Paper - Running Jointed Tubing With CTU v2

7/29/2019 Paper - Running Jointed Tubing With CTU v2

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Using Coiled Tubing Equipment to run complex Jointed Tubing velocity strings

Rignol, Krepa, Hogan, den Besten 1 SPE / ICoTA Aberdeen, November 2003

Abstract

The cost of remedial work on marginal gas

wells suffering from water unloadingproblems can be prohibitive, especially in

an offshore environment. The expected

financial return often does not justify the

rig costs associated with pulling and

running a new completion, while the

formation damage caused by many well-

killing methods can reduce the production

potential of already marginal wells.

A Coiled Tubing velocity string can often

prove a quick and cost-effective method ofassisting in water unloading. The ability to

work in live well conditions avoids

damaging the formation, making it an ideal

solution in many cases. However, the

limited lifespan of carbon steel strings in

corrosive environments calls for a different

solution. The next option is often to run

and hang off a chrome tubing string with a

snubbing unit, which makes running

corrosion-resistant tubing in live well

conditions possible. However, the highercosts and increased time associated with

a snubbing unit reduce its attractiveness.

The unconventional operational procedure

of running corrosion-resistant jointed

tubing with Coiled Tubing equipment has

been used on few occasions to combine

the benefits of Coiled Tubing and snubbing

interventions. Although generally

restricted to relatively short tailpipes, this

method has on occasion been extended torunning full velocity strings. The limited

Using Coiled Tubing Equipment to run complex Jointed

Tubing velocity strings

Joel RIGNOL, Total E&P Nederland

Jean Marc KREPA, Total E&P Nederland

Edward HOGAN, SPE, Schlumberger Oilfield Services

Hendri DEN BESTEN, Weatherford

Presented at the SPE/ICoTA 9th European Coiled Tubing and Well Intervention Round

Table 19 & 20 November 2003 - Aberdeen, Scotland

tensile load capacity of the externally

flush threads has limited the length of the

string in some cases.

A solution to this problem where a

complex string is run in two independent

sections has been applied in the field to

increase the total velocity string length to

4115m.

The paper discusses the design and

execution of the operation where Coiled

Tubing and jointed tubing were used as a

complex velocity string in order to restore

production on a gas well, while retaining the full functionality of the downhole safety

valve. Particular attention will be paid to

the design of the string, which had to be

tailored to remain within the operating

envelope of the externally flush thread.

Introduction

The gas well K6-DN2 was originally

completed with a tapered (5” x 4-½” x3-½”) 13% chrome production string in

1992 (Figure 1). The well produces from a

133 m perforated interval and a 400 m

horizontal 4-½” slotted liner. In latter

years, the well has commenced water

slugging and continuous gas production

has not been possible.

Using nodal analysis software, it had been

determined that stable production could be

regained by replacing the currentcompletion with a 2-3/8” production string.




Because the K6-DN satellite platform is

incapable of handling any operations other

than slickline and wireline, due to crane

and deck space limitations, the workover

operation had to wait until a drilling-rig

(jack up) was mobilized for a conventionalslot recovery/side track operation on the

offset well K6-DN4.

Design Criteria

In preliminary discussions between Total

E&P Nederland and Coiled Tubing Service

provider, Schlumberger Oilfield Services,

the following design parameters were

decided upon:

• The 2-3/8” tubing string must be

composed from a corrosion resistant

alloy to withstand the corrosive

wellbore environment encountered in

the K6 field (4% CO2

in gas composition

and bi-carbonates & chlorides in fluid

composition).

• The bottom of the CRA velocity string

must be located at approximately 4215

m (within the perforated interval 4168

m to 4301 m) which is 326 m below the

bottom of the existing 3-½” tailpipe.

• The 2-3/8” tubing string must be

suspended below the two existing SV-

LNs in order to maintain full integrity of

both the WRSV & TRSV devices.

