nitrogen gas generates foam. The atomizer acts as a foam generator. Since foam is comprised mostly of gas, temperature and pressures affect its quality and rheological properties.

To wash sand from well-bore using foam, the coiled tubing unit is rigged up in the normal manner. It is a must that an adjustable choke is provided in the flow line to hold back pressure to maintain foam quality. The nitrogen discharge and fluid pump discharge are tied into the atomizer with care being taken that all connections match correctly. After everything is tested and checked, the CT is RIH.

Circulation of foam should be started at surface. This will displace any fluids in the hole as the tubing is lowered and assures circulation of foam once the sand is reached. Back pressure at surface must be controlled at all times to assure correct foam quality at bottom. Caution should be used not to wash too fast. Even with the excellent sand carrying capabilities of foam, it is possible to get the sand concentration too great. In

order to calculate the nitrogen to fluid ratio a bottom hole treating pressure must be assumed. This pressure should be somewhat less than the reservoir pressure to assure circulation without any loss to the formation. After deciding on the needed bottom hole pressure, the foam calculations are done. Since a circulating system is being used, a surface back pressure equal to the bottom hole pressure less the hydrostatic weight of the column of foam must be maintained to assure foam quality at bottom.

Fig. 2: Sand washing with foam

Once the sand has been washed to the desired depth, circulation should be maintained until the returns are clean. Bottom should be tagged several times to be sure all sand has been removed. Once the hole is clean, the well may be jetted in or filled with fluid by stopping either the water or nitrogen.

Options:

1. Low pressure injection into pressurized suction.

2. High pressure injection into treating line.

The use of foam through CT is safe, fast, and economical and sometimes the only way to wash sand from a well bore. The sand carrying capabilities of foam allows sand to be washed from deep, large diameter holes with limited pump rates and low velocities. This makes the use of CT practical on wells that might otherwise require a larger work string.

A.8. Clean out with a positive displacement motor (PDM)

The CTU is a very good tool for washing sand and other solids from a well bore. However, there are times when the coiled tubing cannot wash through the fill by jetting. The fill may be compacted sand, cement, scale or any one of many solids. To wash this type of fill it must first be drilled through and broken up so it can be washed from the well. The PDM enables this type of fill to be removed with CT.

PDM Equipment:

The PDM is a tool operated by fluid pressure. The motor is essentially multi-stage pump run in reverse. The specially designed motor consists of an obround-shaped spiral, passage stator containing a solid steel rotor, which rotates eccentrically. Shaped in a regular recurring wave from, this rotor is free to move at the upper end, while the lower end is attached to a connecting rod. The other end of the connecting rod is attached to drive shaft. When fluid is pumped under pressure through the tool, it is directed through the cavity between the rotor and the rubber lined stator. In order to flow to occur, the rotor is displaced and rotated by the pressure of the fluid column, which rotates the connecting rod, the drive shaft and finally the bit or mills.

The gelled water is used as driving fluid for drilling. Air should be avoided as far as possible. Nitrogen should not be pumped through the PDM because the gas dries out and impregnates the rubber lined stator. Diesel oil, acid, solvent should not be pumped through PDM. The PDM, however, should not be used to drill materials for which it is not designed such as nipples, storm chokes, etc.

Installing the PDM on CT:-

1. The tubing needed for the job should only be carried as far as possible. Extra tubing adds to friction pressure and reduces amount of torque that can be produced by PDM.

2. The pumper that is meant for PDM job should be capable of pumping at smooth level rate. In case of surging discharge, the PDM may not work.

3. Run the tubing down the injector and take out 2 ft of tubing down the BOP to work with. Cut the tubing end with pipe cutter to have a smooth end.

4. Flare the down end of CT and file the burs if any. Slip the bowl of the adapter up, then the O-ring. Screw in the flare nut and tighten with the 'T' wrench.

5. Make up the bit on the rig floor into the bottom of the PDM. The rest of the changeover apparatus should be made up in the bowl of the adapter.

6. Screw the PDM on. Make sure all connections are tight. The PDM will be turning at about 850 RPM, if it stalls and any connection loosens more than likely the tool will break off.

Scale Build up

Scale BuildupDrill Bit

Drill

CT tool assembly

Fig. 3: Clean out with PDM

PDM operational procedure: -

1. Install a lubricator long enough to house the PDM without allowing it to obstruct the master gate valve and just sufficient to allow injector to be installed at well head.

