feed checking

FEED Integrity Checks

AIMS-PI-PROC-0408 Rev 1

Custodian: Team Leader - Pipeline Integrity

Issued by: Team Leader - Pipeline Integrity

Date: 24th May 2010

Revision History

Rev Date Description By Reviewed Approved

a 27-03-08 Draft RSt RSh RSt

b 26-09-08 Issued for Review RSt RMac RSt

0 28-10-08 Issued for Use RSt RMac RSt

1 24-05-10 Re-Issued for Use RSt BG GC

Asset Integrity Management System - Onshore Pipelines FEED Integrity Checks AIMS-PI-PROC-0408 Rev 1

Uncontrolled Copy When Printed Page 2 of 15

Table of Contents:

1 Purpose ....................................................................................................... 3

2 Scope ........................................................................................................... 3

3 Definitions ................................................................................................... 3

4 Responsibilities .......................................................................................... 3

5 Procedure .................................................................................................... 4

6 References ................................................................................................ 12

7 Appendix A - Pipeline Integrity FEED Review Checklist ....................... 14

8 Appendix B - FEED Checks Sheet ........................................................... 15



1 Purpose This procedure defines checks to be carried out on flowline FEED documents with respect to the integrity management of the flowlines during their operational phase.

2 Scope This procedure applies to predominantly gas flowline designs including the lease spool connecting the wellhead to the flowline. The application of this procedure to oil flowlines is minimal. Aspects of this procedure may also be applied to more significant pipelines FEED, but the review of the design for these types of lines should be more rigorous due to their increased importance.

3 Definitions

API American Petroleum Institute

CAPEX Capital Expenditure

CO2 Carbon Dioxide

ER Electrical Resistance (Corrosion Probe)

FEED Front End Engineering & Design

H2S Hydrogen Sulphide

ILI In-Line Inspection

MAOP Maximum Allowable Operating Pressure

MIC Microbiologically Influenced Corrosion

OPEX Operating Expenditure

P&ID Process & Instrumentation Diagram

PAMS Pipeline Asset Management Services (Contractor)

PIP Project Initiation Package

PSV Pressure Safety Valve

ROC Remote Operations Controllers

RP Recommended Practice

RTU Remote Terminal Unit

4 Responsibilities

Role Responsibilities

Connections Engineer Preparation of the FEED document prior to installation of the facilities according to applicable Santos Facility Engineering Standards.

Pipeline Integrity Engineer

Review and acceptance / rejection of the FEED package as suitable for the ongoing integrity of the flowline during its operational phase.

Team Leader Pipeline Integrity

Arbitration between Connections Group and Pipeline Integrity Group where issues are identified in the FEED that have not been sufficiently considered / documented.



5 Procedure The primary concern of the Pipeline Integrity Group with respect to reviewing flowline FEED packages is to ensure the corrosion and / or erosion protection considerations are adequate to enable the flowline to survive its design life with minimal risk of failure, and without requiring excessive resources to manage ongoing integrity.

It is the designers responsibility to consider how threats will affect the flowline during its life and select appropriate materials / sizes / mitigation to minimise the likelihood of failure through known deterioration mechanisms. Santos has a relatively high failure rate for flowline connections predominantly due to inadequate mitigation of internal (and some external) corrosion deterioration. If adequate mitigation is not considered at the FEED stage, significant Operating Expenditure (OPEX) can be consumed trying to maintain flowline operation, where better Capital Expenditure (CAPEX) decisions may have prevented this.

The main threat mechanisms to the integrity of the wellhead connection arrangement are described in general terms in the Pipeline Corrosion Management Strategy1 along with methods for monitoring, mitigation and inspection, and are summarised here to aid further discussion:

Acid Gas Corrosion - combination of liquid water, CO2 and / or H2S gas leading to an acidic solution which attacks carbon steel causing pitting and general wall thinning

Erosion - mechanical impingement by liquid and / or solid particles leading to general wall thinning

External Corrosion - deterioration due to acidic conditions in surrounding soil coming into contact with pipe wall, again liquid water must be present for this to occur

These deterioration mechanisms must be considered and documented in the FEED package to demonstrate pipeline integrity will not be compromised during the proposed design life of the flowline. As per the Santos Design Guide2, the FEED package must contain a section on:

Flowline connection considerations re. erosion, corrosion, velocity limits etc. for o Wellhead spooling o Flowline(s)

The rest of this procedure will describe the checks that the Pipeline Integrity Engineer shall make to ensure the threat mechanisms have been adequately considered.

