Hydrotest Procedure for Pipeline

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KETAPANG PSC, EAST JAVA, INDONESIA

ONSHORE RECEIVING FACILITY (ORF)

HYDROTEST PROCEDURE FOR PIPELINE

PREPARED FOR

PC KETAPANG II LTD.

CLIENT

EPCC

CONTRACTOR

Job No. : QPCA00 Contract No. : 5600025662 Doc. No.:

Rev. Date Description By Chk. App. 11-BTORF-P-PRO-0003

A 24-Dec-13 Issued For Review ADR ABR / RZL WHY

Rev : A

PC Ketapang II Ltd. APPROVAL

Sign :

pt. RAGA PERKASA EKAGUNA

ENGINEERS & CONSTRUCTORS

CONSORTIUM

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REVISION LOG REGISTER

Revisions had been performed on following pages:

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1. INTRODUCTION

1.1 General

PC Ketapang II Ltd (PCK2L) plans to develop the Bukit Tua Field, in the Ketapang Block, East Java. Bukit Tua which is primarily an oil field but with significant associated gas, is located 35 km north of Madura Island and 110 km northeast of Gresik at a water depth of approximately 57 m.

Figure 1.1: Bukit Tua Field Location

The Preferred Development Option is a not-normally-manned Well Head Platform (WHP) which is tied back to a spread-moored Floating Production, Storage and Offloading (FPSO), anchored approximately 900 m from the WHP. The Full Well Stream (FWS) from the wells are separated into gas and liquid streams in the production separator on WHP. The gas and liquid are evacuated to the FPSO via two separate single phase 16” gas and 8” liquid infield flowlines. Associated gas is compressed and conditioned on the FPSO and exported via a 12” gas pipeline to WHP and there onwards via a 12” gas export pipelines to the Onshore Receiving Facilities (ORF) in Gresik. Oil is exported by tandem mooring from the FPSO whilst produced water is treated for overboard disposal.

The FPSO vessel, moorings, topsides and the flexible pipeline risers at the FPSO will be leased. FPSO-WHP interfaces shall include the flexible pipeline risers and radio telemetry link for data, telephone and remote monitoring and control of the WHP from FPSO.

The export gas shall be received at the ORF where final separation of condensed liquids shall take place before fiscal gas metering. The metered gas shall be routed to the sales gas delivery point outside plant battery limits.

1.2 Scope

This procedure cover minimum requirement for site hydrostatic test incoming pipeline onshore, Bukit Tua Development Project – Onshore Receiving Facilities (ORF).

1.3 Definition and Abbreviations

1.3.1 Definition

COMPANY : PC Ketapang II Limited (PCK2L), as the Project Developer and Operator of the facility/platform. CONTRACTOR : Consortium of PT Raga Perkasa Ekaguna – PT

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Krakatau Engineering, which carry out all or part of the detailed design, engineering, procurement, construction, and commissioning (EPCC) contract of the project. VENDOR : The Company that manufactures or supplies equipment

and services to perform duties specified by CONTRACTOR. “VENDOR” covers Manufacturers/Supplier/Sub-vendor.

1.4 Reference, Codes and Standard

The latest editions, as of the enquiry date, of the following Codes, Standards and Regulations (as far as they are applicable) are considered part of this specification and are to be used by VENDOR in their design, manufacturing and testing of the offered equipment or package. Where ‘in house’ standards have been developed or are based on recognised National, International or Industry Standards, these may be offered as an alternative, subject to review and approval by COMPANY.

The Codes, Standards and Regulations include but shall not be limited to the following:

1.4.1 National Laws and Standards

Local Rules, Acts and Regulations of Indonesia

Decree 84.k/38/DJM/1988 Guidelines and Procedures of Working Safety Inspection on Installation, Equipment and Engineering used in Natural Gas Mining and Geothermal Source Exploitation

Regulation

06P/0746/M.PE/1991 Safety Audit to Installation, Equipment and Technique used in Oil and Gas Mining and Geothermal Activities

Regulation

05/P/II/PERTAMB/1977

Obligation to Own Certificate of Construction Worthiness for Oil and Gas Platform in the Off-shore area

