OTC-25767-MS

Conceptual Design for Offshore Pipeline Replacement in Mature Field, Using Reinforced Thermoplastic Pipe for CAPEX optimization in F-Field Pipeline Repair and Replacement Program Hanto Yananto, Pertamina Hulu Energi ONWJ, Yuyung Girindra, Pertamina Hulu Energi ONWJ, and Steven Kennedy, Polyflow Global

Copyright 2015, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 4–7 May 2015. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract A study was initiated to evaluate the benefit of low capital

cost and low maintenance cost technologies to rehabilitate

pipelines in marginal fields and apply artificial lift

solutions to marginal wells to keep them running profitably

and with an attractive return on investment (and with no

sacrifice to safety and environmental risks).

The challenge is to have a new technology with lower

“Total” cost from design, procurement, installation,

operation and maintenance during its life time. In addition,

the technology must meet the required planned production

flow, which, in some cases, can be higher than current

flow.

RTP per API15S was shown as the most cost effective

solution in rehabilitation of pipelines in marginal fields.

Introduction Offshore North West Java (ONWJ) field has been operated

for more than 40 year and comprises 9 flow-stations and

hundreds of NUI platforms. About 600 pipelines are used

for transporting either fluid or gas. At least 5 pipelines have

to be repaired or replaced due to integrity of aging

facilities. As a mature field, any additional Capex to

maintain base production shall be carefully assessed.

Figures 1 and 2 show examples of “F” field network.

Figure-1 Pipeline Network at F3-F2

Figure-2 Pipeline Network at FS1-FS231-F261

The objective of this paper is to evaluate and select the right

existing pipeline candidates that are suitable for pipe in

2 OTC-25767-MS

pipe pull through method. Success criteria include

acceptable hydraulics which meets line requirements, flow

velocity minimum performance to minimize maintenance

expenses, material selection to eliminate chemical

treatment and capital cost estimates to demonstrate a

beneficial return on investment to ONWJ.

Pipeline Replacement Strategy The replacement strategies followed by ONWJ are

according to the following steps, i.e.

- To utilize the existing pipeline casing as the conduit for

RTP flow line pull through method.

- RTP flow line will be pulled through from tie-in flange

below Emergency Shutdown (ESD) Valve at one

platform to the same elevation at another designated

platform.

- RTP diameters which meet the hydraulic method and do

not require a modification to existing riser bends are

preferable to those that require riser bends.

- Modifications to bend does not constitute a rejection of

the process. ROI analysis will determine if project is

viable.

- Total installation cost comparison will be generated to

compare technology options.

Design Scope The assessment effort was limited to a process that will

engage the lower hanger flange (just below the

Emergency Safety Valve) on one platform to the lower

hanger flange of the terminating platform, as in Figure 1

Figure 3. Design Scope

Appraise Stage In the appraise stage, several technology options were

considered to select the best option to maintain the

pipeline; API 17J Flexible Pipe and API 5S RTP with Pull-

Thru Installation method are the alternative options

compared to traditional rigid carbon steel pipeline..

Commercially Available Pipe Sizing The new pipeline will be designed to anticipate maximum

fluid or gas production from the existing platform. It is

essential to establish the right size of the pipe for current

and future operating requirements as proper pipe sizing can

minimize the ongoing maintenance by creating critical

velocities to move solids with the liquid flow stream.

One of the benefits of RTP and Flexible pipe systems are

their polymer liners which are smooth extruded surfaces

compared with carbon steel pipe. These smooth liner

surfaces reduce flowing pressure drop for comparable

diameters, thus allowing smaller diameter RTP to replace

larger diameter carbon steel pipe.

References have shown carbon steel to have a relative

roughness of ~ 0.006 in/in versus thermoplastic extruded

relative roughness of ~ 0.00005 in/in. This allows for

smaller diameter polymer lined pipes to create critical

minimum velocities to move solids while not creating

excessive pressure drop.

Modeling was performed to establish the desired diameter

using a polymer lined pipe. Table 1 summarizes the

comparison between new line size and commercially

available existing pipeline size for API 5S, API 17J and

steel pipe. Technical selection was later performed based

on market availability, material capabilities, practicality in

installation, pipeline size and length.

Table-1 Technical Selection Pipeline candidates in F-

Field

Installation Total Cost Comparison Table 2 shows an installation total cost comparison for the

various technologies assessed. The least cost total

installation cost technology) is RTP per API 15S. Flexible

pipe per API17J is more expensive and carbon steel per

API 5L the most expensive.