1 Pipeline Corrosion Management Strategy, Santos Document Ref: AIMS-PI-PROC-0002 2 Design Guide for Gas Wellhead Connection Design, Santos Document Ref: 1515-10-G005



5.1 Velocity Limit Considerations Fluid velocity influences both internal corrosion and erosion threats so velocity limit considerations shall be discussed prior to the specific threat checks themselves. The guidance provided by API-RP-14E should be followed; however, the FEED must include velocity checks for all components in the connection design and not just the 1 spool, i.e. accounting for the different materials selected and dimensions of pipework. For example the following velocity checks have been carried out using Raven #1 data:

Table 1 - Sample Raven #1 Original Connection Velocity Checks

Component Material API-RP-14E C Value Limiting

Velocity (m/s) Actual Velocity

(m/s) Pass / Fail

Check

NB 80 1 Spool Duplex 200 20.55 12.38 Pass

NB 80 Choke Valve Duplex 200 20.55 12.38 Pass

NB 100 2 Spool Carbon Steel 150 (100) 15.41 (10.27) 7.11 Pass





NB 150 Flowline Carbon Steel 150 (100) 15.41 (10.27) 2.63 Pass Note: The values calculated assume no solids in the gas stream. Bracketed values are for no inhibition.

All the components in Table 1 appear to pass the velocity checks; however, it should be noted that the orifice in the choke valve may be significantly smaller than its nominal bore, which in turn means that fluid velocities experienced at the outlet of the choke orifice will be much higher. For example, a choke orifice of 50% nominal bore leads to velocities in the order of 49.52 m/s, which would significantly exceed the velocity limit determined using the API-RP-14E guidance, even for a corrosion resistant material such as duplex stainless steel.

Velocity limits may be exceeded by a small margin for short periods of the wells life. In such cases, it is the designers responsibility to establish how this shall be monitored and to establish what happens when this excursion occurs for longer than anticipated.

As well as demonstrating that the velocity checks have been carried out using pipework nominal bore values, the FEED must also consider alternative scenarios as discussed previously (i.e. choke example) and should examine what happens when corrosion inhibitor mitigation fails3 and / or solids are present4. This will provide additional justification for improved well testing, sand monitoring and the monitoring of inhibitor injection reliability, which will be discussed further in the following sections.

Where new flowlines are connected to existing pipelines, the capacity of the existing pipelines should be checked to ensure there is sufficient capacity for the new flowlines fluid flow i.e. the combined fluid flow does not exceed the allowable velocities in all sections of the downstream network.

Where the FEED has not documented that all the components in the connection have had velocity checks carried out, or does not consider the effects of inhibitor failure or solids production, then the Pipeline Integrity Engineer should inform the Connections Engineer that the requirements of the Santos Design Guide2 have not been met, and therefore the FEED will not be accepted / approved.

3 The corrosion inhibitor may be unable to create / maintain a protective film on the inside surface of the pipe wall when fluid velocities exceed ~20 m/s due to the shear force between the fluid and the pipe wall overcoming the bond between the inhibitor molecules and the steel surface. Master Flo Valve Inc, the makers of Santos preferred choke valve, state that, In corrosive applications the selected body material should be suitable for operation without the assistance of corrosion inhibitors. Higher velocities may diminish the benefit of inhibitors in valve bodies. This implies that in most cases stainless steel bodied chokes should be used in the Cooper Basin. 4 The presence of solids in the fluid flow may directly cause erosion of the pipe wall itself and / or may remove any protective inhibitor film thus enabling unmitigated corrosion to occur.



5.2 Acid Gas Corrosion Considerations 5.2.1 Corrosivity

Gas flowlines are considered to operate in corrosive service if the absolute partial pressure5 of CO2 in the pipeline exceeds ~200 KPaa. At the common design pressures used for Cooper Basin gas flowline design, this applies to almost all flowlines6 so the corrosivity of the gas has been further categorised as shown in Figure 1.

Figure 1 - CO2 Partial Pressure Corrosivity Criteria

Based on the predicted corrosivity of the gas, the designer may apply the following typical mitigation and monitoring guidance to the connection design for ongoing integrity management:

Severe Corrosivity o Duplex choke and 1 spool to provide protection whilst velocities reduce o Duplicate injector systems to improve overall injection reliability o Chemical tank level monitoring, alarmed at area control room & linked to Enable o Corrosion probe (ER) installed in lease spool low point to measure corrosion rate o Water sampling facilities at the lease spool and end of the flowline o Corrosion allowance of 3 mm

High Corrosivity o Duplex choke and 1 spool to provide protection whilst velocities reduce o Duplicate injector systems to improve overall injection reliability o Chemical tank level monitoring, alarmed at area control room & linked to Enable o Water sampling facilities at the lease spool and end of the flowline o Corrosion allowance of 2 mm

Moderate Corrosivity o Duplex choke and 1 spool to provide protection whilst velocities reduce o Single injector system o Chemical tank level monitoring, alarmed at area control room & linked to Enable o Water sampling facilities at the lease spool and end of the flowline o Corrosion allowance of 1 mm

5 Partial pressure is calculated by multiplying the CO2 mole% by the absolute pressure in the gas connection, based on data from the wells Project Initiation Plan (PIP). 6 With a typical design pressure of 11.4 MPag, the CO2 content limit for corrosive service is just over 1.7 mole%.