Regulation Number 11 Year

1979 Working Safety on Refinery and Processing Oil and Gas

1.4.2 Project Specification

11-BTORF-P-DSB-0001 Piping Design Basis

11-BTORF-P-SPC-0020 Piping Material Specification - ORF

1.4.3 Petronas Technical Standards

PTS 61.10.08.11 September 2009 Field inspection prior to commissioning of mechanical equipment

PTS 31.38.01.10 August 2011 Piping classes Basis of Design PTS 31.38.01.11 October 2011 Piping – General Requirements

PTS 31.38.01.15 January 2010 Piping classes – Exploration & Production – (Note 1)

PTS 31.38.01.21 August 2011 Compilation of a specification for piping systems

PTS 31.38.01.31 October 2011 Shop and Field Fabrication of steel piping PTS 31.40.10.19 January 2010 GRP Pipelines and Piping systems PTS 80.45.10.10 February 2010 Pressure Relief and flare system PTS 20.081 June 1993 Piping General requirements PTS 20.208

PTS 39.01.10.12

November 1995 December 2010

Painting protective coating and Linings for Offshore System

Selection of material for life cycle performance (EP) – Upstream Equipment

Note 1: For this project, the onshore receiving facility (ORF) shall be designed referring to this PTS, rather than the normally used PTS 31.38.01.12 Piping Classes – Refining & Chemical.

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1.4.4 International Codes and Standards American Petroleum Institute

API 5L Specification for Line Pipe

API 6D ISO 14313, Petroleum and Natural Gas Industries-Pipeline Transportation Systems-Pipeline Valves

API 1102 Recommended Practice for Liquid Petroleum Pipelines

API 1104 Standard for Field Welding of Pipelines/ Welding of Pipelines and related

API 1105 Construction Practices for Oil and Products Pipelines

American Society of Mechanical Engineers

ASME B31.8 Gas Transmission and Distribution Piping Systems

1.5 Conflict Requirements

In the event of any conflict between this Specification and any requirements of statutory and safety regulations, codes, standards and other documents, the most stringent shall prevail. The order of priority of documents shall be as follows:

 Indonesian Codes and Regulations  Project Specification and Datasheet  Petronas Technical Standard (PTS)

 Internationally recognized Codes and Standards

All apparent conflicts shall be reported to the Company in writing for resolution. The Company decision shall be final. In the case of conflict the more stringent requirement is govern.

2. HYDRO TESTING PROCEDURE

2.1 General Methodology

12” GAS EXPORT pipeline hydro test pressure is: 15MPa (2175.6psig); 1.5x design operating pressure. The pipeline will be hydro tested after completion and visual acceptance of the gauge plates from the pigging operation. Battery limit for the hydro testing will remain as per above; top of riser at BTJT-A platform to end of the onshore tie-in spool (between OIC and ORF EPCC as per drawing: ORF-U-00006 Revision 0).

CONTRACTOR intends to set up the hydro test equipment and pressurize up the pipeline from the ORF onshore tie-in spool location. Calibrated, pressure gauges and pressure/temperature recorder charts will be utilized to monitor the pipeline pressure and temperature. The pressure test will be using the same treated sea water solution as above. The pipeline will be pressurized to the require test pressure and the volume of air monitored during pressurization. The test system is then isolated and allowed to stabilize. Once the pressure has stabilized the hold period of 24 hours will commence.

The hydro test is deemed accepted when the following are achieved:  Air entrapped is less than 0.2% of volume

 No visible leaks is observed

 Pressure is not lower than 98% of test pressure during the 24 hours holding period  No unaccountable pressure changes are observed

The 12” Gas Export pipeline will be deemed mechanically complete and acceptable by COMPANY upon:  Visual inspection of the pipeline gauging plates, and approved when no significant defects are

found on at least one of gauging plates

 Hydrostatic Pressure Testing of pipeline has been satisfactorily completed for required 24 hours period

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The baseline survey by intelligent pig will be performed as per contract and the survey data provided as part of the pipeline as-built documentation.

The hydrostatic testing spread will be set up onshore at the ORF tie-in flange location.

Hydrostatic testing activities will be performed from onshore to top-of-riser at BTJT-A platform. A small suction feeder pump will be set up at the quayside near the existing pipe rack structure for supply to the high pressure positive displacement pump for performing the hydro test. The chemical injection skid will be transferred from the pigging vessel to onshore and set up accordingly.