2. Record all the measurements of bit, PDM, change over sub before lowering into the well.

3. Test PDM at surface before lowering in the well by establishing pumping rate of 1/2 to 3/4 bb1 per minute (18 to 22 GPM). Note the pump pressure for future reference. It is very important that the fluid pump operator knows to pump at a constant rate and what his maximum pressure should be.

4. Pressure the CT to that of well- head pressure. Open the master gate valve and run in at a very low speed. Run in the tubing to the desired depth while doing circulation.

5. Tag obstruction and pick up approximately 25 ft. and establish a constant pump rate and steady pressure. The drill is then lowered on the fill. A pressure increase of 250 psi is desired. This differential indicates rotation of PDM at desired rpm. If a greater pressure

differential is read, it means the bit has stalled. A pressure drop could mean a hole in the CT or washed out seal or bearing in the PDM.

6. Keep the drilling rate fairly low. If the pressure differential goes above 300 psi tool should be picked up untill the original pressure is obtained and then lower back on the fill. Keep close watch on pump pressure, weight indicator and return from well.

7. In case of small diameter pipes, water with friction reducer can be used for removal of cuttings, but in larger pipes guar gum gel should be used to lift cutting / sand.

8. After drilling for 10 ft. pick up to original depth and make two to three passes in new hole and then drill further.

9. When drilling is finished, pick off the bottom and circulate to the bottom untill it is clean. Keep the string reciprocating up and down.

10. After the return is clear of any debris of cutting, pull out the string. Remove the PDM from tubing and rig down the unit

A.9. Paraffin Removal

A problem that has plagued producers since the discovery of the first oil well is that of paraffin deposition on well tubular. This is especially true for oils with a high asphaltine base. The low ends of oil may build up on the tubular to the extent of completely shutting off production.

There are several factors that influence the degree of paraffin build up:

1. Chemical composition of the produced oil.2. Bottom hole temperature of producing reservoir.3. Rate of production.4. Interval length of fresh water sands.5. Heat transfer of media in annulus

Often there is more than one contributing factor leading to paraffin build up. The whole cause of paraffin deposition is the cooling of the produced oil, which causes the low ends of the oil to solidify. These solids begin adhering to the tubular walls and to each other and will eventually reduce or stop flow.

An effective method of relieving paraffin build-up is to melt the paraffin with hot oil/hot water/chemicals. Specially designed HOT OIL UNITS are used to heat the lease oil/water to a temperature of 200 to 500 F and either bullhead it into the well or circulate it through a work string. If the paraffin depositing is solid it will often have to be “washed” out with a work string.

The CT is an excellent tool used in conjunction with hot oil for the removal of paraffin. The CTU is rigged up in standard manner. A high temperature pack-off rubber should be used in the pack-off. The hot oil truck’s discharge line is connected to the rotating

hub of the CTU reel. Hot oil/hot water/chemicals should be circulated through the CT until the CT is hot prior to going in the hole.

Circulation of the hot fluid should be maintained from surface to approximately 500 feet below the fresh water zones. Circulation should be maintained for at least two hours after reaching the desired depth. This will ensure melting away all the paraffin rather than simply washing a hole through it. Returns should be monitored to be sure the oil is hot enough to melt the paraffin before circulation is stopped.

Fig. 4: Paraffin removal with Hot Oil

Extreme caution should be used when working around hot oil/chemical. If the hot oil/chemical should come in contact with someone, it adheres and creates a much more severe burn than would hot water. Extreme care should be used when moving the coiled tubing while circulating hot fluid.

The design of the CTU makes it ideal for use with hot fluid. No other work string enables continuous circulation from surface to bottom. The CTU also has a very effective blowout preventer and pack-off assembly. Its operation is fast effective and economical. Usually production can be restored in hours where days or weeks may be spent bailing.

A.10. Acid Spotting

Sometimes we come across a problem that there is practically no injectivity or very poor injectivity, while checking injectivity prior to stimulation job. One such condition may be a lack of penetration on initial perforating. Re-perforating sometimes alleviates this problem. Another condition that sometimes exists is severe well-bore damage caused by drilling fluids. Whatever be the problem, spotting acid across the perforations will usually clean the well-bore and formation face sufficient to allow fluid penetration into the reservoir.

