Final MSR Rev[1]. C

PROJECT – UPGRADATION OF KONABAN GGS & PIPELINE GRID PROJECT - TRIPURA ASSET Contract No : DLH/OES/MM/UKon_PGP/AGT/X11PC09003/2010 Corrosion Calculation and Material Selection Report

Doc No: UkonPGP/COM/PRO/RPT/4/I/005

Rev: C

Page 1 of 76

Corrosion Calculation and Material Selection Report

Engineering Sub – Contractor Mott MacDonald Pvt. Ltd. Kothari House, CTS No. 185 Off Andheri - Kurla Road Andheri (East) Mumbai 400 059

LSTK Contractor

Client

KazStroyService Infrastructure India Pvt. Ltd. 1st Floor, Vatika Towers, A-Wing, Sector 54, Gurgaon - 122002

Oil and Natural Gas Corporation Ltd. th 8 Floor,Core-3,Scope Minar , Laxmi Nagar,Delhi-110092 (India)

P:\Andheri\IndiaProject\Kazstroy-ONGC-Tripura\09 Document Control\Outside Services\Mat Selection-CAPetrochem\From Petrochem\Rev. C Final\Editable\Final MSR Rev. C.doc



Rev: C

Page 3 of 76

List of Contents

Page No.

1

Introduction

4

2

Abbreviations

5

3

Process Description

6

4

Design Basis for Facilities

13

5

Prediction Models of Pipeline Corrosion

14

6

NACE Guidelines and Our Calculation Model

16

7

Corrosion

17

8

Methods of controlling corrosion

20

9

Corrosivity evaluation, corrosion protection and Material Selection

22

10

Corrosivity evaluations in hydrocarbon systems

53

11

Conclusion

54

12

Bibliography:

56

13

List of Holds :

57

14

References:

58

Annexure I

: Sample Calculations for Corrosion

60

Annexure II

: Streamwise Corrosion Calculation

64

Annexure III

: Material Selection Diagrams

65

Annexure IV

: Material Recommendation for Equipments

67

Annexure V

: Corrosion Inhibitor Vendor Information (HOLD-2)

76




1

Rev: C

Page 4 of 76

Introduction The Scope for this document is to Recommend Base Material for Piping, Equipments/vessels and pumps with calculation of corrosion allowance for sweet service i.e. Corrosion due to CO 2 in absence of H2S based on appropriate corrosion model with proper justification and also suggests the suitable corrosion inhibitor and its injection rate. We found that for given services NACE is not applicable as the given services are not sour and partial pressure of CO2 is also very low (Refer to Para 1.3 and Table 1 of NACE Std. ISO15156-1) We have evaluated various corrosion models and found that only DEWARD model is suitable in our case. Hence the same is used for calculating corrosion allowance for various streams. DEWARD Model calculation is suitable for all services with a corrosion allowance, Corrosion Monitoring system and with injection of proper Corrosion Inhibitor with appropriate flow rate to achieve 75% inhibiting efficiency. It is to be noted that Corrosion allowance as given is suitable for 25 years only if the availability of inhibitor is 95% (Inhibitor is not available for 15 months in a span of 25 years i.e. 300 months) Corrosion, scale formation and salt accumulation pose increasing challenges for the operation of multiphase pipelines. Corrosion-resistant alloys such as 13% Cr steel and duplex stainless steel are often used down hole and, recently, also for short flow lines. For long-distance, large-diameter pipelines, carbon steel is the only economically feasible alternative and corrosion has to be controlled by Corrosion Inhibitors added to the transported fluids. The presence of carbon dioxide (CO 2), hydrogen sulphide (H 2S) and free water cause severe corrosion problems in oil and gas pipelines. Internal corrosion in wells and pipelines is influenced by temperature, CO2, H2S content, water chemistry, flow velocity, oil or water wetting, composition and surface condition of the steel. A small change in any one of these parameters can change the corrosion rate drastically due to changes in the properties of the thin layer of corrosion product that accumulates on the steel surface. When corrosion products are not deposited on the steel surface, very high corrosion rates of several millimetres per year (mm/y) can occur. This ‘worst case’ corrosion is the easiest type to study and reproduce in the laboratory. In the event of CO2 dominating the corrosivity, the corrosion rate can be reduced substantially under conditions where iron carbonate can precipitate on the steel surface and form a dense and protective corrosion product film. This occurs more easily at high temperature or high pH value in the water phase. When H2S is present in addition to CO2, iron sulphide films are formed rather than iron carbonate, and protective films can be formed at lower temperature, since iron sulphide precipitates much easier than iron carbonate. Localised corrosion with very high corrosion rates can occur when the corrosion product film does not give sufficient protection, and this is the most feared type of corrosion attack in oil and gas pipelines. In our case we don’t have H2S even in traces, and pH is also high hence only CO2 shall be dominating factor in causing corrosion.




2

Rev: C

Page 5 of 76

Abbreviations ADB

-

Agartala Dome

CPCB

-

Central Pollution Control Board

CO

-

Carbon Monoxide

CO2

-

Carbon Di-oxide

GGS

-

Gas Gathering Station

GCV

-

Gross Calorific Value

GGS

-

Group Gathering Station

HC

-

Hydrocarbon

HLL

-

High Liquid Level

HP

-

High Pressure

IDBH

-

Indirect Water Bath Heater

KOD

-

Knock Out Drum

KSSIIPL

-

KazStroyService Infrastructure India Pvt. Ltd.

LPD

-

Litres per Day

MMPL

-

Mott MacDonald Private Limited.

MMSCMD

-

Millions of Standard Cubic Meter per Day

NCV

-

Net Calorific Value

NFPA

-

National Fire Protection Association

NPSH

-

Net Positive Suction Head

NOx

-

Nitrogen Oxide

OISD

-

Oil Industry Safety Directorate

OMR

-

Oil Mines Regulations

ONGC

-

Oil and Natural Gas Corporation Limited

OTPC

-

ONGC Tripura Power Company

OWS

-

Oily Water Sump / System

SDV

-

Shut Down Valve

SIL

-

Safety Integrity Level




3

Rev: C

Page 6 of 76

Process Description The process description for new Konaban GGS, existing Konaban GGS and Palatana Terminal is given in the following paragraphs.

3.1

New Konaban GGS The process description for new Konaban GGS is as follows: The incoming well fluid from 22 present wells and 2 future wells for producing condensate, gas and water using different mechanisms for production shall be connected to the new Inlet Manifold consisting of HP header and test header, rated for shut in pressure of 252 kg/cm2g. These incoming well flow lines shall be provided with local PI and TI, PT, TT, sample connection, adjustable choke valve and retrieval type corrosion coupon. The new HP header and Test header shall be connected to existing HP and Test header. The existing Test Separator at Konaban GGS shall be used for testing of the wells connected to new Test Header. The interconnecting valve between existing and new test header shall be opened only when new header wells are required to be tested. Similarly, the interconnecting valve between new and existing HP header shall remain closed during initial phase of operation due to high operating pressure of the wells. Well fluid from new HP header shall be heated in Indirect Water Bath Heater to 45 °C. This heated well fluid shall be sent to HP production Separator operating at a pressure of 27.2 kg/cm2g. The separated gas shall be sent to Gas Scrubber. The separated gas from gas scrubber shall be sent to Palatana terminal via gas metering skid. Part of this gas shall be used for internal consumption such as Fuel gas and Instrument gas via respective processing skids. This gas after pressure reduction shall be sent to Fuel Gas KOD to knock-out the liquid, if any and sent to Fuel Gas Filters. This filtered gas shall be used as fuel gas for the consumers such as bath heater burners, pilot burners of flare, pilot burners of evaporation pit etc. This new fuel gas header shall also be connected to existing fuel gas header. The new Instrument gas system shall consist of a Gas Drier package and Instrument Gas Receiver designed to cater the requirement of new as well as existing GGS considering instrument gas consumption of existing Konaban GGS as 5,000 Sm3/day. The part of gas from Gas Scrubber; after pressure reduction; shall be sent to Instrument Gas Drier package. This dry instrument gas shall be stored in an Instrument Gas Receiver and sent to various consumers via instrument gas header. Condensate from HP Production Separator shall be sent to Condensate Stabiliser operating at a pressure of 1.5 kg/cm2g. The stabilised condensate shall be sent to Condensate Storage Tanks. From condensate storage tanks, condensate shall be transferred to Road Tankers by using Condensate Loading Pumps through condensate metering with coriolis type mass flow meter and by using loading arm. Produced water from HP Production Separator shall be sent to Effluent Stabiliser operating at a pressure of 2 kg/cm2g. The stabilised effluent shall be sent to Evaporation Pit. A provision to transfer this effluent to Effluent Storage Tank shall also be provided. From



Rev: C


Page 7 of 76

Effluent Storage Tank, effluent shall be transferred to Road Tankers by using Effluent Transfer Pumps through effluent metering by using loading arm.

Figure – 3.1.1 Process Block Diagram for New Konaban GGS

NEW FLARE HEADER FLARE EXIST. FLARE HEADER IG SKID

OFF PLOT

TO NEW FLARE HEADER

ON PLOT

INST. GAS

GAS T O FG SKID

EXIST. GAS LINE

GAS To PALATANA

Wel l-1

GAS SCRUBBER

FG TO CANTEEN

CHOKE VALVE - 1

(TYP) Total 24 IDBH

Wells

NEW PROD DUCTI ON HEADE R

EXIST. PRODDUCTION HEADER

NEW TES T HEA DER

PRODUCTION SEPARATOR

COND. STABILISER

o LOADING via COND. TANK

EFFL. STABILISER EFFL. TO EVP’’N PIT VIA . TANK

EXIST. TEST HEADER

EXIST. TEST SEPARATOR




Rev: C

Page 8 of 76

Feed Characteristics for Konaban GGS

The following Table –3.1.1 gives the feed characteristics for Gas and Condensate for Konaban GGS: Table – 3.1.1: Feed Characteristics for Konaban GGS A) Gas Analysis Data (Note-1) Sr. No. Component Unit 1 Methane Mole % 2 Ethane Mole % 3 Propane Mole % 4 i-Butane Mole % 5 n-Butane Mole % 6 i-Pentane Mole % 7 n-Pentane Mole % 8 C6+ Mole % 9 Carbon Di-oxide Mole % 10 Nitrogen Mole % 11 Molecular Weight 12 Specific Gravity (Avg) 3 13 GCV kcal/m 3 14 NCV kcal/m Note-1: Gas analysis data for sample dated June15, 2009. B) Sr. No. 1 2 3 4 5 6 7

C) Sr. No. 1 2 3 4 5 6 7 8 9 10

Property Density Specific Gravity API Gravity Sulphur RVP Nitrogen Calorific Value (Avg.)