Prior to pressurization, the pipeline will be topped up with water while the air being venting out from ¾” venting valve on the riser at BTJT-A. Once top up and venting of the pipeline is completed, the instrumentation shall be install to the test blind at onshore ORF tie-in flange.

During the pressurization, the following information shall be recorded and logged every 0.1MPa are increased intervals:

 Time

 Dead weight tester for the pipeline pressure (bar)  Volume pressurize (bar/liter)



Volume of chemical and Dye injected (m3_/liter)

The equipment for hydro test (location – Onshore Receiving Facility, landfall point) as below:  1 ea x diesel driven positive displacement HP pump (47GPM/10000psig)

 1 ea x air driven positive displacement HP pump  1 set x HP hoses complete with fittings for hydro testing

 1 set x HP Xmas tree assembly complete with valves and fittings  2 ea x Deadweight tester units

 4 ea x Pressure & Temperature Chart recorder units

2.2 Pressurization

Pressurization will be commence at rate of up to and exceeding 0.1MPa per minute from atmospheric to 3.1MPa (450psig) at which air entrapment calculation will be carried out. A pressure volume graph will be produced using the figures attained during pressurize to indicate the volume of entrapped air in the pipeline. Should the air content exceed the maximum allowable of 0.2% of the calculation pipeline volume, the pipeline shall be depressurized and all air fully vented. Pressurization shall recommence as before until acceptable air content is attained.

On acceptance of the air content, the pipeline will be further pressurize at rate of up to and not exceeding 0.5MPa per minute to 70% (10.5MPa) the pressurization shall be stopped to allow to stabilize and leak checked for minimum 3 hours and during the 3 hours stabiles prior the pipeline pressure shall be recorded interval 15 minutes.

Upon completion 3 hours stabilize at 70% (10.5MPa), pressurized shall be continued to 95% (14.25MPa) of test pressure, pressurization shall then continue to 100% (15MPa) of the test pressure at a diminishing rate down to approximately 0.001MPa per minute. Continue pressurizing the line to reach the test pressure (hydrostatic test pressure+0.2%; 15.03MPa). On reaching the nominated test pressure, the system will be allowed to stabilize.

Monitoring of the pipeline pressure during the stabilization period will be conducted using a calibrated dead weight tester (DWT) located onshore. The following information will be monitoring and logged at 15 minutes interval unit stabilization has occurred (i.e. Specified test pressure):

 Time

 Pipeline pressure

 Volume of water added (if any)  Ambient temperature

 Subsea temperature (temperature probe is located at onshore test point and offshore platform location)

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During the stabilization period, re-pressurization may be carried out should the pressure drop below the required test pressure. The volume of water added will be recorded. Leaks or other defects noted during the stabilization period shall be rectified. The section requiring rectification shall be depressurizing to a safe level prior to any repair activity.

2.3 Hold Period (The Pipeline Shall be Isolated from This Point Forward)

Once the pressure in the pipeline has stabilized, a hold period of twenty-four (24) hours shall commence. During the hold period, the following information shall be recorded and logged at thirty (30) minutes time intervals:  Time  Pipeline pressure  Ambient temperature  Subsea temperature 2.3.1 Acceptance Criteria

The pipeline hydrostatic test shall be considered complete when the following condition has been met after the hold period. The pipeline pressure shall not be fall below the required test pressure at any time during twenty four (24) hours holding period. All variation in test pressure shall be accounted for. The test period shall be extended if necessary to achieve these criteria.

Note:

1) Should the test hold period be extended, the hold period will be retrospectively selected where the pressure has maintained within the above criteria for a twenty-four (24) hours period with CSR approval

2) No visible leaks shall be present on observable section of the pipeline.

Should the system require to re-pressurization during the nominated hold period, owner/contractor’s consent will be obtained prior to re-pressurization. The hold period shall start from this point.

2.4 Depressurization

On completion and acceptance of hold period, the pipeline will be depressurized to atmospheric pressure from the double block and bleed (DBB) on the test blind. The rate of depressurization shall not exceed 0.1MPa per minute.

The pipeline pressure will be monitored and recorded during depressurization until the pipeline is fully depressurized.

On completion of pipeline depressurization, all logs and acceptance certificates shall be signed off by all relevant parties.