Low Corrosivity o Single inhibitor injector with manual level checks by Pipeline Asset Management

Services (PAMS) / Operations personnel o Water sampling facilities at the lease spool and end of the flowline o Corrosion allowance of 1 mm

Negligible Corrosivity o Corrosion allowance (to standard pipe wall thickness) to mitigate very low rates of

acid gas corrosion

5.2.2 Inhibitor Injection Reliability Considerations

In corrosive service, Santos uses corrosion inhibitor injection as the primary mitigation of the corrosion of carbon steel materials. The availability of corrosion inhibitor is the key aspect to the successful mitigation of acid gas corrosion and should therefore be taken extremely seriously.

Availability is the percentage of time the inhibitor injection system is able to inject the correct amount of inhibitor into the pipeline; some typical percentages and their equivalent down-times are presented in Table 2. The effect these values have on a typical Severe corrosivity category flowlines integrity is illustrated in Figure 2.

Table 2 - Inhibitor Availability Values % Availability Days Downtime (Per Year) Comment

99.9 0.37 3 day downtime per year extremely unlikely 99.0 3.65 Probably the highest availability that can be achieved

95.0 18.25 Suggested as upper limit for design purposes

90.0 36.50 Suggested lower limit for design purposes

Figure 2 indicates the example flowline is unlikely to last its expected design life of 20 years based on inhibitor availability experience. No matter what availability is used in the design, the designer must specify how the injection performance is to be monitored and what measures should be taken by operations personnel in the event of inhibitor availability being inadequate e.g.

Inhibitor level should be measured using tank level transmitters connected to the wellheads Remote Operations Controller (ROC) Remote Terminal Unit (RTU) to establish near real-time rate-based inhibitor usage that mirrors the flowlines gas production; injection should be alarmed to indicate injector failure

In the event of inhibitor injection failure, the affected flowline should be shut-in within a few days if the injector cannot be repaired and brought back on-line; where repairs take longer than a few days, then the flowline should be blown down to ambient pressure to reduce the corrosivity of the fluids within the line



Figure 2 - Inhibitor Availability vs. Integrity a) Availability = 99.9%; No Failure

Year20Year19Year18Year17Year16Year15Year14Year13Year12Year11Year10Year9Year8Year7Year6Year5Year4Year3Year2Year1Year00.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

0 100 200 300 400 500 600 700 800 900 1000DefectAxialLength(mm)

DefectDep

th(m

m)

NomWTveTolWTDesignCADNVCAASMEB31GNotApplicableModifiedB31GDNVRPF101LeakRuptureFeatureTimeline

b) Availability = 99.0%; Failure: Year 11

Year20

Year19

Year18

Year17

Year16

Year15

Year14

Year13

Year12

Year11

Year10

Year9

Year8

Year7

Year6

Year5

Year4

Year3

Year2

Year1

Year00.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0


DefectDep

th(m

m)


c) Availability = 95.0%; Failure: Year 3

Year7

Year6

Year5

Year4

Year3

Year2

Year1

Year00.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0


DefectDep

th(m

m)


d) Availability = 90.0%; Failure Year: 2

Year3

Year2

Year1

Year00.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0


DefectDep

th(m

m)


Note: Raven 4 used as example: CO2 Content: 44.74 mole %, Pressure: 8.5 MPa, Temperature: 65 C, Wall Thickness: 4.2 mm, Diameter: 168.3 mm, Steel Grade: API-5L-X56, MAOP: 11.4 MPa. Failure is defined as when the corrosion timeline crosses the Modified B31G criteria line.

The use of duplicate injection systems attempts to improve the overall availability of inhibitor chemical entering the flowline; this is demonstrated in Table 3.

Table 3 - Multiple Injector Reliability / Availability of Injectors (i) Individual Reliability / Availability (Ai) Overall Reliability / Availability (Ao)

1 90% Ao = 1-(1-Ai)i = 90.0%

2 90% Ao = 1-(1-Ai)i = 99.0%

3 90% Ao = 1-(1-Ai)i = 99.9%

Based on the information in Table 3, it is clear that reliability / availability figures > 99% can only be achieved with multiple independent injectors with each injector providing a reliability / availability of ~90%.