The use of a CTU is an ideal means of spotting acid-across-a formation. The CT is run to the bottom of the perforations. The volume of acid required to cover the perforated interval is pumped down the CT. The acid is followed by water to displace the acid. After the acid is displaced out of the CT, the tubing is picked up above the perforations. This prevents the acid from being displaced up the hole. If the production tubing is full of water, the wing valve may be closed and fluid pumped down the CT to check ability to pump into the formation. If the production tubing is not full of fluid, it should be filled with fluid or pressured up with nitrogen to determine if formation is open. If still unable to pump into the formation, it may be necessary to wash the formation face with more fresh acid.

A.11. Spotting a Cement plug

There are occasions when an operator would need to seal off a set of perforations for various reasons like (a) Gas shut off, (b) Water shut off or (c) Abandoning a well. A common method to seal off an unwanted zone is to spot a cement plug above the zone.

CTU is rigged up on the well and the tubing and surface equipment tested. The exact tubing capacity is determined by pumping water with food coloring or dye from a calibrated tank.

After the CT is lowered into the well to the desired depth, which may be checked against known plug back or with tubing end locator, the cementing truck may begin pumping. The number of feet of pipe that the volume of cement pumped will fill, should be calculated. With the CT located at the depth of the bottom of the cement plug, cement is pumped into the CT followed by displacement fluid. When the measured capacity of the CT has been pumped, the CT should be raised at a rate corresponding to the pump rate. This will ensure leaving a solid plug of cement without getting the cement up around the outside of the CT. By the time all of the cement has been pumped through the CT, end of the tubing should be located at the top of the plug. The CT should be over displaced by at least one barrel. The tubing can now be POOH and rigged down.The cement plug should be allowed to set. The plug can then the tested with pump pressure for sealing and with wire-line for depth placement.

The CTU provides an excellent method of spotting cement plug. No rig is required and the entire operation can be completed in a matter of hours. The well can be returned to production much quicker.

A.12. Zone Squeezing with Cement

There are times when an operator needs to abandon a perforated interval near a proposed zone. There may not be adequate space to set a cement plug between the zones; therefore, the unwanted interval must be squeezed off. The cement is squeezed back into the perforations leaving none inside the pipe.

The CTU is rigged up, tested and the tubing capacity accurately determined. Large diameter CT is preferred because of high friction pressures involved in pumping cement slurries. The mud gel or sand slurry of specific gravity, higher than that of cement slurry is circulated below perforation to be squeezed. The cement is pumped down the tubing just as if spotting a plug. After the cement has been spotted and the tubing over displaced, the tubing should be raised 100 feet above the cement. If the well is full of fluid the wing valve should be closed and water pumped down the CT. Pumping should continue until the production tubing reaches approximately 1000 psi. This pressure should be maintained for about 15 minutes. If unable to pressure up to 1000 psi, it may be necessary to run another batch of cement. The pressure is then bled off and a contaminate solution ( bio-polymer ) is circulated through the cement left in the casing so as not to allow cement to settle in the casing. After circulating contaminant solution the CT should be raised 500 ft. above the interval or POOH depending on the operator’s choice. After cement in the perforations has had sufficient time to set up, contaminated cement from well bore is circulated out using water. The

well should then be pressured up to 1000 psi and should hold

Fig.

5 :

Cem

ent s

quee

ze th

roug

h CT

that pressure for one hour. If it does not hold the pressure, the cementing process is repeated until the pressure holds. A higher pressure may be applied at the discretion of the operator.

Squeezing the cement while it is in the CT should not be done. This method has been attempted and has not proven successful. Several strings of CT have been cemented up trying this.The CTU provides an excellent means of squeezing off a zone furnishing following advantages.

1. Costly and damaging post-squeeze drill out procedure are eliminated.

2. More accurate placement of cement with lower required cement volume.

3. Cement squeezes may be performed through tubing and below permanent packer.

4. Cement squeezes can be performed successfully in highly deviated wells.

A.13. Circulating to kill a well

Often an operator will need to kill a well for various reasons. He may need to change some tubing, work on the tree, run some down hole tools or to control a near blow out condition when there is no tubing inside. The mechanical condition of the well may prevent pumping of killing fluid into the well from surface. Even if able to pump into the well, the operator may not want to force the fluid into the formation. The other method of killing the well would be to circulate water or mud down a work string until sufficient hydrostatic pressure is established.

A proven method of killing a well is by circulating water or brine down the CT. The CT is used just as a work string except it offers the capability of circulating as it is lowered into the hole.