2.4.1 Preliminary Checks Preparation

STEP DESCRIPTION CONTRACTOR

1 All personal shall be attended the project safety induction PE/Sup 2 Prior to commencing any work, all items of plant and equipment shall be

checked for transit and lifting damage any incident of damage shall be reported to the field engineer of Superintendent immediately

PE/Sup

3 All item of plant and equipment requiring certificate shall be checked

against mobilization record PE/Sup

4 Verified that all certificates are valid and correct PE/Sup 5 Prior to commencing of the operation work the necessary work permits

shall be obtained. PTW shall be utilized PE/Sup

6 Lines and communication established and noted regarding persons in charge, contact name and telephone numbers for the safety and environmental consideration

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7 Provide confirmation that all NDT is complete and acceptable on both permanent and temporary facilities

PE/Sup

2.4.2 Equipment Set-Up and Layout

1 Confirm all the permits are in place and valid for the hydro test operation PE/Sup 2 Proceed toolbox meeting and JSA checked with all relevant parties and

any other site parties working in same area PE/Sup 3 The set-up of hydro test spread in the designated lay down of working

area

PE 4 Secure all the connection hoses with whip checks and line up the

system before hydro test operation to be commenced. Area to be barricade off at onshore and offshore platform location

PE/Sup

5 Secure the working area to post warning signs and erect bunting in

around safe working area PE/Tech

6 Check engine oil and radiator cooling levels Tech 7 The hydro test spread will be set up and function test on the working

boat before any operation to be commence

PE/Sup

2.4.3 Hydro Test Operation

1 Confirm that PTW are in place and valid for the hydro testing activity PE

2 HOLD POINT

Conduct toolbox talk onboard of barge and perform the JSA check with relevant parties and any other affected parties working in the same area, checks or test the communication in between both test ends. Two (2) personnel shall be on BTJT-A platform during test. MIGAS to be on site to witness test

PE

3 Confirm and witness of the test blind had been installed on top riser at BTJT-A and ORF tie-in flange onshore. All the fitting for venting, instrument point is position for the pipeline is in place. Provide records of bolt tensioning for review

PE

4 Confirm to post warning sign and barrier the safe working area before commence the hydro test operation at both ends. Danger zones shall be barricade off

PE

5 Rig up the 1” high pressure hose from the onshore hydro test spread to ORF test blind and connect to double block and bleed manifold on the test blind of the pipeline

Tech/Rigger

6 Confirm the instrument of hydro test operation is install as per listed and drawing:

 Dead weight tester  Pressure Recorder  Pressure Gauge

 Ambient temperature recorder  Sea Bed Temperature probe

PE

7 Confirm to receiving site that the instrument are installed:  Pressure Recorder

 Pressure Gauge  Ambient Temperature  Sea Bed Temperature Probe

PE

8 Prior to commence of the hydro test operation, prepare the following logs:

 Pressurize Report

 Acceptance Air Conclusion Certificate  Stabilization Log

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 Hydro Test Report

9 Request permission from COMPANY to commence the hydro test operation for the pipeline and confirmation that all parties have reviewed the approved pre-commissioning procedure

PE

10 On the permission from COMPANY to commence hydro test operation for the pipeline. Make announcement to all platform personnel at both ends

PE

11 Once confirmation from receiving site of the venting point has already opened. Open the double block isolate valve at the test blind at onshore side

PE

12 Start the pressurizing pump as minimum RPM to top up the pipelines PE 13 Continued to pumping water into the pipeline as minimum RPM of the

pressurizing pump PE/Tech

14 Once water is seen discharging on the receiving end, start to open the venting point at the test blind, continued venting the water out for 10 to 20 minutes till solid water is confirm coming out on both of pipeline. Pressure release hose/drain line shall be located at +2m to +4m elevation

PE/Tech

15 Once the water is coming out is a constant stream, close the venting point valve for both site of the riser, continued pumping water into the pipeline till pressure reach 0.05MPa. Volume pumping from 0MPa shall be noted down

PE/Tech

16 Once pipeline pressure 0.05MPa, stop the pressurizing pump and close

the double block isolate valve on the injection manifold PE/Tech

17 Plug off the vent point at each riser PE/Tech

18 Re-confirm to receiving site that the pipeline is plug off and working area is safe to commence hydro testing operation

PE/Tech 19 Install the chart paper of the pressure recorder and ambient temperature

recorder at launcher site.