5.2.3 Inhibitor Tank Capacity

In addition to the number of injection systems considered for installation at the wellhead connection, sufficient chemical storage capacity must be installed to provide adequate chemical to enable the longest possible interval between tank top-ups. This reduces the resource requirement and driving time (risk) involved in the top-up activity. The current shelf life of the inhibitor chemical is around 6 months (~180 days) therefore sufficient chemical needs to be stored for this period at the required injection rate. The required injection rate is based on guidance provided in the Pipeline CMS1, and is presented in Table 4 as a worked example.

Table 4 - Tindilpie 6 Inhibitor Injection Rate and Tank Capacity Example Basis for Injection Rate Rate Capacity Required

1 pint (0.473 litres) inhibitor / 1 mmscf of gas flow for gas flow of 8.5 mmscf/d 4.02 litres/day 724 litres

200 ppm in water; water at 9 bbl/mmscf (1.43 m3/mmscf) for gas flow of 8.5 mmscf/d 2.43 litres/day 437 litres

1 m on inside surface7 of 168.3 mm, WT 4.2 mm, 4,243 m long flowline (surface area = 2,131 m2) 2.13 litres/day 383 litres

The applied rate should initially be the greatest of those evaluated above rounded up to the nearest whole litre 5.00 litres/day 900 litres

Table 4 indicates this connection would require 900 litres of inhibitor storage capacity, i.e. a 1,000 litre bulky bin, for 180 days, rather than the single 340 litre tank that was actually installed. The 340 litre tank will require filling ~3 times over 6 months versus the bulky bins one fill.

5.2.4 Pigging Facility Considerations

In a gas well connections flowline, water originates from two sources:

Condensation - during initial production the gas at the well-head should be relatively dry, however, as it cools and loses pressure along the flowline, water will condense from the gas and come in contact with the pipe wall. The pure condensed water and dissolved CO2 from the gas will have a low pH i.e. will be more corrosive

Produced directly from the well - as the reservoir depletes, water will be produced from the reservoir itself. Formation water contains impurities which reduce its acidity i.e. the formation water will buffer the pH of pure water and CO2 reducing corrosivity

Once the water is in the flowline, and depending on the topography, water hold-up may occur enabling corrosion at uphill sections of the flowlines route whilst flowing, and in low spots whilst the flowline is shut-in. In addition, the condensed water may continually wet the top and side surfaces of the flowline where the inhibitor cannot reach (only carried in the liquid water phase in the bottom of the pipe). Pigging provides a valuable mitigation function by the following actions:

Sweeping held-up water from the uphill sections and low spots in the line Sweeping condensed water from the top and sides of the pipe Mixing water and inhibitor chemical

Despite the advantages of pigging, the modifications required to a flowline and the manpower required to implement a regular pigging programme should be considered with respect to the overall value and length of the flowline. Flowlines less than 500 m in length do not normally justify pigging facilities as they are usually too short for significant water to condense from the gas. Higher corrosivity and longer flowlines should have their topography reviewed with respect to water hold-up and be considered for the installation of Argus Pigging Valves to enable operational pigging

7 For long flowlines (>10 km) caution should be used as this criterion estimates very large dose requirements. This is most likely because the whole flowlines internal surface is not water wet, only the section at the bottom of the line is wet.



activities. For particularly high value flowlines, in terms of production, the flowline may require the capability for ILI so this should also be considered in the FEED.

Where pigging is recommended, a review of the liquids handling facilities of any downstream facilities should be carried out to evaluate whether the additional liquid slug, that will arrive with a pig, will upset the downstream process.

5.2.5 Corrosion Allowance Considerations

Corrosion allowance is additional wall thickness added to a pipeline that can be corroded should any applied mitigation fail, but does not affect the pressure retaining ability of the pipe. For a fully corrosion mitigated pipeline, an underlying corrosion rate of 0.05 mm/yr is normally applied hence the corrosion allowance should be a minimum of this rate multiplied by the expected life of the flowline.

If minimal corrosion allowance is considered due to the pressure decline likely as a gas reservoir depletes, the FEED document must demonstrate a basis for this design consideration and include guidance as to how this will be monitored.

Alternatively, the flowline should have a nominal 1 mm of corrosion allowance as a minimum for corrosive service; this allowance should be increased for High corrosivity (2 mm) and Severe corrosivity (3 mm) service to account for the increased deterioration rate during periods of poor mitigation.

5.2.6 Alternate Materials

The FEED should consider alternative materials for Severe and High corrosivity service as discussed in Section 5.2.1; though it is expected that such materials will not be specified due to the higher CAPEX involved, despite the reduction in OPEX that such material selection could offer. The FEED should state this as the decision to proceed with carbon steel.