RTP (API15S) ~$2MM USD less than API 17J flexible

RTP (API15S) ~ $3-4MM USD less than carbon steel

Table-2 Price Comparison of Selected Pipelines in

F-Field

1 F2-FP 6" N/A 2.2 Y Y N/A

2 F3-F2 4" 12" 2.6 Y Y Y

3 F4-F3 6" N/A 0.9 Y Y N/A

4 FP-F62 8" 12" 8.8 Y N/A N/A

5 F62-FP 16" 12" 8.8 Y N/A N/A

6 F62-F3 12" 12" 8.8 Y N/A N/A

7 FS1-F62 16" 16" 8.9 Y N/A N/A

8 F62-FS1 6" 16" 8.9 Y Y Y

9 F11-F3 12" 6" 7.6 Y N/A N/A

10 FS231-FS1 10" 12" 2.6 Y Y N/A

11 FS1-FS231 4" 12" 2.6 Y Y Y

12 F261-FS231 8" 10" 4.4 Y Y N/A

13 FS231-F261 4" 10" 4.4 Y Y Y

14 H2651-F14P 10" 12" 13.1 Y N/A N/A

15 F231-sstH2651 8" 8" 0.2 Y Y N/A

16 F14P-FP 12" 16" 11 Y N/A N/A

Carbon Steel

API 5L

Flexible Pipe

API 17J

RTP

API 15SNo. Pipeline

Existing

Size

New

Size

Length

(KM)

OTC-25767-MS 3

Installation Schedule One additional advantage that flexible pipes have over

carbon steel pipes is in the duration of the installation.

Figure 4 shows a generic “pipe-in-pipe” installation

schedule for RTP per API 15S for pipeline lengths less than

5km.

Figure-4 Generic Installation Schedule

RTP per API15S was seen to offer the least cost total

rehabilitation solution and was then selected best return on

investment for use in marginal fields.

Following is a more detailed discussion of RTP

technology.

Selection of New Pipeline The new pipeline is proposed to be installed by using

Reinforce Thermoplastic Pipe (RTP). The general

construction of RTP piping system consists of an

internal liner and substructure (either Nylon or PPS) that

is wrapped externally by aramid fibre in order to

increase allowable pressure of polymer pipe.

The PPS liner is recommended due to its low permeation

rates for both CO2 and H2S gasses. The Fortron liner

has a relative roughness friction coefficient of 0.00005

in/in was used which approximately a hundred times less

than the value is used for steel pipe (0.006 in/in).

RTP line will be installed inside of existing carbon steel

pipeline using method called Pull Thru. The existing line

is currently no flow since the platform is inactive now.

The main concern of using this method is the capability

of existing bends in the steel in handling RTP inside

which depend on the size of the RTP used. Bend

modification, if required, will give impact to the ROI

calculation.

Material comparison of RTP and steel pipeline is shown

in Table 3.

Table 3 Material Comparison

Hydraulic simulation of the new pipeline comparing

RTP and carbon steel line is summarized in Table 4.

Table 4 Comparison of hydraulic simulation result using

RTP and Carbon Steel

As shown in Table 4, for 6 inch pipeline, generally RTP

and steel pipeline generate similar pressure drop (only

0.2 psi difference). For 4 inch, pressure drop along the

steel line is higher than pressure drop along RTP, as well

as for 3.5 inch. It shows that for small diameter, the RTP

will generate less pressure drop.

Still shown in Table 4, fluid velocity for RTP is quite

higher than steel line. It minimizes solid deposition as

long as it is still lower than erosional velocity. An

operational cost avoidance benefit of the higher velocity

is the possible elimination of pigging operations.

Another significant cost benefit for RTP is in the

installation process and associated cost. Steel line lay

process requires lay barge, possibly DP2 vessels, which

resulted in high cost installation. RTP system can use

small work barges and utility vessels to transport small

machinery and materials hence the installation cost will

be less expensive.

Table 5 shows options selection by comparing

advantage and disadvantage of various sizes and

material of pipeline.

Table 5 Option Selection

2 F3-F2 4 2.6 7.2 6.6 4

11 FS1-FS231 4 2.6 7.2 6.6 4

13 FS231-F261 4 4.4 10.08 7.7 5.76

Total 24.48 20.9 13.76

CARBON STEEL

API 5L

RTP

API15S

Estimate Cost

(USD x 106)

FLEXIBLE PIPE

API 17J

Estimate Cost

(USD x 106)

Estimate Cost

(USD x 106)

Length

(KM)No. Pipeline

Size

(Inch)

Day 1 Day2 Day3 Day 4 Day 5 Day 6 Day 7

Vessel Equipment Loading

Vessel Transit to location

Deoil

Scaffolding and Equipment Setup

Actual Lay

Hydro-test

On Production

Line Down x x x

Nominal Size Pipeline

Resulting Pressure Drop

(psi)

Landed Pressure (psi)

Velocity (ft/s)

Requirement for bend modification

6” RTP 3.6 671.4 8 Yes

6” Steel 3.4 671.6 5.5 -

4” RTP 24 651 18 No

4” Steel 26 649 12.8 -

3.5” RTP 48 627 24 No

3.5” Steel 50.1 624.9 16.3 -

4 OTC-25767-MS

Generally steel has proven reliability but the installation

cost is very high. On the other side, RTP installation and

operational costs are lower but reliability is unknown

since it has never been implemented on this field.