• A lower section of 2” tubing would be

required to pass the 2.31” landing

nipple at the bottom of the existing

tailpipe• The re-completion with 2.3/8” tubing

had to be executed as a live well

intervention, to avoid unnecessary

formation damage of the depleted gas-

bearing formation.

While both Operator and Contractor had

experience in running and hanging off

Coiled Tubing velocity strings below the

DHSV in live interventions, the requirementfor a corrosion resistant alloy (CRA)

necessitated a different approach. While

previously, Total E&P Nederland had

turned to a hydraulic workover solution to

run jointed pipe recompletions, the use of

the hybrid Coiled Tubing unit was

preferable in this case for the followingreasons:

• difficulty in erecting HWO unit on

small rig floor

• longer rig up/rig down time for

HWO unit

• CTU on site after stimulation work

on newly drilled sidetrack

• lower overall cost

Design Proposal

Although the authors of this article have

significant experience in similar live well

velocity string re-completion projects

using both Coiled Tubing and hydraulic

work-over systems, the velocity string

project for well K6-DN2 was a more

challenging task than initially expected.

When the project was initiated, it wasconsidered by all parties involved to be a

relatively straightforward operation. The

objective was to recomplete a 5” Cr tubing

completion with a 2-3/8” CRA tubing

velocity string, which had to be suspended

in the first joint of 5”-15#/ft tubing (ID =

4.283”) below the existing SV-LN profiles

(minimum ID = 3.813”) (Figure 1). A Vam

FJL connection would be used, as it was

the only connection available on short

notice. Such re-completions are relatively

commonplace and thus no major

difficulties were expected.

However, when the K6-DN2 velocity string

concept was subjected to a closer look

several critical design limitations became

apparent. The following paragraphs will

describe the engineering solutions, which

were offered to complete the K6-DN2

velocity string design.





Completion Design & Hardware

Conventional downhole suspension

systems were not available as ‘off-the-

shelf’ equipment for the particular case of

the K6-DN2 recompletion. Conventionalmechanical slip type packers (Figure 2) or

hydro-mechanical packers (Figure 3),

which are able to pass through a 3.813” ID

seal bore, are designed for compatibility

with a 4-½” tubing joint. If these packer

sizes are used to set inside a 5” tubing

joint they will not provide enough positive

grip to support the velocity string weight

and the slips may be damaged due to over-

expansion.

When this became apparent, the idea of

suspending the velocity string inside the 5”

tubing was temporarily abandoned and the

existing well completion was reviewed to

identify an alternative suitable suspension

point.

From the existing 5” completion schematic

it could be seen that several restrictions

are present below the SV-LN that could

act as an alternative suspension point.However to maximize the internal diameter

of the 2.3/8” FJT velocity string, either the

5” x 4.1/2” cross-over @ 3162 m or the

3.125” QN LN @ 3177 m were identified to

provide a suitable landing collar spot. After

closer consideration, the selection was

made to design the velocity string around a

suspension in the QN-LN using an RNG

lock mandrel (Figure 4). This would offer

both a no-go type landing collar feature in

combination with an annular pack off.

However, after reviewing the 2-3/8” Vam

FJL connection strengths, it became

apparent that the compressive forces

exerted by the free-standing upper section

of the string would exceed the

compressive load capabilities for the

connections positioned just above the RNG

lock, if the tubing extended above 2500 m.

It was now clear that our working windowwas much more restricted than initially

thought. In fact, if a suitable hang off

system could not be designed to pass the

3.813” SV-LN and set inside the 5” tubing

joint below it, most likely only a tailpipe

extension with a short section of free

standing 2-3/8” FJT mounted above theRNG lock could be installed.

Nodal analysis was performed again at

this stage to evaluate if a 2-3/8” FJT

tailpipe extension with a short section of 2-

3/8” FJT positioned on top of the RNG lock

mandrel would enhance well production to

ensure that the re-completion project

remained a valuable project. This analysis

confirmed that if the top of the 2-3/8” FJT

tailpipe extension could be positioned atapproximately 2500 m, the installation of

only the 2-3/8” FJT tailpipe would be

beneficial for the well production

performance.

