UNIVERSITY OF TRINIDAD & TOBAGOUNIVERSITY OF TRINIDAD & TOBAGO

BASc. PETROLEUM ENGINEERINGBASc. PETROLEUM ENGINEERING

GROUP MEMBERS:GROUP MEMBERS:

Cedric Kimloaz……………………107000908Cedric Kimloaz……………………107000908 Teri-Ann Sobrien………………….109002266 Teri-Ann Sobrien………………….109002266

COURSE NAME:COURSE NAME:

INTRODUCTION TO PETROLEUM ENGINEERINGINTRODUCTION TO PETROLEUM ENGINEERING

COURSE CODE: COURSE CODE: PENG210BPENG210B

TOPIC: TOPIC: COILED TUBINGCOILED TUBING

DATE SUBMITTED:DATE SUBMITTED: 2525thth November, 2008. November, 2008.

INTRODUCTION

What is the subject?

Three basic techniques are commonly used in today’s industry for running or pulling

tubing under pressure.

They are:

The Conventional or Rig-assisted method – uses rig power and a system of

cables, sheaves, and balance weights to pull or run pipe into the wellbore.

Hydraulic cylinder systems – commonly called hydraulic workover units or

snubbing units. It involves the use of a hydraulic jack and double BOP system

to pull tubing strings in single lengths under pressure.

Continuous or Coiled Tubing – uses a continuous length of tubing having no

joints, stored on a reel. The tubing is run or pulled from the well by means of a

continuous motion device, and continuous circulation of fluids is possible

from the time of initial entry into well. It should be mentioned that while

coiled tubing can be run into the well against pressure; which is cited a key

advantage; its usage is not limited to only this condition. It can also perform

many well operations faster than other rig systems when the well is dead (i.e.

hydrostatic pressure of liquid column > formation pressure). It can also

perform these operations without having to remove the Christmas tree.

Although coiled tubing has been in use for some time in oil and gas well

operations, it is a relatively new type of well servicing equipment.

COILED TUBING UNIT DESIGN & PRINCIPLE OF OPERATION

Basically the coiled tubing unit consists of continuous metal pipe coiled up on a reel.

The pipe, usually with its end equipped with a check valve; is manoeuvred via an

injector head through a safety system.

The basic coiled tubing unit components are as follows:

Chain-driven injector head assembly

Coiled tubing reel

Safety assembly

Ancillary surface equipment: includes a self-contained hydraulic crane, power

pack, and control console or cab.

Tubing Injector Head Assembly

The injector head assembly uses a friction drive system actuated hydraulically and

designed with a tractor type chain assembly with segmented type gripping dies that

provides an almost 360º grip contact with the OD of the tubing.

The assembly is designed to perform three basic functions:

Provide the thrust needed to push/snub tubing into the well against pressure.

Control the rate of tubing entry into the well.

Support the full suspended tubing weight.

The injector head assembly often consists of the following subassemblies:

1) Tubing guide – this is commonly called the goose neck, and it guides the

tubing as it leaves the reel and enters the straightener.

2) Tubing straightener – straightens the curved tubing to be driven into the

well.

3) Depthometer – measures length of tubing run into well.

4) Load indicator – monitors weight exerted by the fully suspended tubing.

5) Skid and four legged variable support structure – supports the weight of

the injector head assembly as it is mounted onto the wellhead.

Coiled Tubing Reel Assembly

It is used to store, transport, and spool the continuous tubing. The reel rotation is

controlled by a hydraulic motor that is mounted for direct drive on the reel shaft or

operated by a chain and sprocket assembly. The motor is used to maintain a constant

pull on the tubing and keep the pipe wrapped tightly on the reel. The tubing is guided

onto the spool through a mechanism called the “level-wind assembly” to properly

align the pipe as it wrapped onto or spooled off the reel.

Safety Assembly

The assembly consists of a stripper that provides a seal in the dynamic phases and a

stack of ram-type BOPs that fulfils the safety function in the static phases. The

stripper is located above the BOPs, and the sealing element is hydraulically actuated.

The four BOP compartments are equipped (from top to bottom) with:

a. Blind rams – isolates wellbore without tubing.

b. Tubing shear rams – isolates wellbore and cuts the tubing.

c. Slip rams – supports the weight of cut tubing and prevents it from falling into

wellbore.

d. Pipe rams – closes off the annular space between wellbore and tubing.

Ancillary surface equipment

Other equipment is required such as:

Hydraulic crane with collapsible boom or hydraulically actuated mast.

A power pack with diesel engine.

Adjustable height control cab.

Nitrogen unit if needed.