For similar size, RTP generate less pressure drop than

steel line. Due to that reason, RTP will be more efficient

to be implemented first time in the recommended

options since it is only for gas lift. Six (6) inch size will

be oversized considered the maximum rate is only 3.4

MMSCFD.

The allowable pressure drop along the line should be

about 10-20 psi/mile (6.2-12.4 psi/km). The 3.5” RTP

and steel is resulted in very high pressure drop (48 and

50.1 psi). The only option left is 4” which is technically

and commercially feasible since it is resulted lower

pressure drop (24 psi) and the cost is cheaper than

installing new steel line.

Bend Modification Implications An additional consideration in pipeline rehabilitation or

conversion of lines to gas lift etc. is whether the existing

bends in the steel casing need to be modified.

This is a critical cost impact item in the Return on

Investment (ROI) calculation – not as important when

production flow is sizeable but very critical for pipe-in-

pipe applications in marginal fields.

The recommended initial applications do not require

modification to existing bends.

RTP Pipeline Data The line pipe is described as Piping and associated Joining

System pulled inside the existing steel line pipe casing. In

combination, both systems provide a stable flow line

system for the transport of gas/crude or other products.

The existing carbon steel casing does not require the use of

anodes, cathodes or other corrosion inhibitors as a

requirement for further operation as the RTP pipe will

assume all the integrity requirements for flow. This can

result in a significant operation cost avoidance.

By nature, the piping system is inert to hydrocarbons;

except for flange and splice sections which can be coated

(inner tubular) with surface protectant; such as Fortron

Polylphenylene Sulphide (PPS) or other coating, prior to

installation.

Material Selection The RTP pipe evaluated was constructed with internal liner

of Fortron Polyphenylene Sulfide (PPS), reinforced with

aramid fibers and jacketed with Nylon (refer to Figure 5)

Figure 5: RTP Pipe Construction

The PPS liner was selected because of its resistance to

hydrocarbons and Brine, as well as CO2 and H2S. In

addition, PPS exhibits very low permeation rates for both

H2S and CO2 gas.

Permeation Permeation through the liner does not necessarily damage

the liner but rather can create operational issues such as

build up gas pressure in the reinforcement layer creating

issues with the outer jacket. In the case of the rehabilitation

of a carbon steel pipeline, a build up of gas in the annulus

between the RTP and the steel pipe can create non desirable

issues.

The Figure 6 is comparing various polymers permeation

rates in CO2 at various temperature to show a side by side

comparisons.

Figure 6 Comparison of Polymer Permeation Rates

Figure 6 shows that polyethylene, a common polymer used

in the oilfield has significant permeation rate compared to

No Option Advantage Disadvantage Cost (USD)

1A 6” Steel - Reliability is proven

- High installation

cost 7,200,000

1B 6” RTP - Low installation cost

- Unknown reliability

- Bend modification is needed

N/A

1C 6” Flexible

Pipe - Reliability is proven

- Low installation cost - Material is slightly

expensive 6,600,000

2A 4” Steel - Reliability is proven - High installation

cost N/A

2B 4” RTP

- Generate less pressure drop than steel line (for same size)

- Low installation cost - No need bend modification

- Pipeline repair if leak during operation

- Unknown reliability

4,000,000

3A 3.5” Steel - Reliability is proven

- High pressure drop

- High installation cost

N/A

3B 3.5” RTP

- Generate less pressure drop than steel line (for same size)

- Low installation cost

- No need bend modification

- Unknown reliability

N/A

OTC-25767-MS 5

the other engineering plastics and Fortron (PPS) showed

significantly lower levels of permeation.

No Venting Required

Safety is of critical concern for ONWJ. Therfore, it is

preferable to have a pipe-in-pipe system that does not

require venting of the annulus as a consequence of gas

permeation through the RTP wall into the annulus. This

criteria negated the use of polyethylene (PE) based liners

and materials.

PPS liners do not require venting of the annulus.

Typical RTP Installation Method The first step in installation is to disconnect the

terminations at the lower hanger flange as in Figure 7

(before the safety shut off valve). In some cases due to

limited space the safety valve and associated piping might

be removed to gain acceptable access for pull through.

Figure-7 Typical Lower Hanger Flange Access /

Disconnected Flange

Operational Pigging Philosophy

Once the lower hanger flanges are disconnected, a

gauging pig will be sent through the line with cable

attached to assure that the existing casing has an

acceptable size opening to accept the RTP.