It is very important to have an adjustable choke in the flow line. As the tubing is lowered and fluid circulated, as much back pressure as is practical should be held on the production tubing by means of the adjustable choke. By using the adjustable choke correctly, the gas is bled off and the fluid remains in the hole.

After running the CT to bottom or to a depth sufficient to establish a hydrostatic weight greater than the bottom hole pressure, circulation is maintained and gas bled off until

a solid column of fluid is established. The greater the pump rate, the faster this is accomplished. After the well is subdued, it is wise to circulate a volume equal to the well-bore capacity to be sure no gas pockets remain in the well. The CT can then be POOH and rigged down.

The process of killing a well can be very time consuming. Many factors such as pressure, well productivity index, and pipe sizes affect the case with which a well can be killed. However, the speeds of rigging up and going in and out of the hole make the CTU an excellent means of killing a well.

A.14. Gelled sand slurry placement

Placement of sand plugs to temporarily isolate one or more perforation or creating a base for cement plug or cement squeeze job is very popular in oil industry.

Well # XX

Fig7: Sand slurry placement

Deployment of CTU enables to carry out these jobs very effectively. Initially well bottom or top of the obstruction is checked by CTU. Depending on the hole size and length of fill, exact volume of sand is pumped through pumper (without CTU) and is allowed to settle down. Again bottom is checked by lowering CT and if excess sand is found it is cleared by circulation so that sand top is at the desired depth.

Sand Plug.

Wash Nozzle.

Check Valve Assembly.

CT Connector.

Coil Tubing.

upto 594m.

563

715 4.0MT Sand

Casing 5.1/2"

Ø=~6"

B. Advance CT operations

B.1. Completion with Coil Tubing

Coil tubing can be utilized as a production or an injection string. This has been proved to be more cost effective than conventional integral joint tubing.

Three primary applications in which coil tubing can be used as a permanent installation are -

I) Well Treating Strings,II) Gas Lift III) Production Siphon / Velocity String.

I) Well Treating Strings

There are wells that need treatment at regular intervals or sometimes continuously. These treatments may be to rectify various problems such as corrosion, paraffin deposits, salt deposits, chemical deposits and many others. Often treating fluids are injected down the annulus and allowed to flow back up the tubing. However, packer completed wells cannot be treated in this manner. In these wells, the treating fluid is often bull- headed into the well and can load the well and stop production. To alleviate this problem, a treating string is run into the well to allow regular or continuous circulation of treating fluids.

CTU allows installation of a treating string quickly, economically and with no loss of production or down time. CT as a treatment string permits injection up to one BPM & 5000 psi. Typical treating fluids are as follows: -

1. Fresh water to dissolve salt and to keep it in suspension.2. Methanol to avoid hydration problem in gas wells having combination of CO2, H2

S and free water.3. Water and inhibitor or diesel and inhibitor to protect the tubular from corrosion.4. Solvents or hot oil to keep paraffin deposits dissolved. 5. Acids to treat deposits such as salt of iron and calcium.

II) Gas Lift String

An oil-producing reservoir may have a decline in pressure to the extent that the hydrostatic weight of the produced oil overcomes the reservoir pressure. Increase in water cut will increase hydrostatic head & subsequently leads to ceasure of production. In all these cases, the gas lift can lighten the well bore fluids to the extent that they can be flowed to surface. CTU offers a fast and economical means of installing a gas lift system.There are many ways to set up gas lift system. Each system must be designed to operate effectively under the circumstances involved with a particular well. The well may require only single-point lifting or multi-point gas lifting. In multi-point gas lifting, ports are drilled in the coiled tubing walls. External valves may be affixed to the CT to promote fluid up the CT. The type of gas lift system needs to be designed and preparations to be made for its installations prior

to rig up the CT on the well. A CT string for gas lifting is very effective in evaluating the feasibility of a gas lift in a particular well. After evaluation, the CT can be retrieved. If the tubing is left in the well permanently, it is an effective and economical means of gas lifting a well.

III) Production siphon / velocity string

In depleted gas reservoirs with liquid production, the flow rates through the production tubing may not provide sufficient velocity to lift the produced fluids. In these wells, the produced fluid falls back and increase the flowing bottom-hole pressure, decreasing the flow rate and often building a hydrostatic head sufficient to kill the well. Manually unloading and/or soaping or swabbing are usually required to re-establish production. Higher velocities through the smaller ID coiled tubing/CT-Tbg annulus will continuously lift produced fluids and decrease the flowing bottom-hole pressure sometime allowing dramatic production rate increase.