Volume % IBP 5 10 15 20 25 30 35 40 45

Condensate Property Data Unit gm/cc °API ppm psi (a) Weight % kcal / kg

Condensate ASTM Data Temperature,°C Sr. No. Volume % 62 11 50 88 12 55 104 13 60 115 14 65 123 15 70 131.5 16 75 138 17 80 143.5 18 85 150 19 90 155.5 20 93 (FBP)

Value 96.653 1.840 0.294 0.084 0.067 0.016 0.013 Traces 0.832 0.201 16.72 0.5783 9,177.79 8,269.93

Value 0.8174 0.8178 41.50 52 2.4 0.02 10,996.9

Temperature,°C 163.5 173 179.5 191 200 209 224 236 245 247




3.2

Rev: C

Page 9 of 76

Existing Konaban GGS The process description for existing Konaban GGS is as follows: The existing Konaban GGS has a capacity of processing 0.5 MMSCMD of gas, 10 m3/day of condensate and 50 m3/day of effluent water. The existing Konaban GGS has 10 flow lines connected to the Production and Test headers. These headers are provided with 2 Nos. of control valves installed in series (PCV-001/001A and PCV-002/002A respectively) for noise reduction and block discharge PSVs (PSV015/016 and PSV-017/018) to divert gas to flare. The well fluid from 8” production header is routed to bath heater (E-1) to heat up the well fluid through indirect water bath heater. The heated well fluid from bath heater is routed to production separator (SD-1) for separation of gas, condensate and water. Similarly, the well fluid from 6” test header is routed to bath heater (E-2) to heat up the well fluid through indirect heat water bath. The heated well fluid from bath heater is routed to test separator (SD-2) for separation of gas, condensate and water. Separated gas from Production and Test separators is passed through filters (F1 & F2) and routed to the metering station before dispatch to consumers. A provision to despatch the gas from existing Konaban GGS to Palatana terminal and that from new Konaban GGS to existing consumers is also provided under the scope of this project. The condensate separated out in production and test separators is routed to LP separator (SD-3) for stabilization where the dissolved gas is liberated from the condensate and routed to flare. The separated condensate is sent to Storage Tank. The water separated out in production and test separators is routed to water flash drum (SD4) where the dissolved gas is liberated from the water and currently routed to flare. The separated water is routed to evaporation pit for evaporation. A provision to send the gas from LP Separator and Water Flash Drum along with the produced gas from new Condensate and Effluent Stabilisers to Canteen as fuel gas is also provided under the scope of this project.




3.3

Rev: C

Page 10 of 76

Palatana Terminal The gas from Konaban GGS along with gas from Sonamura GGS and Agartala Dome GGS is sent to Palatana terminal via pipelines from respective GGS. This collected gas shall be sent to a Gas Scrubber via a header where the condensate from the gas is knocked out and gas shall be sent to OTPC power plant through custody transfer meters. The condensate from Gas Scrubber shall be stabilised in Condensate Stabiliser and sent to loading in Tankers via an overhead Condensate Storage Tank. Vents and outlet of the pressure relief devices will be connected to a Vent Stack with CO2 snuffing system.

Figure– 3.3.1 Process Block Diagram for Palatana Terminal

OFF PLOT

ON PLOT

PIG RECEIVER GAS FROM AGARTALA DOME GGS GAS FROM KONABAN GGS

GAS FROM SONAMURA GGS

GAS TO OTPC POWER PLANT

GAS METERING

GAS SCRUBBER

GAS TO VENT STACK

PIG RECEIVER CONDENSATE STABILISER

OVERHEAD CONDENSATE TANK

CONDENSATE To LOADING




3.4

Rev: C

Page 11 of 76

Pipeline Grid Pipeline Grid consisting of - 20”, 53 km long pipeline between ADB and Palatana via Nimbutali Junction and Bagabasa. This pipeline shall be provided with 4 SVS's and is hooked up to a gas collection manifold at Palatana. - 16”, 12 km long pipeline between Konaban GGS and Nimbutali Junction point. The pipeline is further connected to 20” line at Nimbutali from ADB GGS. - 16”, 22 km long pipeline between Sonamura and Palatana. This pipeline shall be provided with 2 SVS's and hooked up to a gas collection manifold at Palatana. This pipeline shall be provided with one spare tapping of 16” with a blind to integrate with Phase II Pipeline grid comprising of Tichna and Gojalia. - Kunjaban manifold with provision to hook up 10 wells, 8”, 19.5 km long Feeder pipeline and 6”, 19.5 km long Test pipeline between Kunjaban manifold and ADB GGS. - Sundalbari manifold with provision to hook up 12 wells, 8”, 12.5 km long Feeder pipeline and 6”, 12.5 km long Test pipeline between Sundalbari manifold and Sonamura GGS.




Rev: C

Page 12 of 76

Figure– 3.4.1 Pipelines Block Diagram



Rev: C


4

Design Basis for Facilities

4.1

Konaban GGS

Page 13 of 76

The following table – 4.1.1 gives the capacity of Konaban GGS: Table– 4.1.1: Capacity of Konaban GGS Sr. No.

Item

1

Konaban GGS New Konaban GGSExisting Konaban GGSafter upgradation

2 3

4.2

Capacity Min. / Max. Gas, Condensate, 3 MMSCMD Sm /day

Remarks

0.1 / 1

1 / 10

Produced Water, 3 Sm /day 10 / 50

- / 0.5

10

10 / 50

0.1 / 1.5

1 / 20

20 / 100

Palatana Terminal The following table– 4.2.1 gives the capacity of Palatana terminal: Table – 4.2.1: Capacity of Palatana Terminal Sr. No.

Item

1

Palatana Terminal

Capacity Min. / Max. Gas, Condensate, 3 MMSCMD Sm /day 2.65 / 3.5

1.5 / -

Remarks Produced Water, 3 Sm /day -

Process Parameters

The process parameters for the various streams involved are as follows: Min Temperature

:

2°C

Max Temperature

:

45°C

Min Operating Pressure

:

1 kg/cm2g

Max Operating Pressure

:

80 kg/cm2g

Mole Fraction of CO2

:

0.008

pH

:

> 6.5




5

Rev: C

Page 14 of 76

Prediction Models of Pipeline Corrosion Several prediction models have been developed for CO2 corrosion of oil and gas pipelines. The models have very different approaches in accounting for oil wetting and the effects of protective corrosion films, and this can produce significant differences in behaviour between the models. Some of the models have a very strong effect of oil wetting for certain flow conditions, while others do not consider oil wetting effects at all. Some models include strong effects of protective iron carbonate films, especially at high pH value or high temperature. The models are correlated to different laboratory data and, in some cases, also to field data from the individual company. It is important to understand how the corrosion prediction models handle especially the effects of oil wetting and protective corrosion films when the models are used for corrosion evaluation of wells and pipelines. Most of the models cannot be used in situations where H2S or organic acids dominate the corrosion process. An important aspect in corrosion evaluation of oil and gas wells and pipelines is to obtain a realistic estimate of the actual pH value in the water phase. When formation water is produced it is important to obtain good water analysis data, especially with respect to bicarbonate and organic acids. The actual pH value must be calculated from the CO2 and H2S partial pressure, temperature, bicarbonate content in the water and ionic strength. When only condensed water is present the dissolved corrosion products may increase the pH value significantly. Corrosion caused by CO2 in presence of water, and in absence of sulphide, is called sweet corrosion In the absence of moisture in CO2, it is a non-corrosive gas. When dissolved in water it forms carbonic acid which leads to a decreased pH of the solution and thereby increased corrosivity. Following other models were reviewed for calculating Corrosion rate in Oil and Gas Pipelines and found not suitable because of following reasons...

5.1

DeWard Includes the effect of temperature and partial pressure of CO2 and not does not give any consideration for pH

5.2

Cormed The CORMED prediction mode, which qualitatively estimates the probability of corrosion attack, is based on a detailed analysis. The model takes the CO2 partial pressure, in-situ pH, Ca+2 concentration and the amount of acetic acid which does matches to streams.

5.3

Lipucorr This Model is used where H2S dominates the corrosion but our service is sweet hence this model is not applicable.




5.4

Rev: C

Page 15 of 76

Hydrocorr Inhouse model of SHELL.

5.5

Casandra Involves Slug Flow i.e. A multiphase-fluid flow regime characterized by a series of liquid plugs (slugs) separated by a relatively large gas pockets. In vertical flow, the bubble is an axially symmetrical bullet shape that occupies almost the entire cross-sectional area of the tubing. The resulting flow alternates between high-liquid and high-gas composition.

5.6

Predict This Model is used where H2S and acetic acid dominates the corrosion but our service is sweet and no formation of acids hence this model is not applicable.

5.7

CorPos This Model is used where H2S dominates the corrosion but our service is sweet hence this model is not applicable.

5.8

NORSOK 506 It includes the effect of pH, temperature and partial pressure of CO2 .In our case pH is not low hence this model is not applicable In our case the pH Value is more than 6.5 hence pH is not to be considered and here Deward is the Model which includes the effect of temperature and partial pressure of CO2 only and does not give any consideration for pH. Hence, DEWARD has been selected for calculation of corrosion rate.




6

Rev: C

Page 16 of 76

NACE Guidelines and Our Calculation Model As per NACE Corrosivity evaluations in hydrocarbon systems, Evaluation of corrosivity should include following parameters at minimum…

• • • • • • • • •

CO2-content, H2S-content, Oxygen content and content of other oxidizing agents, Operating temperature and pressure, Organic acids, pH, Halide, metal ion and metal concentration, Velocity, flow regime and sand production, Biological activity, Condensing conditions.

From the criteria mentioned above, Following are the status of considerations which has been taken care in Calculation of corrosion allowance Table 6.1 Criteria considered for Calculation of corrosion allowance Criteria

Consideration

Remarks

CO2-content Oxygen content Content of other oxidizing agents, Operating temperature and pressure,

Yes No No Yes

As per DeWard Model Not applicable Not applicable As per DeWard Model

Organic acids, pH H2S-content Halide, metal ion and metal concentration, Velocity, flow regime Sand production, Biological activity, Condensing conditions.