Where any of the considerations mentioned above have not been considered and documented in the FEED package, then the Pipeline Integrity Engineer should inform the Connections Engineer that the requirements of the Santos Design Guide2 have not been met, and the FEED will not be accepted / approved.

5.3 Erosion Considerations Erosion considerations are only required at the well connection due to the probable high velocities associated with the smaller diameter piping components upstream of the flowline. With sand-free reservoir fluids, the velocity limits described previously in Section 5.1 should be adequate in preventing erosion related failures provided these considerations are fully complied with.

Where the reservoir fluid contains continuous and significant quantities of sand, then further consideration may include:

Increase choke size to reduce velocity of fluid flow at outlet Increase pipe work diameter to reduce velocity of fluid flow Install erosion monitoring facility to measure erosion directly Anticipate failure and increase frequency of inspection to forecast replacement

The issue with sand production is knowing whether it is continuous and / or significant. There is anecdotal evidence that sand is produced in the Cooper Basin as it has to be removed from separators in process plants, but currently it is unknown where exactly the sand comes from.

Until clear evidence of continuous and / or significant sand production is provided through more thorough well testing it will be assumed that it does not occur in the Cooper Basin and the velocity limits discussed previously shall be used to address erosion issues.



5.4 External Corrosion Considerations External corrosion is primarily a threat to buried carbon steel gas flowline connections. To mitigate this, the flowline is normally coated with Fusion Bonded Epoxy (FBE) and has some form of Cathodic Protection (CP) applied.

Surface-laid above-ground oil flowlines will also suffer from external corrosion, but this will normally be limited to the lower half of the line as it sits on the ground. As surface laid oil flowlines are not normally coated, it is essential that the FEED considers methods of mitigating the external corrosion, such as lifting and supporting the line using approved supports.

Unmitigated soil corrosion rates in the Cooper Basin may be as low as 0.1 mm/yr (based on buried ER probes in the Moomba Plant), however, over a 25 year life this equates to metal loss of up to 2.5 mm which may threaten the integrity of the pipelines pressure containment capacity. It should also be considered that unmitigated corrosion rates in salt pans and other soil types can be up to 5 times higher than the low rates measured within the Moomba Plant.

Where any of the considerations mentioned above have not been considered and documented in the FEED package, then the Pipeline Integrity Engineer should inform the Connections Engineer that the requirements of the Santos Design Guide2 have not been met, and the FEED will not be accepted / approved.

5.5 FEED IMP Should a FEED Integrity Management Plan not be included in the FEED package, then the Pipeline Integrity Engineer should inform the Connections Engineer that the requirements of the Santos Design Guide2 have not been met, and the FEED will not be accepted / approved.

5.6 Pipeline Integrity Review For new flowline connections it is important that these lines are included in the next planned Pipeline Integrity Review8. This is to ensure that conditions assumed by the designer are updated with actual conditions to validate the design as adequate for the purposes of ongoing integrity management. Where the design is subsequently assessed as inadequate, corrective action shall be implemented and a summary of this fed back to the Connections group for consideration for future connection FEED.

8 Pipeline Integrity Review Procedure, Santos Document Ref: AIMS-PI-PROC-0005



6 References Table 5 Santos Facilities Engineering Standards

1515-10-G005 Design Guide for Gas Wellhead Connection Design

1515-10-G006 Design Guide for Oil Wellhead Connection Design

1515-10-G007 Design Guide for Fluid Flow Calculations

1515-50-D002 Design Practice for Valves

1515-50-G001 Design Guide for Piping

1515-50-G007 Design Guide for Gas and Oil Gathering Systems

Table 6 Santos Procedures

Man

agem

ent

AIMS-PI-PROC-0001 Pipeline Asset Management System (PAMS)

AIMS-PI-PROC-0002 Pipeline Corrosion Management Strategy (CMS)

AIMS-PI-PROC-0003 Pipeline Safety and Operating Plan

AIMS-PI-PROC-0004 Integrity Management Planning

AIMS-PI-PROC-0005 Pipeline Integrity Review

AIMS-PI-PROC-0006 Performance Monitoring - KPIs

AIMS-PI-PROC-0007 Records Management

AIMS-PI-PROC-0008 5-Year Plan

Mon

itorin

g AIMS-PI-PROC-0101 Corrosion Rate Monitoring

AIMS-PI-PROC-0102 Water Sampling & Analysis

AIMS-PI-PROC-0103 Pig Trash Sampling & Analysis

Miti

gatio

n

AIMS-PI-PROC-0201 Operational Pigging

AIMS-PI-PROC-0202 Chemical Injection System Management

AIMS-PI-PROC-0203 Pipeline Batch Chemical Treatment

AIMS-PI-PROC-0204 Pig Barrel Treatment

AIMS-PI-PROC-0205 CP System Operation & Maintenance

Insp

ectio

n

AIMS-PI-PROC-0301 Pig Barrel Inspection

AIMS-PI-PROC-0302 Lease Spool Inspection

AIMS-PI-PROC-0303 ROW Patrol & Inspection

AIMS-PI-PROC-0304 In-Line Inspection

AIMS-PI-PROC-0305 Direct Assessment Inspection

AIMS-PI-PROC-0306 Coating Defect Inspection

Oth

er (S

uppo

rt)