To determine whether a well has been slugging or exhibiting a sharp decline in production rate might be a candidate for a siphon string, a computation should be made of the maximum pipe I.D. that will deliver the necessary velocity in gas to support continuous lifting of the produced fluids. Optimum CT size and depth can be determined through software (considering IPR and tubing performance curve) and economics may be worked out.

If the calculated maximum allowable I.D. is less than the I.D. of the present production tubing, the well may experience liquid loading problem and it can be alleviated by installing CT as siphon string. It is an intermediate step before installing artificial lift.

For installing the CT as permanent string requires special kind of tools like:

1. Tubing Hanger Spool : - This is available in various pressure rating and different flange connections to fit directly on existing X-mas tree. It houses the hanger packer assembly. These are basically of two types; one is to lower coil tubing in live wells and other one is to use in dead wells. Both are shown in the figures.

Fig. 8: Tubing Hanger

2. Hanger / Packer Assembly: - The hanger / packer assembly holds the coil tubing with the slips and isolate the coil tubing from coil tubing / production tubing annulus with the help of viton packer. The weight of tubing is taken by pack off packer. Hold down & hanger screws keep the coil tubing in the center.

Fig. 9: Hanger/ Packer Assembly

3. Pump -off Check Valve : - The pump-off check valve provides a convenient means of preventing back flow through the tubing and then removal, leaving a full opening for flow through the coil tubing. The removal is accomplished by pumping the trip ball down to seal and applying the required pressure. The number of brass shear screws adjusts shear pressure.

4. Back Pressure Valve: - By installing the back pressure valve nipple with valve in place, at the hang - off point, prior to starting the tubing installation, the tubing can be run under pressure with no fear of collapsing the coil tubing. After the tubing has been landed and the tree re-installed above the Tubing Hanger, the valve can be retrieved and the well resumes production. Should the coil tubing need be retrieved for any reason, the Back pressure Valve must be re-installed and the tubing can be pulled out.

5. Back Pressure Valve Retriever: - This removes back pressure valve from landing nipple under pressure.

6. Safety Clamp: - The safety clamp holds the coil tubing while inserting hanger/ packer assembly; to ensure safety of personnel working; in case slip ram or B.O.P. fails.

B.2. CT Conveyed Inflatable Packer

CT conveyed inflatable packers have increased the demand for CT services many fold. Some of the applications are:

1. To seal off water production or depleted zone2. For leak detection in tubing3. Acidising through a gravel pack screen – with straddle packer4. Seal off the top of a gravel pack5. Acidising beneath gas lift mandrels or tubing leaks6. Selective acidising of multiple zones7. Applications with velocity string

Among all these applications, selective acidization is the most popular in ONGC.

Fig.

10:

CT

conv

eyed

pac

ker

Fig. 11: Through tubing packer operation

Selective acidization:

To remove formation damage, acid spotting through CT is very common. But acid has a tendency to go into the path of least resistance i.e. with less skin or damage whereas the main

aim of acidization is to remove maximum formation damage. Hence for better control of acid job some diverter has to be used depending on completion type. Depending on completion types inflatable flow control devices or gas liquid emulsion can be used. Some common completion types are:

(a) Open hole completions: Offers minimum well-bore flow control. Irregular bore hole surfaces make running of CT and stimulation tools difficult. Inflatable packers or bridge plugs have been effective for zone isolation.

(b) Slotted liner completions: Offers no isolation between casing and bore hole. Fluidized diversion is recommended.

(c) Gravel pack completions: Also offers minimum flow controls of treatment fluid placement. Foamed diversion is often used.

(d) Perforated casing completions: Cement isolation is well suited for positive flow control with mechanical or fluidized diverter. CT conveyed packers (single or straddle) are used to acidize each of the perforations or part of the perforation selectively for best result.

B.3. Under reaming

Normally drill bits/milling tools are lowered with CT conveyed PD motors to drill within production tubing. With the development of CT under-reamer in 1990, many wells have been under-reamed eliminating the need of deployment of rigs. Cost saving is enormous when performed in offshore wells.

An under-reamer is a tool designed to pass through a restriction, open up below the restriction to clean the hole full gauge and then close up again to be retrieved from the hole. Most common application is removal of cement left from CT cement squeeze operations. It is also used to clean out scale and hard fill that can not be removed from liners by jet washing with CT nozzle.