Note: Chart shall be signed by COMPANY and Regular Body Inspector (MIGAS), not the code on the chart

CSR/PE/MIGAS

20 Confirm with receiving site that pressure gauge, temperature probe and ambient temperature are installed

PE/Tech 21 Once confirm the working area at launcher site is safe to commence the

hydro test, open the double block isolation valve on the test blind at ORF side

PE/Tech

22 Reset the flow meter, and start the pressurizing pump PE/Tech 23 Monitor and logging the pressure and flow read of the pump and

increase the flow as required slowly. Prior to commence pressurizing the pipeline shall follow logs:

 Time

 Pipeline Pressure  Volume pumping

 Ambient Temperature recorder  Sea Bed Temperature probe

PE/Tech

24 Pressurize rate shall be 0.1MPa per minute till reach 20% of the test

pressure PE/Tech

25 Once reach 20% of test pressure, slowly decrease the pressurizing pump and turn off the pressurizing pump. Allowed for 30 minutes stabilization

PE/Tech

26 Once the pressurizing pump has been stop, close the double block isolate valve on the injection manifold on the test blind at ORF

PE/Tech 27 Engineer or test supervisor shall calculate the air inclusion of the

pipeline, acceptance criteria 0.2% of air content for each pipeline PE/Tech 28 Check for leak around the launcher and receiving site during this time, if

any leak found for any site of the riser shall be report to the test supervisor or test engineer

PE/Tech

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the leak

30 Once the leak has been repaired. To re-pressurize the pipeline, shall be follow on step 18 to 28

PE/Tech 31 Once 30 minutes prior of stabilization complete and no leak has found,

continued pressurization up to 70% of test pressure PE/Tech 32 Open the double block isolate valve on test blind and start the

pressurizing pump PE/Tech

33 Continued commencing pressurizing to the pipeline and increase the rate as 1barg per minute till 70% of test pressure, prior to commence shall be following by the logs

 Pressurizing log  Volume pumping log

PE/Tech

34 Once pressure reach 70% of test pressure, decrease the pressurizing

pump and turn off the pressurizing pump PE/Tech

35 Once the pressurizing stop, close the double block isolate valve on the

injection manifold of the pipeline. Check for leak regularly. PE/Tech 36 Stabilization prior will take 4 hours approximately: during that prior

logging at ORF will be taken interval 15 minutes following by:  Time

 Pressure reading  Ambient temperature  Subsea temperature

PE/Tech

37 Once stabilization has completed continue to commence the

pressurizing for the pipeline PE/Tech

38 Open the double block isolate valve PE/Tech

39 Started the pressurizing pump, and increase the volume as per require. Note: During this state of pressurization from 70% to 100% of test pressure, pressurization rate of 0.1MPa per minute till 100% test pressure

PE/Tech

40 Once the pressure reach at 100% test pressure (15MPa), pressurizing

pump will be stop and close the double block isolate valve PE/Tech 41 Final physical leak check for the launcher and receiver site of the

pipeline PE/Tech

42 Once confirm no leak is detected for the both site of launcher and receiver. Carry on stabilization of the pressure for 4 hours

PE/Tech 43 Once stabilization is completed, continues to change the pressure chart

of the pressure recorder and temperature recorder and confirm that the chart has been signed

PE/Tech

44 Commence 24 hours hydro test period.

During the test hold period, pipeline shall be tested and monitored. During this period, following logs shall be taken for pipeline:

Pipeline pressure by:  Dead weight tester  Pressure chart recorder  Pressure gauge

Temperature by:

 Ambient temperature (recorder)  Subsea temperature

PE/Tech

45 Once the test hold period for pipeline is completed, pressure shall not drop down more than 0.4MPa per 1ºC after acceptance criteria calculation temperature change

PE/Tech

46 Engineer or test supervisor shall be calculated the temperature vs. pressure for acceptance criteria

PE/Tech 47 Inform all witness parties and if the test is accepted by MIGAS and

COMPANY, the pipeline shall to depressurized as 0.1MPa per min down to 0MPa (atmospheric)

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48 Once the test of the pipeline has been completed, the chart shall be signed follow by the acceptance Certificate and logs:

 Pipeline hydro test certificate  Hydro test Report

 Chart Paper of Temperature  Chart paper of Pipeline Pressure

Hydrotest Procedure for Pipeline

KETAPANG PSC, EAST JAVA, INDONESIA