No Yes No Yes No No No

Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable Not applicable

The table shown above is enough that NACE guidelines has been fulfilled to calculate the corrosion allowance




7

Rev: C

Page 17 of 76

Corrosion The Starting point for any materials selection exercise is to examine the suitability of carbon steel. Only if the corrosion study indicates that the cost of achieving a viable working life from carbon steel is likely to be excessive should attention be directed to more expensive materials. (a)

CO2 Corrosion

It will be noted that the produced hydrocarbons contain CO2 in almost all the streams shown in PFDs Theoretical considerations predicated that corrosion rates would be a function of pH, which in turn would be a function of the partial pressure of carbon dioxide (PCO2). The measured the corrosion rates for Carbon steel in carbonic acid/brine solution in laboratory tests. From these results a relationship was developed between PCO2 and the temperature. The equation has recently been revised and is now:

LogV

=

5.8 +

1710 T

+

0.67log(pCO 2 )

(1.1)

Where V = predicted corrosion rate for carbon steel (mm/y)* T = temperature pCO2 = Partial Pressure of CO2 It is widely believed that Equation 1.1 gives a pessimistic estimate of corrosion rate, and this is often confirmed by field experience. However, there is also evidence that field data sometimes exceed the predictions of the equation by a factor of three or more at elevated temperature (60°C) and high flow rate DeWaard at al have gone some way towards resolving these difficulties. (b)

Effect of Oil

It is said that crude oil in a flow line can have a beneficial effect on corrosion by CO2 There are three reasons: - The steel becomes hydrophobic (oil-wetted). - The oil may contain natural corrosion inhibitors. - Providing the flow rate is sufficiently high, the potentially corrosive water will be dispersed in the oil, i.e. no water drop-out occurs.




Rev: C

Page 18 of 76

Corrosion allowance calculated in this report are based on worst situation, without taking wetting factor into account, but in some places it is adjusted (adjustment is <1mm Corrosion allowance for 25 years) considering some oil wetting into account. (c)

Effect of Temperature

A real moderating effect on the predicted corrosion rate is the possible formation of protective corrosion product films, in practice, carbonic acid solution will always deposit such films on steel, but these are not necessarily protective. At temperature above about 60°C the film becomes progressively more protective and adherent. Thus the corrosion rate increases with temperature until a temperature is reached (the scaling temperature) where the protective films begin to form, where the corrosion rate decreases once more. The scaling temperature (Tscale) is given by de Waard et al as:

T scale

=

2400 6.7 + 0.6 log(CO 2 )

(1.2)

Of course, the continuity and protectiveness of the corrosion product will be adversely affected by high fluid flow rates with the result that Tscale will be flow dependent. In our case this is not applicable as scaling temperature is much above than design temperature. (d)

Effect of pH

There are a variety of reasons why the corrosion rate might exceed the predictions of equation 1.1. The most important is the effect of pH. The equation was developed from steady state corrosion rate data determined under conditions where the ferrous ion (Fe2+) concentration of the solution was at the value needed for iron carbonate (FeCO3) and/or magnetite (Fe3O4) saturation. This pH is higher than the value produced by the dissolution of CO2 in water at the pCO2 and temperature prevailing in the dissolution of CO2 in water at the pCO2 and temperature prevailing in the process stream. That is, until any liquid water present is saturated with Fe2+, the corrosion rate will be higher than that predicted by equation 1.1. Conversely, it is equally true that if the pH exceeds the saturation value (because of the dissolution of alkaline buffering salts, for example), the corrosion rate will be lower. The pH due to dissolution of CO2 in water is given by: pH CO2 = 3.71 + 0.00417t – 0.5 log (pCO 2)

(1.3)

where t is the temperature (°C) P:\Andheri\IndiaProject\Kazstroy-ONGC-Tripura\09 Document Control\Outside Services\Mat Selection-CAPetrochem\From Petrochem\Rev. C Final\Editable\Final MSR Rev. C.doc



Rev: C

Page 19 of 76

The pH for saturation with magnetite is:

pHmag = 1.36 +

1307 t

−

0.17 log(CO 2 )

(1.4)

and for iron carbonate: pHcarb = 5.4 – 0.66 log (pCO 2)

(1.5)

As long as the pH remains lower than the lowest pH given by equation (1.4) or (1.5) the solution will be unsaturated with Fe2+ and the corrosion rate will exceed that given by equation 1.1. This adverse effect can be accounted for by the application of a factor (FpH) to equation 1.1: log FpH = 0.32 ( pHsat – pHact)

(1.6)

where pHsat is the lower of the pH values given by equations (1.4) and (1.5) and pHact is the actual pH. In the absence of a measured value for pHact, pH CO2 (equation 1.6) may be calculated and used. In many respects it is the more reliable value. In our case actual pH is more than 6.5 hence FpH can not exceed 1 hence no additional corrosion allowance to be added to basic equation 1.1. Please refer Annexure – I for sample Calculation




8

Rev: C

Page 20 of 76

Methods of controlling corrosion There are various methods of mitigating corrosion some of them are:

8.1

-

Corrosion inhibitors

-

Hydrate preventers

-

Reduction of water wetting

-

Increasing pH

-

Reducing CO2 partial pressure

-

Selection of materials

Use of Corrosion Inhibitors: Corrosion control of carbon steel pipelines is often managed by the use of corrosion inhibitors. These are organic molecules that are added in parts per million (ppm) levels and form surface layers that reduce the corrosion reaction on the steel. Different inhibitors are used depending on the actual conditions in each pipeline. Selection and qualification of inhibitors in the laboratory prior to implementation in the field is essential and, most often, dedicated laboratory experiments will have to be performed with candidate inhibitors for each field or pipeline. A number of factors may influence inhibition in multiphase pipelines. Factors such as temperature, water-oil partitioning, water chemistry and flow conditions have been widely studied. Less attention has been paid to factors such as the composition and microstructure of the steel, the type of corrosion products formed on the steel surfaces, inhibitor adsorption on suspended particles in the produced water and inhibitor accumulation on gas bubbles, oil/water droplets and emulsions. It has been difficult to account for the effects of multiphase flow on corrosion inhibition in laboratory screening tests. We are using this method to prevent corrosion where ever uninhibited corrosion allowance is exceeding 7 mm. Efficiency of Corrosion Inhibitor is taken 75% (However NORSOK code allows Efficiency of Corrosion Inhibitor from 0% ~ 100%) with an availability of 95% i.e. Inhibitor is not available for 15 months spread in 25 years.

8.2

Hydrate preventers: Glycols can be used as hydrate preventer for which calculation can be done in similar way as done in inhibitor injection.

8.3

The pH stabilisation technique: The pH stabilisation technique can be used for corrosion control in wet gas pipelines when no or very little formation water is transported in the pipeline. This technique is based on precipitation of protective corrosion product films on the steel surface by adding pH-stabilising agents to increase the pH value of the water phase in the pipeline. The pH-stabilisation technique has been taken into use in several wet gas condensate pipelines and is currently being considered for several new fields. This technique is very well suited for use in pipelines where glycol is used as hydrate preventer, as the pH stabiliser will be regenerated together with the glycol. This means that there is very little need for replenishment of the pH stabiliser.




Rev: C

Page 21 of 76

Experiments for qualification of the pH stabilization technique at the IFE have shown that protective films form in a short time at temperatures between 40°C and 100°C, reducing the corrosion rate to less than 0.1mm/y. At lower temperatures around 20°C, the iron carbonate precipitation is very slow and it may take several months to obtain protective corrosion films. Since the initial corrosion rate is low at 20°C and with a high pH value, it is acceptable to wait a few months for a protective corrosion film to form When glycol is used to prevent hydrate formation, it is convenient to transport and inject the pH stabilizer together with the glycol. The pH stabiliser is regenerated together with the glycol and the consumption is therefore very low. However, under some conditions with high CO2 partial pressure, the demand for pH stabiliser can be so high that it is not possible to dissolve enough pH stabilisers in the glycol. The pH-stabilisation technique cannot be used for pipelines carrying large quantities of formation water due to formation of carbonate scale at the elevated pH value. Replenishment of pH stabiliser may become costly for systems where even small amounts of formation water are carried over from the offshore processing. When the glycol is regenerated, the salts will be accumulated in the regenerated glycol. When salts are removed, the pH stabiliser will usually also be removed, and even a small formation water carry-over may then require considerable replenishment of the pH stabiliser. The pH-stabilisation technique has been used mostly for wet gas pipelines without any H2S in the gas, but is now being taken into use also for pipelines with considerable amounts of H2S in addition to CO2. Here, the corrosion product depositing on the surface will be iron sulphide instead of iron carbonate. These sulphide films have different protective properties than the iron carbonate films forming in sweet systems. Localised corrosion in the form of pitting is the critical factor in H2S-containing systems. In our case pH is greater than 6.5 hence this technique is not relevant.

8.4

Reduction of Water Wetting: Special Inhibitors are to be used, in our case some consideration is given to oil wetting due some oil content in Wet Streams. But this consideration is <1mm and is used only round down the Corrosion Allowance by some fraction of 1mm.

8.5

Reducing CO2 partial pressure: Reducing CO2 partial pressure is not possible in our case

8.6

Selection of materials: Use of CRAs include huge capital cost hence where ever Inhibited Corrosion allowance is exceeding 6.0 mm we have used Corrosion Resistant Alloys (CRAs)




9

Rev: C

Page 22 of 76

Corrosivity evaluation, corrosion protection and Material Selection As per Para 4.3 of NORSOK standard M-001. A corrosion allowance of 3 mm is generally recommended for carbon steel piping, unless higher corrosion allowances are required. NORSOK is a recommended practice for the evaluation of CO2 corrosion. A corrosion evaluation with inhibition should be based on the Corrosion inhibitor availability, considered as the time the inhibitor is present in the system, at a concentration at or above the minimum dosage A.

Percentage availability (A %) is defined as: A % = 100 x (inhibitor available time)/(lifetime)

B.

Corrosion allowance (CA) = (the inhibited corrosion allowance) + (the uninhibited corrosion allowance)

C.