Fig. 12: Under-reaming with coil tubing

Fig.13: Under-reamer

Some essential tools for under-reaming operation are:

(a) CT with sufficient torsional strength (size 1-1/2-in or more)(b) Connector with fishing neck(c) Two check valves(d) Hydraulic disconnect (e) Circulating sub (optional)(f) Down-hole motor having torque capacity compatible with CT(g) Under-reamer

B.4. FishingFishing is always known to be an uncertain job and time consuming. But even with its limited strength CT is quite popular to carry out fishing operation to fish out CT, CT conveyed tools, wire-line, lock mandrel stuck in profile nipples etc.

Advantages and limitations: -

CT has several distinct advantages. It offers additional tensile strength above that of braided line and the ability to use heavier tools is helpful in most applications. The capacity to circulate fluid through the system can also be helpful in some situations. Relatively low cost, quick rig up and fast trip time are advantages in certain applications.While CT has many advantages, it also has disadvantages when compared to conventional work over rigs. Relatively low tensile strength capacity restricts over pull and inability to rotate limits the use of bent subs, wall hooks and some types of releasing mechanisms that are incorporated

into conventional overshot and spears. CT is more expensive than braided line operations and cannot use spang jar as effectively due to limited running speed.

Actual well conditions and operational objectives determine whether coiled tubing fishing should be attempted. To properly evaluate a well as a candidate for CT fishing and make proper decisions during the operation, supervisors must fully understand the advantage, disadvantage, strengths and limitations of CT. They must also understand the many available tools and their appropriate applications. Using this knowledge, the chances of success can be evaluated against operational cost to determine if CT fishing should be attempted, continued, or if a work over rig should be used to complete the operation.

Early Coiled Tubing Fishing: -

When fishing with CT was first undertaken, specialty tools were not available. Overshot and spears used in wireline fishing operations were modified for use with CT tools. Hydraulic disconnects and other tools, which were designed for standard coiled tubing applications were also used for fishing.

These early operations met with some success, but the tools were not optimized for fishing applications. Overshot that could be shear released with wireline had no such flexibility when used with CT. Hydraulic disconnects that performed well in other applications had serious limitations when used with hydraulic jars. Additional or improved tools were needed to overcome these problems.

A range of CT fishing tools is now available in the market for the operator to choose from to suit the specific job requirements.

B.5. Coiled tubing job in Horizontal Well:

The technology of drilling deviated wells has improved to the stage where wells can be successfully drilled at angels up to 90° from vertical. Servicing of these wells with work over rigs is time consuming and quite costly when performed in offshore.

Now well servicing in high angle and horizontal well bore is no longer a problem due to availability of CT. It has the ability to push tools due to its rigidity.

Design for the conventional CT jobs when to be carried out in a well having more than 45° deviation or in a horizontal well is entirely different. As the CT enters deviated portion, axial friction/ compression force is generated on CT. Initially CT forms a sinusoidal mode then helical buckling mode. When CT is pushed further, it acts as a spring and fails only when flexibility is lost. Various software programs are available to analyze tubing force and critical buckling mode. Using different tools or chemicals operator's choice is to minimize the drag/ axial forces and perform the operation.

B.6. Logging and perforating:

Highly deviated extended-reach, horizontal and even inclining well bores are being used to meet the requirements of increasingly cost and environmental conscious oil and gas development efforts. High-angle holes have been drilled and completed effectively in sensitive areas, in zones with little vertical standoff from undesirable fluids, for increased production over conventional vertical wells and for many other reasons. These completion types have resulted in new logging and perforating challenges.

Wireline, the most common logging method, is not suitable for high-angle use since it relies on gravity to help convey tools to desired targets. When well deviation increases above 60o, the vertical gravity component is often too low to assure that tools will slide along the well bore, especially in high coefficient of friction environments. Mechanical problems such as rolled-over casing ledges or squeezed perforation cement nodes decrease the maximum hole angle in which wireline-conveyed tools can be used. Rollers or motivators may add an additional 10o of deviation to the functional range of wireline in optimum hole conditions, but about 70o is considered the upper limit for gravity conveyed systems.

Mud-pulse logging while drilling (LWD), drill string-conveyed logging and pump down stringer techniques are available options when drilling or work over rigs are available, but when a rig is not available or desirable, options are few. CT is currently the most flexible tool available to convey logging tools in high-angle wells.