At the same time a supplier of thru-tubing

packers was requested to review the

possibility to design a custom build

retrievable packer (Cr13) to pass the 3.813”

SV-LN and set inside the 5” – 15 #/ft tubing

with a tensile load (>45000 lbs) & pressurerating (>100 bar) to suit this application.

As a packer setting mechanism, which is

not influenced by the carried tail pipe load,

is required, the proven PB packer design

was considered to provide a suitable

solution. Based on the design of a 3.67” OD

PB Packer, a proto-type 3.78” OD PB

packer for 5” – 15 #/ft and the associated

EH hydraulic setting tool were designed,

built and tested at the beginning of 2003.

The main feature for the prototype 3.78”

OD PB Packer was to overcome the

required extended slip reach. This was

achieved by designing a special slip

carrier in combination with an extended

stroke hydraulic setting tool.

After the proto type 3.78” OD PB Packer

system was build, it was subjected to the

following test procedure prior to allowingfield release :





• Set 3.78” OD PB Packer inside a 5” –

15#/ft casing joint using the custom

build 3.78” EH Setting Tool (Extended

Hydraulic setting tool).

• Heated up the system to 55 degC tosimulate well bore environment at

setting depth in well K6-DN2

(approximately 120 m).

• Apply 45000 lbs of tensile force on

3.78” OD PB Packer to simulate

tailpipe load (upper part of velocity

string).

• Apply 170 bar in the bottom annulus

along with the tail pipe load of 45000

lbs applied.• Release the 3.78” OD PB Packer using

the Retrieving Tool with 10000 lbs

straight pull.

• Allowed element to relax for 30

minutes.

• Retrieve the 3.78” OD PB Packer

through a 3.813” ID restriction with

approximately 1500 lbs overpull

During the initial test a few minor problemswere encountered. However these issues

were resolved and did not re-occur when

the actual 3.87” OD PB Packer (Cr13) was

tested at the end of February 2003.

The PB packer could not be used to

suspend the entire string as the weight of

the string would exceed the to the tensile

load capacity of the 2-3/8” VAM FJL

connection. However, now suspension

systems for both the lower string (RNGlock mandrel) and the upper string (3.78”

OD PB Packer) were available, a solution

to run a full 2-3/8” FJT velocity string was

available (Figure 5).

A conventional seal stinger & polished

bore receptacle (PBR) were selected, to

tie back the upper velocity string with the

lower velocity string to create a

continuous flow conduit.

Base Pipe Material

All tubing used for the velocity string

should be made from a CRA type material

(i.e. Cr13) to maximize the lifetimeexpectancy of the velocity string in the

corrosive well environment.

However 2” OD CRA Coiled Tubing was not

commercially available at the time of the

operation and 1.9” OD FJT Cr13 could not

be handled with conventional CT surface

equipment.

Therefore, it had to be accepted that a

short section of conventional 2” OD CT

(HS80CM) was made up to the bottom of a2.3/8” – Cr13 FJT velocity string using a

common type external CT connector in

order to extend the velocity string till the

middle of the perforations @ 4215 m.

Well Control Barriers

To allow the proposed two-stage velocity

string design to be deployed into a live

well, dual barrier systems needed to beavailable to allow each velocity string

section to be deployed against a positive

wellhead pressure.

The lower tailpipe, which was deployed

against full wellbore pressure, was

equipped with a commonly used double

barrier pump out plug (Figure 6).

After the lower tailpipe had been landed in

the QN-LN, the pressure above the doublepump out plug would be bled off, which

would allow the top string to be run into a

zero-pressure well.

However, in case the RNG lock packing did

not seal completely in the QN-LN seal

bore, a dual barrier system for the top

string was also required for contingency

purposes. It was requested to offer a

“non-debris” system to reduce operational

costs and avoid any risk of plugging the

lower tailpipe with expelled debris. The





most simple and reliable solution that

could be found was a “glass disk” sub

(Figure 7).