CA = (CRinhib x A %/100 x lifetime) + (CRuninhib x {1 – A %/100} x lifetime)

where CRinhib = inhibited corrosion rate. CRuninhib = uninhibited corrosion rate (from DEWARD or other model). Corrosion Summary for various streams is as follows. This summary is based on 75% Inhibitor Efficiency and 95% availability



Rev: C


Page 23 of 76

Table 9.1 A : Corrosion Allowances Calculated for Konaban GGS (4 Cases)

Stream Number

Stream Description

Corrosion Allowance (Uninhibited) for 25 years

Corrosion Allowance (Inhibited) for 25 years with 75% efficiency

Net Corrosion Allowance with 95% Availability

Recommended Corrosion Allowance

KONABAN GGS CASE-1: WELL FTHP 154 KG/CM2G, INLET MANIFOLD AT 80 KG/CM2G AND 20°C 1

Production Manifold

16.68

4.17

4.8

4.75

2

IDBH Outlet

48.03

12.01

13.82

SS316L

3

To HP Separator Package

11.03

2.76

3.18

3

4

Produced Gas To Gas Scrubber

DRY GAS

NR

NR

3

5

Condensate From HP Production Separator

1.37

NR

NR

3

6

Effluent From HP Production Separator

1.47

NR

NR

3

7

Produced Gas From Scrubber

DRY GAS

NR

NR

3

8

Condensate From Gas Scrubber

1.35

NR

NR

3

9

Gas To Palatana

DRY GAS

NR

NR

3

10

To Instrument Gas Header

DRY GAS

NR

NR

3

11

Total Condensate To Condensate Stabiliser

1.37

NR

NR

3

12

Gas From Condensate Stabilser To Canteen

DRY GAS

NR

NR

3

13

Condensate To Storage Tank

1.36

NR

NR

3

14

Condensate Transfer Pump Suction

1.36

NR

NR

3

15

Condensate Transfer Pump Discharge

1.36

NR

NR

3



Rev: C


Stream Number

Stream Description

Page 24 of 76





DRY GAS

NR

NR

3

16

Gas from Effluent Water Stabiliser to Canteen

17

Effluent Water To Storage

1.48

NR

NR

3

18

Effluent Loading Pump Suction

1.48

NR

NR

3

19

Effluent Loading Pump Discharge

1.48

NR

NR

3

20

CI Pump Suction

CI

NR

NR

3

21

CI Pump Discharge

CI

NR

NR

3

22

To Gas Dryer Package

DRY GAS

NR

NR

3

23

Instrument Gas To Receiver

DRY GAS

NR

NR

3

24

Condensate From Gas Dryer Package

4.3

NR

NR

4.5

25

Instrument Gas Header

DRY GAS

NR

NR

3

26

Condensate From Instrument Gas Receiver

4.3

NR

NR

4.5

27

Instrument Gas to New Konaban GGS

DRY GAS

NR

NR

3

28

Instrument Gas to Existing Konaban GGS

DRY GAS

NR

NR

3

29

Condensate To OWS Header

4.3

NR

NR

4.5

30

Gas To Fuel Gas Scrubber

DRY GAS

NR

NR

3

31

Fuel Gas From Fuel Gas Scrubber

DRY GAS

NR

NR

3

32

Condensate From Fuel Gas Scrubber

0.97

NR

NR

3



Rev: C


Page 25 of 76





33

Fuel Gas To Existing Konaban GGS Fuel Gas Header

DRY GAS

NR

NR

3

34

Fuel Gas To IDBH

DRY GAS

NR

NR

3

35

Fuel Gas To Flare Package

DRY GAS

NR

NR

3

36

Fuel Gas To Flare Header Purging

DRY GAS

NR

NR

3

37

Fuel Gas To Evaporation Pit Package

DRY GAS

NR

NR

3

38

Gas From Existing Konaban GGS

DRY GAS

NR

NR

3

39

Gas From Existing LP Sep. & Water Flash Drum

DRY GAS

NR

NR

3

Stream Number

Stream Description


Production Manifold

39.48

9.87

11.36

SS316L

2

IDBH Outlet

48.03

12.01

13.82

SS316L

3


11.08

2.77

3.19

3

4


DRY GAS

NR

NR

3

5


1.37

NR

NR

3

6


1.48

NR

NR

3

7


DRY GAS

NR

NR

3

8


1.36

NR

NR

3

9

Gas To Palatana

DRY GAS

NR

NR

3



Rev: C


Stream Number

Stream Description

Page 26 of 76





DRY GAS

NR

NR

3

10


11


1.37

NR

NR

3

12


DRY GAS

NR

NR

3

13


1.36

NR

NR

3

14


1.36

NR

NR

3

15


1.36

NR

NR

3

16


DRY GAS

NR

NR

3

17


1.48

NR

NR

3

18


1.48

NR

NR

3

19


1.48

NR

NR

3

20

CI Pump Suction

CI

NR

NR

3

21

CI Pump Discharge

CI

NR

NR

3

22


DRY GAS

NR

NR

3

23


DRY GAS

NR

NR

3

24


4.33

NR

NR

4.5

25


DRY GAS

NR

NR

3

26


4.33

NR

NR

4.5

27


DRY GAS

NR

NR

3



Rev: C


Stream Number

Stream Description

Page 27 of 76





DRY GAS

NR

NR

3

4.33

NR

NR

4.5

28


29


30


DRY GAS

NR

NR

3

31


DRY GAS

NR

NR

3

32


0.98

NR

NR

3

33


DRY GAS

NR

NR

3

34

Fuel Gas To IDBH

DRY GAS

NR

NR

3

35


DRY GAS

NR

NR

3

36


DRY GAS

NR

NR

3

37

Fuel Gas TO Evaporation Pit Package

DRY GAS

NR

NR

3

38


DRY GAS

NR

NR

3

39


DRY GAS

NR

NR

3


Production Manifold

8.85

2.22

2.56

3

2

IDBH Outlet

24.72

6.18

7.11

SS316L

3


22.44

5.61

6.46

6

4


DRY GAS

NR

NR

3



Rev: C


Page 28 of 76




Stream Number

Stream Description


5


2.86

NR

NR

3

6


2.98

NR

NR

3

7


DRY GAS

NR

NR

3

8


2.83

NR

NR

3

9

Gas To Palatana

DRY GAS

NR

NR

3

10


DRY GAS

NR

NR

3

11


2.85

NR

NR

3

12


DRY GAS

NR

NR

3

13


2.85

NR

NR

3

14


2.85

NR

NR

3

15


2.85

NR

NR

3

16


DRY GAS

NR

NR

3

17


2.99

NR

NR

3

18


2.99

NR

NR

3

19


2.99

NR

NR

3

20

CI Pump Suction

CI

NR

NR

3

21

CI Pump Discharge

CI

NR

NR

3

22


DRY GAS

NR

NR

3



Rev: C


Stream Number

Stream Description

Page 29 of 76





23


DRY GAS

NR

NR

3

24


9.45

2.37

2.73

3

25


DRY GAS

NR

NR

3

26


9.45

2.37

2.73

3

27


DRY GAS

NR

NR

3

28


DRY GAS

NR

NR

3

29


9.45

2.37

2.73

3

30


DRY GAS

NR

NR

3

31


DRY GAS

NR

NR

3

32


2.16

NR

NR

3

33


DRY GAS

NR

NR

3

34

Fuel Gas To IDBH

DRY GAS

NR

NR

3

35


DRY GAS

NR

NR

3

36


DRY GAS

NR

NR

3

37


DRY GAS

NR

NR

3

38


DRY GAS

NR

NR

3

39


DRY GAS

NR

NR

3




Rev: C

Page 30 of 76

KONABAN GGS CASE-4: WELL FTHP 80 KG/CM2G, INLET MANIFOLD AT 30 KG/CM2G AND 40°C Corrosion Allowance (Inhibited) for 25 years with 75% efficiency



Stream Number

Stream Description


1

Production Manifold

20.9

5.23

6.02

6

2

IDBH Outlet

24.72

6.18

7.11

SS316L

3


22.44

5.61

6.46

6

4


DRY GAS

NR

NR

3

5


2.85

NR

NR

3

6


2.98

NR

NR

3

7


DRY GAS

NR

NR

3

8


2.83

NR

NR

3

9

Gas To Palatana

DRY GAS

NR

NR

3

10


DRY GAS

NR

NR

3

11


2.85

NR

NR

3

12


DRY GAS

NR

NR

3

13


2.84

NR

NR

3

14


2.84

NR

NR

3

15


2.84

NR

NR

3

16


DRY GAS

NR

NR

3

17


2.99

NR

NR

3




Stream Number

Stream Description

Rev: C

Page 31 of 76





18


2.99

NR

NR

3

19


2.99

NR

NR

3

20

CI Pump Suction

CI

NR

NR

3

21

CI Pump Discharge

CI

NR

NR

3

22


DRY GAS

NR

NR

3

23


DRY GAS

NR

NR

3

24


9.45

2.37

2.73

3

25


DRY GAS

NR

NR

3

26


9.45

2.37

2.73

3

27


DRY GAS

NR

NR

3

28


DRY GAS

NR

NR

3

29


9.45

2.37

2.73

3

30


DRY GAS

NR

NR

3

31


DRY GAS

NR

NR

3

32


2.16

NR

NR

3

33


DRY GAS

NR

NR

3

34

Fuel Gas To IDBH

DRY GAS

NR

NR

3




Stream Number

Stream Description

Rev: C

Page 32 of 76





35


DRY GAS

NR

NR

3

36


DRY GAS

NR

NR

3

37


DRY GAS

NR

NR

3

38


DRY GAS

NR

NR

3

39


DRY GAS

NR

NR

3




Stream Number

Stream Description


Rev: C

Page 33 of 76




KONABAN GGS CORROSION SUMMARY 1

Production Manifold

SS316L

2

IDBH Outlet

SS316L

3


4


3

5


3

6


3

7


3

8


3

6 (With Inhibitor)

SEE DETAIL CORROSION SUMMARY (TABLE – 9.1 B) FOR ALL 4 CASES IN KONABAN

9

Gas To Palatana

3

10


3

11


3

12


3

13


3

14


3

15


3

16


3

17


3




Stream Number

Stream Description


Rev: C

Page 34 of 76




18


3

19


3

20

CI Pump Suction

3

21

CI Pump Discharge

3

22


3

23


3

24


3 (With Inhibitor)