AIMS-PI-PROC-0401 Cooper Basin Pipeline Failure Recovery Plan

AIMS-PI-PROC-0402 Failure Investigation

AIMS-PI-PROC-0403 Abandonment & Suspension

AIMS-PI-PROC-0404 Selection & Treatment of Water

AIMS-PI-PROC-0405 In-Direct Assessment

AIMS-PI-PROC-0406 Integrity & Defect Assessment

AIMS-PI-PROC-0407 Project / Programme Implementation

AIMS-PI-PROC-0408 FEED Integrity Checks

AIMS-PI-PROC-0409 Inspection Target Co-ordinates Evaluation [This Document]



Table 7 Other References API-RP-14E Recommended Practice for Design and Installation of Offshore Production

Platform Piping Systems

NORSOK P-001 Process Design



7 Appendix A - Pipeline Integrity FEED Review Checklist

Well / Flowline Name:

FEED Reference:

Reviewing Integrity Engineer: Date:

Velocity Checks 9/8/NA 9/8/NA Choke velocity limit considered (open) ? Lease spool velocity limit considered ?

Choke velocity limit considered (partially closed) ? Flowline velocity limit considered ?

Are any velocity limits exceeded ? Has risk assessment been carried out ?

Downstream facility velocity limits ? Are any downstream velocity limits exceeded ?

Acid Gas Corrosivity & Mitigation Checks

Has gas corrosivity been categorised ? Has corrosion rate been calculated correctly ?

Has inhibitor availability been applied correctly ? Does availability match injector arrangement ?

Is appropriate corrosion allowance specified ? Is stainless steel choke body specified ?

Is inhibitor injection rate specified correctly ? Is adequate tank capacity specified ?

Is inhibitor tank level monitoring specified ? Is level monitoring connected to the ROC ?

Is corrosion monitoring probe specified ? Are water sample locations specified correctly ?

Have alternative materials been considered ? Have pigging facilities been considered ?

Has any downstream facility liquids handling review been carried out where pigging has been recommended ?

Remarks:

Erosion Checks

Is sand production expected ? If 9, describe documented mitigation below.

External Corrosion Checks

Is flowline buried ? Is FBE coating specified ?

Is CP specified to provide additional protection ? Has soil corrosion rate been considered ?

Has lifting been specified for surface laid lines ? Have approved supports been specified ?

Remarks:

FEED IMP

Has a FEED IMP been included ? If 8, the FEED cannot be accepted. FEED Acceptance

FEED Accepted If not summarise reasons below + note other issues.



8 Appendix B - FEED Checks Sheet A spreadsheet has been prepared to assist / guide the FEED checks described in this document and can be found in the Excel FEED Check Sheet [Latest Date].xls workbook.

FlowlineFEEDIntegrityChecksDocumentControl MAOPContainmentWallThicknessChecks InternalCorrosionMitigation

WellName: Component Min.WT CA Units InhibitorDoseRate Initial Maximum Units

FEEDReference(includingrev.): 1Spool 2.41 N/A mm 9 BasedonGasFlow: 3.79 4.26 litres/dayPreparedby: 0.00 00Jan00 MeteringSpool 4.43 4.13 mm 9 Basedon200ppminwater: 0.51 0.57 litres/dayReviewedby: 0.00 00Jan00 Flowline 3.45 2.15 mm 9 Basedon1mfilmonpipewall: litres/dayApprovedby: 0.00 Notes: ProposedInitialRate: litres/day

InputData Initial Maximum Units Ullage(for6months)/TankType: litres/~

NatureofHydrocarbonLiquid: ~ InjectorArrangementRequired: !Override! 9GasRate: 8.00 9.00 mmscf/day CorrosionProbeRequired: ~

HCLiquidRate: 0 0 bbl/day VelocityChecks LiquidHoldupExpected: ~Water/Gas Ratio: 2 2 bbl/mmscf Choke(fullyopen): Initial Maximum Units PiggingFacilitiesRequired: ~