CT Running & Deployment Equipment

In rigless operations, the use of a CTU

injector head to run jointed tubing often

employs a basket constructed above the

injector head for making up the threaded

connection. In this basket, operators make

up the connections with the pipe tongs and

operate a gin pole winch assembly to raise

the next pipe.

In the case of K6-DN2, it was decided touse the advantage of the presence of the

rig to allow safer and more efficient

operations. This was done by placing the

injector head and pressure control

equipment below the rig floor and using

the rig floor for conventional tubular

running (Figures 8-11).

The stackup design criteria were:

• Sufficient riser length to deploy all

subassemblies• Hydraulic jacking frame for safe

subassembly deployment

• Minimum change of pressure

control equipment during change

from 2” to 2-3/8”

• Double barrier philosophy at all

times

A support frame structure incorporating

hydraulic jacking frame, generally used for

safe deployment of long BHAs in CoiledTubing land operations, was adapted for

use on an offshore platform. The 9.5 m

structure was built up on the weather deck

of the platform extending up into the BOP

deck of the rig, where the injector head

was placed on top of it, approximately 5 m

directly below the slip bowl on the rig floor

(Figure 9). This stackup enabled sufficient

riser length between the stripper and the

BOPs, which were rigged up directly on

the wellhead on the wellhead deck.

All subassemblies would be deployed by

breaking the riser at the platform weather

deck level and lifting the injector head/

riser with the hydraulic jacks in the

support frame legs. The subassemblies

could then be easily pulled up from theplatform weather or wellhead deck into the

riser before reconnecting and running-in-

hole.

The six ram BOP stack allowed the double

pressure barrier philosophy be maintained

at all times during the operation, while

avoiding changing the stackup between

running the 2” CT tailpipe and running the

2-3/8” Vam FJL. The configuration was (top

to bottom):• 4-1/16” 10k gate valve

• 2-3/8” Blind / Shear

• 2” Shear

• 2-3/8” Pipe/Slip

• 2-3/8” Pipe

• 2” Pipe/Slip

• 2” Pipe

One stage of the velocity string installation

would involve running the lower section of

the velocity string into the well with CoiledTubing, to hang it off in the QN nipple. In

order to allow this be carried out with

minimum time lost in rigging up and down

the CT equipment, it was decided to work

out a solution to allow Coiled Tubing be run

from the cantilever deck, while leaving the

injector head in position below the rig floor

on the support frames.

A special frame was constructed to house

the Coiled Tubing pipe straightener, onwhich the Coiled Tubing gooseneck can be

mounted (Figure 10). This frame could be

positioned on top of the slip bowl in the rig

floor, which was directly above the

injector head. The Coiled Tubing string

could be run over the gooseneck and

through the injector head in this fashion,

without a long rig up / rig down time. This

would effectively be a standard Coiled

Tubing operation with a 5 m gap between

the gooseneck and injector head.







release. Drop ball back up release

feature failed as drop ball hung up in

surface equipment and thus false

pressure indications were observed.

Fortunately, the rotational back up

release functioned correctly and therunning tool was released from the

packer. A post job inspection of the

EH setting tool did confirm proper tool

function but that shear rating of

screws installed did exceed the

theoretical shear value. This was due

to a mistake being made in the

surface area value used in the

hydraulic calculations. This error has

been corrected so it should not re-

occur in future operations.• To shear out the glass disk and double

pump out plugs an additional run with

a sealing snap latch assembly was

used. By using this sealing snap latch

assembly the pressure was

maintained inside the PB packer body

which did significantly reduce the

compressive peak load on the anchor

slips and the packer elements.

Conclusion :

A rig (jack up) mobilization only to

recomplete well K6DN2 would not have

been economical, however by utilizing a

rig that was in place on the same platform,

the K6DN2 recompletion as executed

became justifiable.