25


26


27


28


29


30


3

31


3

32


3

33


3

34

Fuel Gas To IDBH

3

35


3

3

SEE DETAIL CORROSION SUMMARY (TABLE – 9.1B) FOR ALL 4 CASES IN KONABAN

3 (With Inhibitor) 3 3 3 (With Inhibitor)




Stream Number

Stream Description

36


37


38


39



Rev: C

Page 35 of 76




3

SEE DETAIL CORROSION SUMMARY (TABLE – 9.1B) FOR ALL 4 CASES IN KONABAN

3 3 3



Rev: C

Page 36 of 76


Table 9.1 B: Corrosion Summary for Konaban (4 Cases) CASE I FOR 25 YEAR Stream Number

Stream Description

CASE II FOR 25 YEAR

CA Inhibit ed

Net CA 95% Availabil ity

Recomme nded CA

CA Uninhibi ted

mm

mm

mm

mm

CA Uninhibi ted

CASE III FOR 25 YEAR

CA Inhibit ed

Net CA 95% Availabili ty

Recomm ended CA

CA Uninhibi ted

CA Inhibited

mm

mm

Mm

mm

Mm

mm

CASE IV FOR 25 YEAR

Net CA 95% Availa bility

Recomm ended CA

CA Uninhib ited

mm

mm

mm

CA Inhibite d


Recomme nded CA

MAX RECOM MEDED CA

mm

mm

mm

mm

1

Production Manifold

16.68

4.17

4.8

4.75

39.48

9.87

11.36

SS316L

8.85

2.22

2.5 6

3

20.9

5.23

6.02

6

SS316L

2

IDBH Outlet

48.03

12.01

13.82

SS316L

48.03

12.01

13.82

SS316L

24.72

6.18

7.11

SS316L

24.72

6.18

7.11

SS316L

SS316L

3


11.03

2.76

3.18

3

11.08

2.77

3.19

3

22.44

5.61

6.46

6

22.44

5.61

6.46

6

6

4


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

5


1.37

NR

NR

3

1.37

NR

NR

3

2.86

NR

NR

3

2 .85

NR

NR

3

3

6


1.47

NR

NR

3

1.48

NR

NR

3

2.98

NR

NR

3

2 .98

NR

NR

3

3

7


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

8


1.35

NR

NR

3

1.36

NR

NR

3

2.83

NR

NR

3

2 .83

NR

NR

3

3

9

Gas To Palatana

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

P:\Andheri\IndiaProject\Kazstroy-ONGC-Tripura\09 Document Control\Outside Services\Mat Selection-CA-Petrochem\From Petrochem\Rev. C Final\Editable\Final MSR Rev. C.doc


Rev: C

Page 37 of 76



Stream Description

CASE II FOR 25 YEAR

CA Inhibit ed


Recomme nded CA

CA Uninhibi ted

mm

mm

mm

mm

Dry Gas

NR

NR

CA Uninhibi ted


CASE IV FOR 25 YEAR


Recomm ended CA

CA Uninhib ited

CA Inhibit ed


Recomm ended CA

CA Uninhibi ted

CA Inhibited

CA Inhibite d


Recomme nded CA

MAX RECOM MEDED CA

mm

mm

Mm

mm

Mm

mm

mm

mm

mm

mm

mm

mm

mm

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

10


11


1.37

NR

NR

3

1.37

NR

NR

3

2.85

NR

NR

3

2 .85

NR

NR

3

3

12


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

13


1.36

NR

NR

3

1.36

NR

NR

3

2.85

NR

NR

3

2 .84

NR

NR

3

3

14


1.36

NR

NR

3

1.36

NR

NR

3

2.85

NR

NR

3

2 .84

NR

NR

3

3

15


1.36

NR

NR

3

1.36

NR

NR

3

2.85

NR

NR

3

2 .84

NR

NR

3

3

16


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

17


1.48

NR

NR

3

1.48

NR

NR

3

2.99

NR

NR

3

2 .99

NR

NR

3

3

18


1.48

NR

NR

3

1.48

NR

NR

3

2.99

NR

NR

3

2 .99

NR

NR

3

3



Rev: C

Page 38 of 76


Table 9.1 B: Corrosion Summary for Konaban (4 Cases) CASE I FOR 25 YEAR

CASE II FOR 25 YEAR

CA Inhibit ed


Recomme nded CA

CA Uninhibi ted

mm

mm

mm

mm

1.48

NR

NR

CI Pump Suction

Dry Gas

NR

21

CI Pump Discharge

Dry Gas

22


23


24


CASE IV FOR 25 YEAR


Recomm ended CA

CA Uninhib ited

CA Inhibit ed


Recomm ended CA

CA Uninhibi ted

CA Inhibited

mm

mm

Mm

mm

Mm

mm

mm

mm

3

1.48

NR

NR

3

2.99

NR

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR


4.3

NR

NR

4.75

4.33

NR

25


Dry Gas

NR

NR

3

Dry Gas

26


4.3

NR

NR

4.75

27


Dry Gas

NR

NR

3

Stream Number

Stream Description

19


20

CA Uninhibi ted

CA Inhibite d


Recomme nded CA

MAX RECOM MEDED CA

mm

mm

mm

mm

mm

3

2 .99

NR

NR

3

3

NR

3

Dry Gas

NR

NR

3

3

NR

NR

3

Dry Gas

NR

NR

3

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

NR

4.75

9.45

2.37

2.73

3

9.45

2.37

2.73

3

4.75

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

4.33

NR

NR

4.75

9.45

2.37

2.73

3

9.45

2.37

2.73

3

4.75

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3



Rev: C

Page 39 of 76


Table 9.1 B: Corrosion Summary for Konaban (4 Cases) CASE I FOR 25 YEAR

CASE II FOR 25 YEAR

CA Inhibit ed


Recomme nded CA

CA Uninhibi ted

mm

mm

mm

mm

Dry Gas

NR

NR

4.3

NR


Dry Gas

31


32


33


CASE IV FOR 25 YEAR


Recomm ended CA

CA Uninhib ited

CA Inhibit ed


Recomm ended CA

CA Uninhibi ted

CA Inhibited

mm

mm

Mm

mm

Mm

mm

mm

mm

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

4.75

4.33

NR

NR

4.75

9.45

2.37

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

0.97

NR

NR

3

0.98

NR

NR


Dry Gas

NR

NR

3

Dry Gas

NR

34

Fuel Gas To IDBH

Dry Gas

NR

NR

3

Dry Gas

35


Dry Gas

NR

NR

3

36


Dry Gas

NR

NR

3

Stream Number

Stream Description

28


29


30

CA Uninhibi ted

CA Inhibite d


Recomme nded CA

MAX RECOM MEDED CA

mm

mm

mm

mm

mm

3

Dry Gas

NR

NR

3

3

2.73

3

9.45

2.37

2.73

3

4.75

NR

NR

3

Dry Gas

NR

NR

3

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

3

2.16

NR

NR

3

2 .16

NR

NR

3

3

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

0

NR

NR

3

0

NR

NR

3

0

NR

NR

3

3



Rev: C

Page 40 of 76



Stream Description

CA Uninhibi ted

CASE II FOR 25 YEAR

CA Inhibit ed


Recomme nded CA

CA Uninhibi ted


CA Inhibit ed


Recomm ended CA

CA Uninhibi ted

CA Inhibited

CASE IV FOR 25 YEAR


Recomm ended CA

CA Uninhib ited

CA Inhibite d


Recomme nded CA

MAX RECOM MEDED CA

mm

mm

mm

mm

mm

mm

Mm

mm

Mm

mm

mm

mm

mm

mm

mm

mm

mm

37


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

38


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3

39


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

3




Rev: C

Page 41 of 76

Table 9.1C Corrosion Summary For Utilities (Konaban)

Stream Number

50 51 52 53 54 55 56 57

58 59 60 61

62

63

64

Stream Description

Feed From New Konaban GGS to Flare KOD Flare Gas to Flare Package Condensate Transfer Pumps Suction Condensate Transfer Pump Discharge Effluent Water From Flare Package to OWS System Oily Water from New OWS Header Oily Water from Existing OWS Header Condensate From OWS to Condensate Storage Tank Effluent Water From OWS to Effluent Storage Tank Bore well Pump Dischage Service Water To Flare Package Service Water To IDBH Package Potable Water To Safety Shower & Eye Wash Package KON-A-0420 Feed From Existing Konaban GGS to Flare KOD Potable Water To Safety Shower & Eye Wash Package KON-A-0720

Corrossion Allowance (Unihibited) for 25 years

Corrossion Allowance (Ihibited) for 25 years with 75% efficiency

Net Corrossion Allowancewith 95% Availability


Mm

Mm

mm

mm

0.49

NR

NR

3

0

NR

NR

3

0.51

NR

NR

3

0.51

NR

NR

3

0

NR

NR

CS (Galv.) C.A. 0mm

2.92

NR

NR

3

2.92

NR

NR

3

2.91

NR

NR

3

0

NR

NR

3

0

NR

NR

CS (Galv.) C.A. 0mm

0

NR

NR

CS (Galv.) C.A. 0mm

0

NR

NR

CS (Galv.) C.A. 0mm

0

NR

NR

CS (Galv.) C.A. 0mm

2.2

NR

NR

3

0

NR

NR

CS (Galv.) C.A. 0mm




Rev: C

Page 42 of 76

Table 9.2 A : Corrosion Allowances Calculated for PALATANA (4 Cases)