For sending of the gauging/messenger pig, a compressor

is required.

The compressor will be integrated with a temporary

pigging joint “in-line”. Figure 8 gives a visual of this

connector type which is standard in industry. When

messenger process is complete this joint is removed.

The temporary pig launcher will have flange connection

to connect with existing terminations at the platform.

Figure-8 Messenger Pig

Pulling Method

A pulling cone is attached to the RTP pipe. The pulling

cone has holes that allow for water to fill the pipe as it is

pulled within the steel casing. The operator must use a light

weight, high strength rope for the messenger pig and pull

through operation.

A winch and rope should be capable of pulling with greater

than 2x the expected pulling force (which will provide the

operator with a suitable safety factor).

The pull through speed is expected to be 7-14 m/minute.

Speed is monitored via winch controller. A faster pulling

rate is possible when the size of the casing is much larger

than the RTP pipe.

As one RTP spool is completely unwound, the pull is

stopped, the existing empty spool removed and replaced

with a new spool in the unwinding station. Then a splice

coupling is used to join the two pipe sections and continue

spooling.

A custom designed 10,000 psi rated pump is required to

swage the couplings at joining locations. The final issue is

determining the end connections. When possible it is

recommended to flange to the existing steel flange

termination because as the RTP pipe is flexible,

terminating to a non-rigid structure can cause some issues

with excessive bending.

The pipe is then pulled past the lower flange hanger (~ 5-

10 m) and the pipe is cut near the lower flange.

The proprietary termination coupling is then added using

the hydraulic press. Terminations are provided that mate

to the existing flange structure. The termination flange is

then bolted to the lower hanger flange assembly to close

off the pipe in pipe system.

Pre-commissioning

6 OTC-25767-MS

The final installation process step is to hydro-test the line

to ensure splice and termination joint integrity. In general,

the installation contractor will follow the following

recommended hydro testing guidelines for RTP. Typically

the hydro-test is done at 1.5 x the “operating” pressure for

gas lines and 1.25x the operating pressure for liquid lines

of the line for an 8 hour period. However, there are a few

requirements from the RTP Supplier:

1. Pressures testing should be done with liquid (salt water

is acceptable).

2. The line should be increased in 250-500 psi increments

and held for ~15-20 minutes before increasing pressure,

thus allowing the pressure to stabilize. (There is some

stretching of the line and pressure drops can occur

during the pressurization of the line.)

3. Once the final pressure is achieved, there may be a few

recharges required during the pipe relaxation before the

pressure test hold procedures begin.

4. The pressure profile curve is asymptotic, so there may

be slight pressure decay for several hours before the

pressure stabilizes.

Conclusions During Appraise-Select Stage, 3 pipelines were proposed

to be replaced with RTP by pull through method as shown

in Table 6.

Table 6 Summary of RTP pipeline candidates

Pipeline

Section

Cost Subsea

Work

Pulling

Through*

F3-F2 $ 4 mio No < 1 day

FS1-FS231 $ 4 mio No < 1 day

FS231-F261 $ 5.76 No < 1 days

*) RTP pull-thru equal to sending the messenger wire up to

pulling thru the RTP.

The budget required for capital expenditure on those RTP

pipelines can be optimized to 56% of regular carbon steel

pipeline laying by pipe lay barge as shown on table 7.

Table 7 Summary of CAPEX optimization

Additional operation cost reductions can be acheived from

RTP systems by elimination of pigging operations and

chemical injections associated with carbon steel pipelines.

The following is the summary of selection RTP as the most

valuable for those 3 pipelines.

- Pulling Through method is the most valuable solution

for pipeline rehabilitation in marginal field where there

were suficient existing abandoned pipeline as casing for

RTP pipe.

- No subsea intervention, but might need subsea team

support to be standby during pigging.

- For the selected lines, the maximum size RTP

applicable for existing pipeline as casing without

modification is about 4”, All for gas lift.

Pipeline rehabilitation using RTP technology has the

potential to greatly impact the performance of marginal

fields. Rehabilitation of existing lines can realized ~56+%

less capital cost compared to an installation using

conventional carbon steel pipeline. Proper planning and

analysis of the pipeline to be rehabilitated shall be executed

at earlier stage to ensure smoother installation process and

better achievement to the project in term of schedule and

expenditure spending.

References - N/A

CAPEX

Optimization

2 F3-F2 4 2.6 7.2 4 56%

11 FS1-FS231 4 2.6 7.2 4 56%

13 FS231-F261 4 4.4 10.08 5.76 57%

Total 24.48 13.76 56%

Length

(KM)No. Pipeline

Size

(Inch)

Estimate Cost

(USD x 106)

RTP API15S

to CS API5L

CARBON STEEL

API 5L

RTP

API15S

Estimate Cost

(USD x 106)