HCLiquid/Gas Ratio: 3 3 bbl/mmscf CValue: ~ FlowlineInletInternalCorrosion Initial Average UnitsSurfaceTemperature(flowing): ~ 190 F MixtureDensity: 94.53 94.53 kg/m3 InitialFluidCorrosivity: Moderate Low ~

~ 88 C 5.90 5.90 lb/ft3 RawCorrosionRate: 31.45 17.53 mm/yrSITHP: ~ 2500 psig VelocityLimit: 25.09 25.09 m/s SampledWaterpH: ~ 9 ~ 17.2 MPag Velocity: 10.26 11.54 m/s 9 pHBufferedCorrosionRate: 15.96 11.08 mm/yr

FTHP: ~ 870 psig Choke(notfullyopen): InhibitorAvailability: % ~ 6.0 MPag 1.90 MinimumChokeOpening: % 9 OilWettingMitigation: ~ ~ %

ExpectedWellLife: years CValue: ~ Attempt#1BOLCorrosionRate: 0.15 0.12 mm/yrCompositionN2: mole% MixtureDensity: 94.53 94.53 kg/m3 Attempt#1RemainingLife(BOL): 14.15 17.82 yr 9

CO2: mole% 5.90 5.90 lb/ft3 AdditionalMitigationRequired: ~C1: mole% VelocityLimit: 25.09 25.09 m/s Pigging: ~C2: mole% Velocity: 10.48 11.79 m/s 9 BatchTreatment: ~C3: mole% 1Spool: Attempt#2BOLCorrosionRate: ~ ~ mm/yriC4: mole% CValue: ~ Attempt#2RemainingLife(BOL): ~ ~ yr 9nC4: mole% MixtureDensity: 94.53 94.53 kg/m3 Notes:iC5: mole% 5.90 5.90 lb/ft3 9nC5: mole% VelocityLimit: 25.09 25.09 m/sC6: mole% Velocity: 7.15 8.05 m/sC7: mole% MeteringSpool: DefectTolerance

C8+: mole% CValue: ~ AssessmentCode: ~

H2S: mole% MixtureDensity: 94.53 94.53 kg/m3 LengthCorrosionMultiplier: ~Total: SG:1.50 9 5.90 5.90 lb/ft3 #1/#2PredictedBOLFailureAge: 21 ~ years 9

PipeSizing/MaterialSelection VelocityLimit: 18.82 18.82 m/s AxialFitness forPurposeTimelineChartMAOP/DesignPressure: MPag Velocity: 7.10 7.99 m/s 9

ChokeSize: mm 9 FlowlineInlet:ChokeMaterial: ~ 9 CValue: ~

1SpoolDiameter: mm 9 MixtureDensity: 94.53 94.53 kg/m31SpoolWallThickness: mm 5.90 5.90 lb/ft3

1Spoolmaterial: ~ VelocityLimit: 18.82 18.82 m/sMeteringSpoolDiameter: mm 9 Velocity: 2.72 3.06 m/s 9

MeteringSpoolWallThickness: mm FlowlineOutlet:

MeteringSpoolMaterial: ~ OutletTemperature: 27.79 28.94 CFlowlineDiameter: mm 9 OutletPressure: 5.44 5.33 MPag

FlowlineWallThickness: mm CValue: ~

FlowlineMaterial: ~ MixtureDensity: 108.59 105.66 kg/m3OtherData 6.78 6.60 lb/ft3

DesignCode: ~ VelocityLimit: 17.56 17.80 m/s 9Safety/DesignFactor: ~ Velocity: 2.37 2.74 m/s

LocationClassification: ~ Notes:

FlowlineLength: m

ExternalCoatingDetails: ~

Above/BelowGround: ~

FlowlineFeedCheckCorrosivityChart NotesTemperature(C)vs.Distancealongl ine(m)

Pressure(MPa)vs.Distancealongl ine(m)

Initial BOLCorrosionRate(mm/yr)vs.Distancealongl ine(m)

Corrosivity

Wareena #1 InitialWareena #1 Average

'PipeSizing/Material Selection'entries arethedesigner's proposedoptionsfortheleasepipingandflowline.Thechecks carriedoutonthesevalues arevelocitychecksi.e.ensuringvelocityl imits arenotexceeded.

'MAOPContainmentWall Thickness Checks'arebasedonpressurecontainmentonly.TheCAcheckisbasedon10years ata'ful lymitigated'corrosionrateof0.05mm/yr.Abovegroundpipeworkusesasafety/designfactorof0.6,belowgrounduses 0.72.

'VelocityChecks'areall basedontheAPI14Eapproachforcalculating:pressuredrop,velocity,velocityl imit,andfluiddensity.Exponential temperaturedropis calculatedusingoverall heattransfercoefficientsof0.025forabovegroundand3.120forbelowground.