Stream Number

Stream Description





CASE-1: WELL FTHP 154 KG/CM2G, INLET MANIFOLD AT 80 KG/CM2G AND 20°C 1

Gas From Sonamura GGS

DRY GAS

NR

NR

3

2

Gas From ADB & Konaban GGS

DRY GAS

NR

NR

3

3

To Gas Scrubber

DRY GAS

NR

NR

3

4

Gas To OTPC Power Plant

DRY GAS

NR

NR

3

5

Condensate To Condensate Stabiliser

0.99

NR

NR

3

6


0.99

NR

NR

3

7


0.99

NR

NR

3

8


0.99

NR

NR

3

9

Vent Gas

DRY GAS

NR

NR

3



DRY GAS

NR

NR

3

2


DRY GAS

NR

NR

3

3

To Gas Scrubber

DRY GAS

NR

NR

3

4


DRY GAS

NR

NR

3

5


0.99

NR

NR

3




Stream Number

Stream Description

Rev: C

Page 43 of 76





6


0.99

NR

NR

3

7


0.99

NR

NR

3

8


0.99

NR

NR

3

9

Vent Gas

DRY GAS

NR

NR

3



DRY GAS

NR

NR

3

2


DRY GAS

NR

NR

3

3

To Gas Scrubber

DRY GAS

NR

NR

3

4


DRY GAS

NR

NR

3

5


0.99

NR

NR

3

6


0.99

NR

NR

3

7


0.99

NR

NR

3

8


0.99

NR

NR

3

9

Vent Gas

DRY GAS

NR

NR

3



DRY GAS

NR

NR

3

2


DRY GAS

NR

NR

3

3

To Gas Scrubber

DRY GAS

NR

NR

3




Stream Number

Stream Description

Rev: C

Page 44 of 76





4


DRY GAS

NR

NR

3

5


0.99

NR

NR

3

6


0.98

NR

NR

3

7


0.98

NR

NR

3

8


0.98

NR

NR

3

9

Vent Gas

DRY GAS

NR

NR

3

PALATANA CASE SUMMARY 1


3

2


3

3

To Gas Scrubber

3

4


3

5


6


3

7


3

8


3

9

Vent Gas

3

SEE DETAIL CORROSION SUMMARY (TABLE – 9.2B) FOR ALL 4 CASES IN PALATANA

3



Rev: C

Page 45 of 76


Table 9.2 B : Corrosion Allowances Calculated for PALATANA (4 Cases) CASE I FOR 25 YEAR Stream Number

Stream Description

CA

Net CA

CASE II FOR 25 YEAR

Inhibite d

95% Availabilit y

Recom mende d CA

Uninhibite d

mm

mm

mm

mm

CA Uninhibite d

CA

Net CA


CA

Net CA

Inhibite d

95% Availabilit y

Recom mende d CA

Uninhibite d

Inhibited

95% Availab ility

mm

mm

mm

mm

Mm

mm

CA

CA

CASE IV FOR 25 YEAR

Inhibited

95% Availabilit y

Recom mende d CA

MAX RECO MMED ED

mm

mm

mm

mm

mm

Recom mende d CA

Uninhibite d

mm

mm

CA

CA

Net CA

1


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

3

2


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

3

3

To Gas Scrubber

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

3

4


Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

3

Dry Gas

NR

NR

NR

3

5


0.99

NR

NR

3

0.99

NR

NR

3

0.99

NR

NR

3

0.99

NR

NR

NR

3

6


0.99

NR

NR

3

0.99

NR

NR

3

0.99

NR

NR

3

0.98

NR

NR

NR

3

7


0.99

NR

NR

3

0.99

NR

NR

3

0.99

NR

NR

3

0.98

NR

NR

NR

3

8


0.99

NR

NR

3

0.99

NR

NR

3

0.99

NR

NR

3

0.98

NR

NR

NR

3



Rev: C

Page 46 of 76


CASE I FOR 25 YEAR Stream Number

Stream Description


10

Vent Gas

Net CA

Inhibite d

95% Availabilit y

Recom mende d CA

Uninhibite d

mm

mm

mm

mm

0.99

NR

NR

Dry Gas

NR

NR

CA Uninhibite d

9

CA

CASE II FOR 25 YEAR

CA

Net CA


CA

Net CA

Inhibite d

95% Availabilit y

Recom mende d CA

Uninhibite d

Inhibited

95% Availab ility

mm

mm

mm

mm

Mm

mm

3

0.99

NR

NR

3

0.99

3

Dry Gas

NR

NR

3

Dry Gas

CA

CA

CASE IV FOR 25 YEAR

Inhibited

95% Availabilit y

Recom mende d CA

MAX RECO MMED ED

mm

mm

mm

mm

mm

3

0.98

NR

NR

NR

3

3

Dry Gas

NR

NR

NR

3

Recom mende d CA

Uninhibite d

mm

mm

NR

NR

NR

NR

CA

CA

Net CA




Rev: C

Page 47 of 76

Table 9.3 : Corrosion Allowances Calculated for KUNJABAN MANIFOLDS

Stream Number

Stream Description





WELL FTHP 154 KG/CM2G AND INLET MANIFOLD AT 20°C 1

From Pig Launcher KUN-L0101

7.54

1.89

2.18

3

2


5.85

NR

NR

5.75

3


4.46

NR

NR

4.5




Rev: C

Page 48 of 76

Table 9.4 : Corrosion Allowances Calculated for ADB GGS

Stream Number

Stream Description





1

To Existing HP Header

6.51

NR

NR

6

2

To Existing Test Header

6.65

NR

NR

6

3


6.65

NR

NR

6

4

To Existing MP Header

4.46

NR

NR

4.5

5

Gas To Palatana VIA Nimbutali

DRY GAS

NR

NR

3




Rev: C

Page 49 of 76

Table 9.5 : Corrosion Allowances Calculated for SUNDALBARI MANIFOLDS

Stream Number

Stream Description





1

From Pig Launcher SUN-L0101

8.08

2.02

2.33

3

2


8.12

2.03

2.34

3

2


4.54

NR

NR

4.5




Rev: C

Page 50 of 76

Table 9.6 : Corrosion Allowances Calculated for SONAMURA GGS

Stream Number

Stream Description





1


7.71

1.93

2.22

3

2


7.79

1.95

2.25

3

3


7.79

1.95

2.25

3

4

To Existing MP Header

4.54

NR

NR

4.5

5

Gas To Palatana

DRY GAS

NR

NR

3




Rev: C

Page 51 of 76

Table 9.7 : Corrosion Allowances Calculated for NIMBUTALI JUNCTION POINT

Stream Number

Stream Description





1

Gas From Konaban GGS

DRY GAS

NR

NR

3

2

Gas From ADB GGS

DRY GAS

NR

NR

3

3

Gas To Palatana

DRY GAS

NR

NR

3

Refer Annexure – II for CORROSION CALCULATION SHEET FOR Various Streams.




Rev: C

Page 52 of 76

Wherever inhibited corrosion is written as NR (Not Required) says that stream does not require injection of corrosion inhibitor. The inhibitor availability to be used in a design calculation depends on the planned corrosion management programme, including corrosion monitoring and corrosion inhibition. Maximum inhibitor availability shall not exceed 95 %. 95 % inhibitor availability requires that a qualified inhibitor is injected from day one and that a corrosion management system is in place to actively monitor corrosion and inhibitor injection. The effect of any inhibitor depends on reservoir conditions which may change during production time. Due to complex geometries and normally high flow rates, there is an increased risk for high inhibited corrosion rates locally in process systems compared to pipelines, which will influence the need for inspection and maintenance.




10

Rev: C

Page 53 of 76

Corrosivity evaluations in hydrocarbon systems As per NORSOK Std. M-001 Evaluation of corrosivity shall as a minimum include • • • • • • • • •

CO2-content, H2S-content, Oxygen content and content of other oxidising agents, Operating temperature and pressure, Organic acids, pH, Halide, metal ion and metal concentration, Velocity, flow regime and sand production, Biological activity, Condensing conditions.

A gas is considered dry when the water dew point at the actual pressure is at least 10 °C lower than the actual operation temperature for the system. Materials for stagnant gas containment need particular attention. The inhibited corrosion rate shall, however, be documented by corrosion tests at the actual conditions or by relevant field or other test data. It should be noted that to achieve the target residual corrosion rate, high dosages of inhibitor may be required. The inhibitor availability to be used in a design calculation depends on the planned corrosion management programme, including corrosion monitoring and corrosion inhibition. The effect of any inhibitor depends on reservoir conditions which may change during production time. Use of corrosion inhibitors in process can be used provided the inhibitor in each process stream satisfies the inhibitor supplier's minimum recommended concentration for each stream and flow rate. Due to complex geometries and normally high flow rates, there is an increased risk for high inhibited corrosion rates locally in process systems compared to pipelines, which will influence the need for inspection and maintenance. Vessel materials for oil separation and gas treating systems shall be selected based on the same corrosivity criteria as for hydrocarbon piping systems. Vessels manufactured in solid CRAs, internally CRA clad or weld overlaid, will not need additional internal corrosion protection systems. Galvanic corrosion between CRA equipment and the vessel wall in internally paint coated (lined) carbon steel vessels shall be addressed in case of coating damages. As a minimum CRA support brackets shall be painted. Please refer Annexure III for the Material Selection Diagrams of different facilities. P:\Andheri\IndiaProject\Kazstroy-ONGC-Tripura\09 Document Control\Outside Services\Mat Selection-CAPetrochem\From Petrochem\Rev. C Final\Editable\Final MSR Rev. C.doc



11

Rev: C

Page 54 of 76

Conclusion Unless otherwise specified on the other project specifications, carbon steel pipes shall have min 3 mm corrosion allowance to all pressure retaining parts and all surfaces of nonremovable internals exposed to the process fluid, no Corrosion Allowance is permitted for Austenitic Stainless steel. Corrosion allowance can exceed 3 mm but not more than 6mm for carbon steel. Where ever calculated Corrosion allowance is exceeding 7 mm we need to provide corrosion inhibitors. Where ever Corrosion Allowance is exceeding 6 mm but less than 7 mm we have rounded down the Corrosion Allowance to 6 mm taking some oil wetting into consideration as injecting Corrosion Inhibitor for saving less than 1mm Corrosion Allowance is not economical. If Inhibited Corrosion Allowance (with 75% inhibiting efficiency and 95% availability) is also exceeding 7 mm then MOC is changed to SS316L. When ever Inhibited Corrosion Allowance is exceeding 6 mm but less than 7 mm we have rounded down the Corrosion Allowance to 6 mm taking some oil wetting into consideration which shall support inhibitor. Selecting SS316L for saving less than 1mm Corrosion Allowance is not economical. Vendor recommendations are attached in Annexure – IV for Inhibitor details. Table – 11.1 : Corrosion inhibitors requirement Summary

Area

Stream No. 3

KONABAN

KUNJABAN SONAMURA

SUNDALBARI

Description

Corrosion inhibitor Flow Rate, LPH HOLD-1

26

To HP Separator Condensate From Gas Dryer Package (NOTE-1) Condensate From Instrument Gas Receiver (NOTE-1)

29

Condensate To OWS Header (NOTE-1)

HOLD-1

1

FROM PIG LAUNCHER KUN-L-0101

HOLD-1

1


HOLD-1

2


HOLD-1

3


HOLD-1

1

FROM PIG LAUNCHER SUN-L-0101

HOLD-1

2

FROM PIG LAUNCHER SUN-L-0102

HOLD-1

24

HOLD-1 HOLD-1

Notes:




1.