Thorough pre-job engineering & planning

from all parties involved made thisrecompletion operation, using a 2-3/8” FJT

velocity string in combination with a

unique deployment method, become a

valuable alternative to a conventional

work-over rig or hydraulic work-over

operation.

By using this innovative live well

intervention technique, an existing gas

well was re-completed with a smaller size

production string without inducing any

formation damage to the depleted gas-

bearing reservoir during any stage the

work-over operation.

Length limitations on the smaller velocity

string, which can either be dictated by

connection strength or tubing body tensilestrength, become less restricted if a

modular velocity string design is used.

This type of operations can be executed

more economically by taking the potential

velocity string requirement into account at

the initial well completion design stage. If

dedicated down hole suspension subs are

build in the initial completion, significant

cost reductions can be achieved in the

future as i.e. only a no-go sub might berequired instead of a packer.

Acknowledgements

The authors would like to sincerely thank

Total E&P Nederland B.V., The Hague,

Schlumberger Oilfield Services, and

Weatherford for permission to publish this

paper.

We would also like to thank all field

personnel involved in the planning and

execution of the K6-DN2 operation. Their

experience and professionalism was the

key to making this a safe and successful

operation.

Abbreviations used

“ = inch

Cr13 = Chrome 13CRA = corrosion resistant alloy

CO2

= carbon dioxide

FJT = Flush Jointed Tubing

HWO = Hydraulic work-over

m = meter

Nm3/day = normal cubic meter per day

PBR = Polished bore receptacle

SV-LN = safety valve landing nipple

WRSV = wireline retrievable safety valve

TRSV = tubing retrievable safety valve





Figure 1 – Existing Completion of K6-DN2





Figure 2 - Mechanical slip type packer

The Mechanical Packer is ideal for use on coiled tubing or conventional tubing in straight hole

or deviated well applications, where the tubing rotation required to actuate the packer is not

possible.

The Mechanical Packer is set and released by reciprocal motion of the tubing.

Features:

• Set and released by reciprocal motion of the tubing

• Drag spring design offers substantial increase in drag and strength

• Dual high performance packing elements

• Sealed J-Slot housing

• Increased tensile strength to accommodate heavier tailpipe loads

• Large bore mandrels

• Ideal for use on coiled tubing or conventional tubing

• Designed for setting below most common tubing size related LN restrictions. Figure 3 - Hydro-mechanical packer

Figure 4 – RNG Lock Mandrel

The Hydromechanical PB-Packer is the largest bore Retrievable Packer available.

The Packer is coiled tubing, slickline or E-line set and straight pull release.

Applications:

The PB Packer can be used in monobore wells for screen hang-offs, tailpipe extensions, or

multiple packers can be used to temporarily or permanently isolate a section of tubing or

casing.

Features:

• Large bore

• Coiled tubing, E-line, or slickline set

• Straight pull release

• 5,000 psi @275°F rated

• Short overall length

• Low force for shear release

• Designed for setting below most common tubing size related LN restrictions.

a). No-Go engages

b). Set dogs by slackingoff 5000 lb





Figure 5 – Two-stage velocity string solution for K6-DN2

680 m

650 m

385 m

125 mRKB

2525 mRKB

3202 mRKB

3855 mRKB

4240 mRKB

Retrievable Packer

2 3/8” VamFJL 13%Cr tubing

Glass disks (shear 3Kpsi)PBR stinger w/ OR w/o seals


RNG lock weight set


Connection CT toVamFJL joint

2” Coiled Tubing cs2 pump out subs

2400 m

1715 m





Figure 6 - Double Barrier Pump-Out Plug

Figure 7 - Glass disk sub





Figure 8 – Equipment Rig Up

Gooseneck and frameremoved for running

tubulars





Figure 9 – Support Frame Structure Figure 10 - Gooseneck

mounted on frame

Figure 11 – Running

Jointed Pipe on Rig Floor


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Paper - Running Jointed Tubing With CTU v2