APPLICATIONS OF COILED TUBING UNITS

Coiled tubing units are utilized in practically all through-tubing well servicing

operations that require a circulating path. It can also be used for lightweight drilling,

and has recently been used to assist in well logging and production operations.

Common applications of Coiled Tubing Units:

Reducing hydrostatic pressure prior to under-balanced perforating.

Kick off a flowing well after a stimulation job.

Figure 1: Diagram showing the basic components of a typical Coiled Tubing Unit

Implement temporary gas lift.

Sand and Solids washing – most common coiled tubing workover services.

Acidizing, hydraulic fracturing, and other stimulations.

Well control – injection of a killing fluid.

Squeeze and Plug-back cementing.

Clean out hard fill and scale, with a jetting tool or drill bit with a hydraulic

motor.

Lightweight drilling out of cement plugs etc.

Perform some fishing jobs using an overshot.

Deepening or making a horizontal drain in a conventional well.

Unloading wells with lighter fluids such as natural gas.

Foam Cleanout.

Assist in Logging and Perforating.

Installed Production Strings and Velocity Strings.

Clean Out and Reworking of Pipelines.

Sand and Solids Washing

The coiled tubing is run into wellbore to the hold-up depth, and the treating fluid is

pumped down the tubing, and the sand and fluid returns are circulated through the

tubing-wellbore annulus. The check valve at the bottom of the coiled tubing prevents

the return of sand up the tubing. A flow tee located directly below the BOP stack

directs returns out of the well. Coiled tubing should not remain stationary for longer

than half the time required for circulating bottoms-up, and the pumps should never be

shut down until coiled tubing is out of the well.

Foam Cleanout

This is a concentric tubing cleanout where foam is used as the circulating fluid instead

of LSW. It has proved to be highly useful in low pressure formations where the

flowing bottom-hole pressure (FBHP) is insufficient to support a column of fluid

commonly used for cleanout. It is also more effective in removing sand since it has a

greater carrying capacity than conventional workover fluids due to its lower density.

Foam cleanouts are also advantageous in wells where the size of the annular space

causes insufficient velocity for removing solids. Foam quality capable of suspending

pebble-size solids is obtainable with the use of a foam generation chamber along with

a source of high pressure gas.

Unloading Wells with Lighter Fluids

Initiating flow in a dead well involves reducing the pressure in the tubing to a value

less than the formation pressure. This can be achieved by injecting and circulating

low-density gas into the fluid in the tubing. The gas which is usually nitrogen can be

pumped down the coiled tubing and up the annulus to allow the well to flow.

Cleanout and Reworking of Pipelines

Coiled tubing can be used to clean out sand, paraffin, scale or other debris in

horizontal pipelines. Also, when a pipeline has deteriorated to the point that repairs is

uneconomical; a smaller coiled tubing flowline can be run inside to become a “liner”

in the old pipeline.

Advantages of Coiled Tubing Operations:

Less time consuming and more economical – requires less rig time since there

are no pipe lengths to be made-up.

Can be run into a live well without having to remove the Christmas tree.

Lightweight, compact, portable, and hence requires little space on offshore

platforms.

Requires only 2-3 specialized workers, while conventional rig-methods

require in excess of 4 workers. This is important when offshore living quarters

are limited.

The injector head assembly is capable of running tubing in excess of 200

ft/min, whereas 30 ft/min is fast for jointed tubing.

Having no connections reduces the risk of potential leaks.

No clearance problems which are common at couplings due to increase in OD.

No kill fluid required. This reduces cost as well as the risk of formation

damage.

Has a higher tensile strength that wireline, and as such heavier tools can be run

when logging or fishing.

Compatible with most artificial lift methods.

Limitations of Coiled Tubing Operations:

Relatively low tensile strength capacity restricts overpull.

Inability to rotate limits the use of bent subs, wall hooks, and some types of

releasing mechanisms that are incorporated into conventional overshots and

spears.

More expensive than wireline operations.

It is not as flexible as wireline.

Reverse circulation is limited due to low collapse pressures when the pipe is in

tension in a deep well with considerable friction.

RECENT ADVANCES IN COILED TUBING TECHNOLOGY

Advanced-Composite Spoolable Tubing

It offers new solutions to many changing oilfield operations. The key attributes:

Excellent corrosion resistance

Low material density

High working-pressure rating

Extensive fatigue resistance;

makes it attractive for a number of oilfield tubular applications, including well-

servicing strings and corrosion-resistant completion strings.

REFERENCES

H. Cholet, Ed., Well Production Practical Handbook, Institut Français Du

Pe`trole Publications.

D. Perrin, Well Servicing and Workover.