Rev: C

Page 55 of 76

The injection point indicated at the downstream of Gas Scrubber (KON-S-0301) stream no. 7 is not required in view of the calculated corrosion allowance being very less. This corrosion inhibitor point shall be shifted to the locations mentioned in table 11.1 above.

SS316L is recommended at Production manifold (Stream 1), and IDBH Outlet (Stream 2) for Konaban GGS. Rest for all the streams CS material is recommended with CA as mentioned in Tables 9.1 to 9.7. Valves MOC shall be as per following table 11.2

Table – 11.2 : Valve MOC Recommendation Criteria

Rating

Body / Trim

Uninhibited CA < 3mm or

Cl.150 , Cl. 300

CS / Trim 1

>= Cl.600

CS / Trim 5

Uninhibited CA > 3mm and stream MOC CS

Cl.150 , Cl. 300

CS / Trim 12

Uninhibited CA > 3mm and

>= Cl.600

CS / Trim 16

Stream MOC SS316

Cl.150 , Cl. 300

SS316 L / Trim 12

Stream MOC SS316

>= Cl.600

SS316 L / Trim 16

Inhibitor lines

>= Cl.600

SS04 / Trim 10

Inhibitor lines

>= Cl.600

SS304 / Trim 15

Dry Gas Uninhibited CA < 3mm or Dry Gas

stream MOC CS

Trim No. Shall be as per API600




12

Rev: C

Page 56 of 76

Bibliography: 1.

NORSOK Std M-001 Rev4 Aug2004

: Material selection

2.

Corrosion Vol. 59, No. 8

: NACE Paper on CO2 Corrosion in Oil & Gas Production

3.

IFE Paper by Rolf Nyborg

: Corrosion Control in Oil and Gas Pipelines

4.

NTNU Paper

: Corrosion in Hydro Carbon systems

5.

NACE Std. ISO 51516-1

: Sulphide Stress Cracking Resistance Metallic

Material for Oil Field Equipment 6.

NACE Std. : NACE RP0775

: Preparation & Installation of Corrosion Coupons and interpretation of test data in Oilfield Operations

7.

Corrosion and Protection

: By Einar Bardal

8. 9. 10.

NACE paper no. 69 API 610 API 600

: NACE Paper on CO2 Corrosion de Waard : Pumps : Valves




13

Rev: C

Page 57 of 76

List of Holds : 1.

Corrosion Inhibitor Flow Rates Based on Ve ndor Information (MMPL).

2.

Vendor Information for Corrosion Inhibitors (MMPL).



Rev: C


14

Page 58 of 76

References: 1.

Process design Basis Doc No. UkonPGP/COM/R/DBS/001

2.

Equipment List DOC NO: Ukon/COM/PRO/SCH/3/A/001

3.

Process Flow Diagrams (PFD) as per below list:

Sr. No.

Drawing No.

Rev

1

UKON-KON-PRO-PFD-0-A-100

D

Inlet Manifold, IDBH and HP Separator

2


D

Gas Scrubber And Metering

3


D

Condensate Stabilizer, Storage And Loading

4


D

Effluent Stabilizer, Storage And Loading

5


D

Corrosion Inhibitor Dosing System

6


D

Instrument Gas System

7


D

Fuel Gas System

8

UKON-KON-PRO-PFD-0-A-107 Sheets 1 to 4

D

Heat and Mass Balance Drawings

9

UKON-KON-PRO-UFD-0-A-100

C

Borewell Pump

10


C

Flare System

11


C

OWS and Evaporation Pit

12

UKON-PAL-PRO-PFD-0-A-100

C

Gas Scrubber & Condensate Stabilizer

13

UKON-PAL-PRO-PFD-0-A-101

C

Condensate Storage & Loading

14

UKON-PAL-PRO-PFD-0-A-102 Sheets 1 to 2

C


15

UKON-KUN-PRO-PFD-0-A-100

C

Inlet Manifolds & Pig Launchers

16

UKON-KUN-PRO-PFD-0-A-101

C


17

UKON-ADB-PRO-PFD-0-A-100

C

Pig Receivers, Inlet Manifolds & Pig Launcher

Drawing Title



Rev: C


Page 59 of 76

Sr. No.

Drawing No.

Rev

18

UKON-ADB-PRO-PFD-0-A-101

C


19

UKON-SUN-PRO-PFD-0-A-100

C

Inlet Manifolds & Pig Launchers

20

UKON-SUN-PRO-PFD-0-A-101

C


21

UKON-SON-PRO-PFD-0-A-100

C

Pig Receivers, Inlet Manifolds & Pig Launcher

22

UKON-SON-PRO-PFD-0-A-101

C


23

UKON-NIM-PRO-PFD-0-A-100

C

Pig Receiver for Konaban To Nimbutali Pipeline

24

UKON-NIM-PRO-PFD-0-A-101

C


Drawing Title




Annexure I

Rev: C

Page 60 of 76

: Sample Calculations for Corrosion

1. Symbols CRt

:

Corrosion Rate at Temperature t in mm/year

P

:

Total System Pressure in bar

T

:

Temperature given in Kelvin.

t

:

Temperature given in °C

CO2

:

CO partial pressure in bar

Vcorr pCO2

: :

Corrosion Rate in mm Partial Pressure of CO2

c

p

2




Rev: C

Page 61 of 76

2. Input for sample KONABAN GGS CASE-1: WELL FTHP 154 KG/CM2G, INLET MANIFOLD AT 80 KG/CM2G AND 20°C Production Manifold Stream Description Vapour Fraction

0.9341

Temperature

°C

Pressure

kg/cm g

80.00

Molar Flow

kgmole/hr

1882.8

Mass Flow

kg/hr

32323.7

Std Gas Flow

STD_m /d

Std. Ideal Liq Vol Flow

m /hr

Actual Gas Flow

ACT_m /hr

Actual Liquid Flow

m /hr

Mass Density

kg/m

Viscosity

cP

Phase mass density

Phase viscosity

20 2

3

1068419.6

3

98.6 3

448.6

3

0.8

3

71.6 3

71.6

3

65.9

3

800.0

3

1013.5

Overall

kg/m

Vapour

kg/m

Liquid

kg/m

Aqueous

kg/m

Overall

cP

-

Vapour

cP

0.013

Liquid

cP

0.8

Aqueous

cP

1.0

Master Composition Mole Frac (CO 2)

0.0078

Master Composition Mole Frac (H 2O)

0.06



Rev: C


Page 62 of 76

3. Calculation P tC Mole Fraction of CO2 p p p

CO2 CO2 CO2

= = =

80.00 kg/cm 20°C 0.0078

2

= mole fraction x P /1.01 barg = 0.0078 x 80 /1.01 barg = 0.624 barg

T = 273 + tC T = 273 + 20 T = 293 As per de Waard – Milliams Equation of Dewards Model Log10 (Vcorr) = 5.8 – 1710 / T + 0.67 log 10(p

)

CO2

Log10 (Vcorr) = 5.8 – 1710 / 293 + 0.67 log10(0.624) Hence Vcorr = 0.67 mm per year 0.67 mm/year is uninhibited corrosion rate and for 25 years same shall be 25 x 0.0.67 = 16.75 mm hence we need corrosion inhibitor with 75% efficiency. Inhibitor efficiency = 75% (Inhibitor efficiency is corrosion inhibiting capability in %) Hence inhibited corrosion rate shall be 0.67 x (1-75/100) Inhibited corrosion rate = 0.17 mm / yr Inhibited corrosion rate for 25 years shall be 0.17 x 25 = 4.25 mm / yr A corrosion evaluation with inhibition should be based on the inhibitor availability, considered as the time the inhibitor is present in the system at a concentration at or above the minimum dosage. The percentage availability (A %) is defined as: A% = 100 x (Inhibitor Available Time) / (Lifetime) CA = (CRinhib x A %/100 x Lifetime) + (CRuninhib x {1 – A %/100} x Lifetime) CRinhib = Inhibited Corrosion Rate. CRuninhib = Uninhibited Corrosion Rate




Rev: C

Page 63 of 76

As per NORSOK M-001 the Inhibitor availability to be used in a design calculation depends on the planned corrosion management programme, including corrosion monitoring and corrosion inhibition. Unless otherwise defined, an inhibitor availability of 90 % shall be used. Maximum inhibitor availability shall not exceed 95 %. 95 % inhibitor availability requires that a qualified inhibitor is injected from day one and that a corrosion management system is in place to actively monitor corrosion and inhibitor injection. We have CRinhib CRuninhib We take A CA CA CA

= =

0.17 mm / yr 0.67 mm / yr

= = = =

95% (0.17 mm x 95%/100 x 25 ) + (0.67 x {1 – 95%/100} x 25) (4.03) + (0.84) 4.87 mm

Conclusion: For selected stream the calculated corrosion allowance is 4.87 mm with inhibitor having efficiency of 75% and availability of 95%



Rev: C


Annexure II

Page 64 of 76

: Streamwise Corrosion Calculation

Sr. No.