Logging with coiled tubing (CTL) is outwardly simple, offering advantages that may, in some applications, not be available with other methods.(Fig. 35). There are, however, costly and potentially hazardous pitfalls if the technology is not used properly.

A Brief History

CT used to convey wireline tools is generally credited to Wilbur L. Daniel, U.S. patent 3,401,749, dated September 17, 1968. It was not until 1985, however that CT-wireline logging became a reality. The delay was due in part to generally poor CT performance and reliability in the 1960s. By the middle-to-late 1980s, confidence has increased to the point that operation such as cementing, under reaming and fishing with CT were becoming commonplace.

In 1985, CTL services were being pioneered independently in two areas for different reasons. One effort began in April in Alaska's North Slope and involved installing 1/4-in. 7-conductor wireline inside 11/4-in. OD by 0.095-in. WT coiled tubing. Wireline was installed by laying 15,450 ft. of CT along a reasonably straight pipeline access road with only a few doglegs and very little traffic. A 0.109-in. OD slickline was pumped through the CT using shop-fashioned swab cups and a stuffing box on one end of the tubing. The electric line reel was then attached to the distal end of the slickline. Combining pull from the electric line end of the CT successfully completed installation. Probably the most difficult task was backing the lowboy while reeling the coiled tubing-electric line (CTEL) up off the road. Although wireline installation was completed in August, the first logs

were not run until November 1985 when all the specialized peripheral equipment was available.

Concurrent with Alaskan efforts, another company developed a CT-conveyed system for logging horizontals and highly deviated wells. This effort culminated in the logging of a 600-ft horizontal section with a collar locator, gamma ray and acoustic cement bond tool in 1985. Since then, CT has been used to perform hundreds of logging and perforating jobs and is available throughout the world. It can now be manufactured with wireline installed, or arrangements can be made through tubing manufacturers to install electric line in existing CT reels.

Fig. 14: CT Logging

Advantages of Coiled tubing conveyed wireline operations

Convey tools over long distances in high-angle extended-reach and horizontal wells.

Allow for continuous movement. Convey tools through short sections of corkscrewed or twisted pipe. Introduce or reverse circulate fluid down hole Provide constant pressure control. Minimize the danger of being "blown up hole". Record data while drilling, stimulating or performing other tasks. Electric line remains inside the CT for higher reliability. Assist specialized applications, like bore hole seismic.

B.7. Sand control:

Sand production can severely impair well performance and profitability by damaging production equipment or by plugging well bore. Sand control in existing wells may be required because of inadequate initial completion design, re-completion to new intervals or changes in reservoir production characteristics. The most durable and reliable sand control is by conventional gravel packing, but in some cases, conventional packs may not be economical or feasible.

Improvements in CT technology and reliability have resulted in better application and increased acceptance of through tubing sand control. Concentric gravel packing and sand consolidation is being used more because of advances in equipment, services, down hole tools and fluids. Candidates for these techniques include conventional completions that begin producing sand and wells with gravel pack failures. Economical jobs have been performed successfully in several different well configurations. Some initially non-gravel packed wells are now being designed for possible through-tubing gravel packing, anticipating sand production later in the completion's producing life.

Candidate Selection

There are a number of different concentric sand control alternatives that can be performed using coiled tubing techniques without incurring the expenditure on a conventional gravel pack.

Through-tubing sand control is considered when:

- Harsh conditions or remote locations make it impractical to perform conventional, rig-supported gravel pack operations.

- Reserves will not pay out conventional gravel pack expense.- Multiple or thin zones cannot be gravel packed individually.- High-pressure formations require potentially damaging and expensive heavy

brines for well control.

Other factors to be considered include interval length expected or required production rates, water production and overall project costs and economics.

Mechanical Gravel Packs

Mechanical gravel packs are through tubing screens that can pass through minimum production tubing restrictions and be installed concentrically inside production casing. These small diameter conventional and pre-packed screens are now being manufactured with greater precision and higher quality than in the past. In addition, stronger materials, larger tube sizes, heavy-duty units capable of increased push or pull and better fluids are making concentric installations and pumping viscous slurries easier and more effective.There are two through-tubing mechanical gravel pack methods:

Over-the-top squeeze Wash down.

If properly placed, flow limitations should be about the same as for conventional packs.