Theminimumchokeopeningis usedtoi l lustratethethresholdbelowwhichthevelocitycheckwill fai l i .e.theopeningbelowwhichvelocitiesexceedthevelocityl imitbyAPI14EatthePIPflowrates.Openingpercentagesarein10%increments.

Appearsthatminimumcorrosionallowancesareinplacebasedonfullymitigatedcorrosionrateof0.05mm/yr.

25

TheFEEDchecks havebeenimplementedbasedontherequirementsofSantosDocument151510G005'DesignGuideforGas WellheadConnectionDesign'.

Thedesignershouldalsoconsidertheeffects ofthisnewflowlineondownstreamfacil ities toensurethesefacil ities will notbeputatriskthroughexcessivefluidflow.Inaddition,thel iquidhandlingcapacityofdownstreamfaci l itiesshouldbereviewed.

'InputData'isobtainedfromtheflowlinewell'sProjectInitiationPlan(PIP).Theaccuracyofthisdata hasagreateffectontheresults oftheleasepipingandflowlinedesign,soeveryendeavourshouldbemadetoensurethisis representative.

A106GrB

0.090.020.00

80.00

5.60

8.56

11.40

114.308.74

SS

114.30

99%

NoYesYes

Duplex

915/BulkyBin

No

Wareena#1

100.00

Condensate

6.611.140.23

0

10

0.05

3.514.0083.90

0.230.11

0.11

Attempttogetall thecheckcolumnstocontaingreenticks.

150168.30

No

12.345.00

DualInjector

ModB31G

BottomofLine(BOL)Corrosionmitigationappearsadequate.

4.77

200

60200

200

150

150

'Internal CorrosionMitigation'values arecalculatedbasedonthePIPinputdata,corrosivityofthefluid,lengthoftheflowlineetc.Ifthecorrosionchecksfail ,thedesignermayoverridetheinjectorarrangementtoimprovetheavailabil ityofinhibitor.

Internal corrosionratecalculations areperformedattheflowlineinlet,whichisl ikelytoexperiencetheworstconditions i .e.pressureandtemperature.RatesareestimatedusingdeWaardandMill iams'93approachas perAIMSPIPROC0002AppendixA.

Remainingl i fechecks arecarriedoutfor:1)usingcorrosionallowanceonlyi .e.toevaluatewhethercorrosionallowancewill survivethenominal 10yearl i fe,and2)usingaxial corrosiondefecttolerancei.e.growingdefectandcomparingwithModifiedB31GFFPcriteria.

Appearsthatvelocitylimitsarenotexceededsopipesizingisappropriate.

Note:Thischarttakesnoaccountofthetemperatureofthegas,whichhasasignificanteffectonthelikelycorrosionrate.

Buried

No

X56

AS2885.10.72

25,000R1BroadRural

FBEYear1

Year2Year3

Year4Year5Year6Year7Year8Year9Year10Year11Year12Year13Year14Year15Year16Year17Year18Year19Year20Year21Year22Year23Year24Year25

0.0

1.0

2.0

3.0

4.0

5.0

6.0

1 10 100 1,000 10,000

Dep

th(m

m)

Length(mm)

WTCAASMEB31GModB31GDNVRPF101LeakRupture#1BOLTimeline#2BOLTimeline

Raven1Tindilpie6

BigLake63

Psyche3Bookabourdie4

Challum27

Della23

Dullingari53

Gidgealpa38

Marabooka10

Moomba063

Okotoko01

Tirrawarra71

BMP

Wareena#1Initial

Wareena#1Average0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

50%

0 2 4 6 8 10 12 14

SampleWells21KPaappCO2Threshold207KPaappCO2Threshold650KpaappCO2Threshold1,500KPaappCO2ThresholdWareena#1InitialWareena#1Average

HighCorrosivity

ModerateCorrosivityLowCorrosivity

SevereCorrosivity

0

20

40

60

80

100

0 5,000 10,000 15,000 20,000 25,000 30,000

0.0

2.0

4.0

6.0

8.0

0 5,000 10,000 15,000 20,000 25,000 30,000

0.00

0.05

0.10

0.15

0.20

0 5,000 10,000 15,000 20,000 25,000 30,000

Attempt#1 Attempt#2

2010-06-14T11:31:36+0800Richard Stentiford

2010-06-14T11:33:35+0800Bob GreenwoodI have reviewed this document

2010-06-28T13:18:28+0930Greg Cowley

feed checking

Documents

pipeline integrity group

ongoing integrity

feed package

flowline feed documents

significant pipelines

review rst rmac rst

use rst rmac rst

appendix b feed checks