Fig. 15: Over the Top Squeeze Pack

Fig. 16: Wash Down PackB.8. Spool able gas lift string:

With the development of CT technology, Spoolable gas lift strings are also available in the market. Depending on reservoir potential, gas lift valves are fitted within CT at a pre-determined length by the coil-tubing manufacturer and ready to install in a particular well.

B.9. Cleaning out flow lines:

It is just as important to keep the flow line operational and in good working order, as it is to keep the well bore in good condition. If the flow line from a well or a group of wells is plugged, the well or wells are off production. There are times that solid, paraffin, or other materials build up and completely shut off production through a flow line.

There are several ways of unplugging a flow line, probably the most common of which is to dig the line up, cut it and remove the material or replace that section which is plugged. This method is fine if the line is easily accessible. However, there are flow lines in places that would make removal very expensive and often impractical.

The CT unit offers an operator another way of unplugging this flow lines. Of course, there are some flow lines that have excessive bends and other physical shapes that would prohibit running the CT unit inside. The physical properties of the flow line such as size, number and degree of bends, and access to operating end must be considered when contemplating the use of CT for clean out. The radius of the bends should be at least three times the radius of the pipe. The total number of bends should not equal to or more than 90o.

The rig up of the injector head will usually be abnormal of conventional rig up. At times the head will have to be leaned at an angle or even laid on its side. Timbers or blocks may be needed to build up under and support the head. Care must be taken that the oil in the planetary and motor side of the head does not leak out the vents. Provisions may need to be made to run the vents upward. The head may be set upright if the operator is able to weld a riser pipe with a three-radius bend to the flow line. Tubing should be run with shoe to prevent the tubing and from hanging on welds.

Fig.

17

: Cle

anin

g ou

t flow

line

s

CT should be stopped every 200 feet and retrieved a few feet to check for drag. If the drag becomes excessive, the operator should be notified of this and the decision to run CT further should be his. The injector pressure required to push and pull the coiled tubing will be somewhat higher than when working in a well bore due to the friction of the CT laying horizontally. CT may be run to what ever length conditions will permit, but from previous experience about 5000 feet is maximum.

CTU allows flow lines to be cleaned that would otherwise have to be replaced. Circulation of any type fluid or gas can be performed through the coiled tubing so that almost any type of obstruction can be washed or dissolved from the flow line. The CT has also been used to remove stuck pigs from flow lines.

B.10. Drilling:

Drilling through CT is probably the fastest growing CT service in recent times. Coil tubing drilling (CTD) started in 1991 with 3 wells drilled (2 vertical, 1 directional), which grew to 410 wells in 1996 of which 100 vertical wells and 310 directional well.

Continuity of CT gives it several advantages over conventional drill strings like:

Drilling under balance safety Significantly reduced trip time Continuous circulation Smaller surface requirements

Current CT drilling operations has the following limitations:

Conventional rig assistance is required for well preparation though combo rigs are already being used.

Conventional rigs must assist in running long protective and production casing strings or liner.

Hole sizes are smaller. Working depth capabilities are shallower. Coiled tubing fatigue life is less.

Applications of Coiled Tubing Drilling

Drilling with CT may not replace drilling with conventional drill strings, however, it is well suited for many slim hole, and re-entry drilling applications. Potential applications of CTD, all of which can be performed under balanced, include:

Horizontal re-entries from existing vertical wells for increased well productivity and ultimate recovery.

Horizontal re-entries from existing vertical wells to mitigate water or gas coning. Horizontal re-entries from existing vertical wells to reconfigure drainage patterns

in water floods and EOR projects from radial to linear flow.

Horizontal re-entries from existing vertical well for exploration and formation evaluation purposes.

Directional re-entries from existing vertical wells to access bypassed reserves in heterogeneous reservoirs.

Deepening existing vertical wells. Lengthening existing horizontal wells, Re-entry drilling from existing horizontals wells to alter wellbore placement in

the reservoir. Vertical drilling in and below lost circulation zones. Expandable, slim-hole exploration wells. Slim-hole production wells.

Coiled tubing drilling can also be used in conjunction with conventional drilling operations for:

Drilling in or below lost circulation zones. Coring pay zones. Under-balance drilling of the pay zone.

In these applications a conventional rig would be used to drill most of the well and the CTU would be used to finish the hole.

Shallow vertical wells do not require sophisticated equipment hence use of CTU for vertical well is restricted to drill the pay zone under balance or extending the horizon. Whereas directional re-entries require window milling and directional control equipment which itself is very advance operation and CT is used to its true potential.