Area

No. of Sheets

1

Konaban

5

2

Palatana

2

3

Kunjaban

1

4

ADB

1

5

Sundalbari

1

6

Sonamura

1

7

Nimbutali

1


ADB GGS n o i s s i

m o r o r o r r e y n a g n i n i a t n o c r o , e s o p r u p r e h t o y n a r o f d e s u g n i e b r o , y t r a p r e h t o y n a y b n o p u d e i l e r g n i e b t n e m u c o d s i h t f o s e c n e u q e s n o c e h t r o f y t i l i b i s n o p s e r o n t p e c c a e W . e s o p r u p r e h t o y n a r o f d e s u r o y t r a p r e h t o y n a y b n o p u d e i l e r e b t o n d l u o h s t I . y l n o t c e j o r p d e n o i t p a c e v o b a e h t h t i w d e t c e n n o c s e s o p r u p c i f . i s c e e i p t s r r a p o r f e d t n h a o NOTES: t i y 1. FOR PROCESS FLOW DIAGRAMS, REFER PFD DRAWING NO. Ukon/ADB/PRO/PFD/0/A/100. d b e s n u o o 2. NORMALLY THERE WILL NOT BE ANY FLOW TO MP HEADER. THE FLOW FROM NEW TEST MANIFOLD TO MP HEADER TO i s t s d 3. SCALING OF FECO3 IS NOT TAKEN INTO ACCOUNT AS TEMPERATURE IS BELOW 60 DEG CENTIGRADE i e i l m p m p o u c s h t c a i a h d w n y i HOLDS: t r n a i o p s 1. FLOW RATE TO MP HEADER & TEST HEADER AT ADB GGS THROUGH 6" MANIFOLD FROM KUNJABAN (ONGC). s e i h t m r o o r REV DATE DESCRIPTION PRPD f o d r e o u r s r s e i n s a i : t o n t R e e E m u M u d I c s A o L d i h C s i c S I i h h D T w

1

Stream Number


Stream Description Vapour Fraction Temperature Pressure Molecular Weight Molar Flow Mass Flow Std Gas Flow Std. Ideal Liq Vol Flow Actual Gas Flow Actual Liquid Flow Mass Density Viscosity Phase mass density

°C kg/cm2 g kg/kgmoles kgmole/hr kg/hr STD_m3 /d 3 m /hr 3 ACT_m /hr m3 /hr 3 kg/m cP 3 kg/m 3 kg/m kg/m3 3 kg/m cP cP cP cP

Overall Vapour Liquid Aqueous Phase viscosity Overall Vapour Liquid Aqueous Master Composition Mole Frac (CO2) Master Composition Mole Frac (H2O) Partial Pressure of CO2

barg

Corrossion Allowance (Unihibited) for 25 years Corrossion Allowance (Ihibited) for 25 years with 75% efficiency Net Corrossion Allowancewith 95% Availability Recommended Corrosion Allowance

mm mm mm mm

0.9132 19 51.70 17.23 847.2 14599.4 480738.9 43.9 320.0 0.41 45.4 45.4 40.6 806.8 1013.2 0.012 0.8 1.0 0.0031 0.08 0.16 6.51 Not Required Not Required #N/A

2 HOLD-1 To Existing Test Header 0.9126 20 51.70 17.24 231.2 3984.5 131182.4 12.0 87.5 0.11 45.3 45.3 40.5 806.7 1012.8 0.012 0.8 1.0 0.0031 0.08 0.16 6.65 Not Required Not Required #N/A

3 HOLD-1 To Existing Test Header 0.9126 20 51.70 17.24 231.2 3984.5 131182.4 12.0 87.5 0.11 45.3 45.3 40.5 806.7 1012.8 0.012 0.8 1.0 0.0031 0.08 0.16 6.65 Not Required Not Required #N/A

4 HOLD-1, NOTE-2 To Existing MP Header 0.9130 19 28.60 17.26 423.7 7313.2 240450.0 21.9 300.9 0.21 24.2 24.2 21.6 819.1 1012.4 0.012 0.9 1.0 0.0031 0.08 0.09 4.46 Not Required Not Required #N/A

5 Gas To Palatana VIA Nimbutali 1.0000 26 24.00 16.65 3876.9 64530.8 2200000.0 210.6 3713.5 17.4 0.012 17.4 17.4 0.0 0.012 0.0038 0.00 0.1 0 Not Required Not Required #N/A

BE DIVERTED BASED ON THE WELL FTHP. OIL AND NATURAL GAS CORPORATION LTD., INDIA

CLIENT

LSTKCONTRACTOR

CHKD

APRD

KazStroyService Infrastructure India Pvt. Ltd. 1st Floor, Vatika Towers, A-Wing Sector 54, Gurgaon - 122002, India Mott MacDonald Pvt. Ltd., Kothari House, CTS No. 185, J.B. Nagar, Off Andheri - Kurla Road, Andheri (East), Mumbai 400 059, India

PROJECT: UPGRADATION OF KONABAN GGS & PIPELINE GRID PROJECT - TRIPURA ASSET CONTRACT:

DLH/OES/MM/UKon_PGP/AGT/X11PC09003/2010

Annexure - II CORROSSION CALCULATION SHEET FOR ADB GGS UKON/COM/PRO/RPT/4/I/005 SHEET 1 OF 11

KUNJABAN MANIFOLDS: WELL FTHP 154 KG/CM 2G (HOLD-1) AND INLET MANIFOLD AT 20°C 1 HOLD-2

Stream Number

n o i s s i m o r o r o r r e y n a g n i n i a t n o c r o , e s o p r u p r e h t o y n a r o f d e s u g n i e b r o , y t r a p r e h t o y n a y b n o p u d e i l e r g n i e b t n e m u c o d s i h t f o s e c n e u q e s n o c e h t r o f y t i l i b i s n o p s e r o n t p e c c a e W . e s o p r u p r e h t o y n a r o f d e s u r o y t r a p r e h t o y n a y b n o p u d e i l e r e b t o n d l u o h s t I . y l n o t c e j o r p d e n o i t p a c e v o b a e h t h t i w d e t c e n n o c s e s o p r u p c . NOTES: i f i s c e 1. FOR PROCESS FLOW DIAGRAMS, REFER PFD DRAWING NO. Ukon/KUN/PRO/PFD/0/A/100. e i r p t s a r p 2. NORMALLY THERE WILL NOT BE ANY FLOW TO MP HEADER AT ADB GGS. THE FLOW FROM NEW TEST MANIFOLD o r f e d t h 3. SCALING OF FECO3 IS NOT TAKEN INTO ACCOUNT AS TEMPERATURE IS BELOW 60 DEG CENTIGRADE n a o y t i b d s e u n o o t i s d s e i i l m p m p HOLDS: o u c s 1. KUNJABAN WELLS FTHP (ONGC). h t c a i a h d 2. KUNJABAN MANIFOLD OPERATING TEMPERATURE (ONGC). w i y n t r n 3. FLOW RATE FOR 6” TEST MANIFOLD FROM KUNJABAN (ONGC). o a i p s s e i h t m r o DESCRIPTION REV DATE o r f o d r e r u o s r s e i s n a i : t o t n R e e E m u M u d I c i s A o L d h C i c s i S h I h D T w

Stream Description Vapour Fraction Temperature Pressure Molecular Weight Molar Flow Mass Flow Std Gas Flow Std. Ideal Liq Vol Flow Actual Gas Flow Actual Liquid Flow Mass Density Viscosity Phase ma ss den sity

Overall Vapour Liquid Aqueous Phase viscosit y Overall Vapour Liquid Aqueous Master Composition Mole Frac (CO2) Master Composition Mole Frac (H2O) Partial Pressure of CO2 Corrossion Allowance (Unihibited) for 25 years Corrossion Allowa nce (Ihibited) f or 25 years with 7 Net Corrossion Allowancewith 95% Availability Recommended Corrosion Allowance

TO MP HEADER TO BE DIVERTED BASED ON THE WELL FTHP.

2 HOLD-2,3

2 HOLD-2,3 NOTE-2

FROM PIG LAUNCHER FROM PIG LAUNCHER FROM PIG LAUNCHER KUN-L-0101 KUN-L-0102 KUN-L-0102 °C kg/cm2 g kg/kgmoles kgmole/hr kg/hr STD_m 3 /d m3 /hr ACT_m 3 /hr m3 /hr kg/m3 cP kg/m3 kg/m3 kg/m3 kg/m3 cP cP cP cP

barg mm mm mm mm

0.9131 20 60. 85 17.23 847.2 14599.4 480738.9 43.9 268.2 0.41 54. 1 54. 1 48. 5 802.6 1012.9 0.013 0. 8 1.0 0.0031 0. 08 0. 19 7. 54

0.9126 20 41. 63 17.26 423.7 7313.2 240450.0 21.9 203.1 0.22 35.9 35.9 32.0 811.3 1012.4 0. 012 0.9 1. 0 0.0031 0. 08 0. 13 5. 85

0.9130 19 28.60 17.24 423.7 7313.2 240450.0 21.9 300.9 0.21 24.2 24.2 21.6 819.1 1012.4 0.012 0.9 1. 0 0.0031 0. 08 0. 09 4. 46

1.89 2.18 3

Not Required Not Required 5.75

Not Re quired Not Re quired 4. 5

CLIENT

OIL AND NATURAL GAS CORPORATION LTD., INDIA LSTKCONTRACTOR

KazStroyServiceInfrastructureIndia Pvt.Ltd. 1st Floor, Vatika Towers, A-Wing Sector 54, Gurgaon- 122002, India

PRPD

CHKD

APRD

MottMacDonaldPvt.Ltd., Kothari House, CTS No. 185, J.B. Nagar, OffAndheri -Kurla Road, Andheri (East), Mumbai 400 059, India

PROJECT: UPGRADATION OF KONABAN GGS & PIPELINE GRID PROJECT - TRIPURA ASSET CONTRACT: DLH/OES/MM/UKon_PGP/AGT/X11PC090 AGT/X11PC09003/2010

Annexure - II CORROSSION CALCULATION SHEET FOR KKUNJABAN UKON/COM/PRO/RPT/4/I/005 SHEET 6 OF 11

NIMBUTALI JUNCTION POINT Stream Number

n o i s s i m o r o r o r r e y n a g n i n i a t n o c r o , e s o p r u p r e h t o y n a r o f d e s u g n i e b r o , y t r a p r e h t o y n a y b n o p u d e i l e r g n i e b t n e m u c o d s i h t f o s e c n e u q e s n o c e h t r o f y t i l i b i s n o p s e r o n t p e c c a e W . e s o p r u p r e h t o y n a r o f d e s u r o y t r a p r e h t o y n a y b n o p u d e i l e r e b t o n d l u o h s t I . y l n o t c e j o r p d e n o i t p a c e v o b a e h t h t i w d e t c e n n o c s e s o p r u p c i f . NOTES: i s c e e i 1. FOR PROCESS FLOW DIAGRAMS, REFER PFD DRAWING NO. Ukon/NIM/PRO/PFD/0/A/100. p t s r r a o p r 2. SCALING OF FECO3 IS NOT TAKEN INTO ACCOUNT AS TEMPERATURE IS BELOW 60 DEG CENTIGRADE f e d t n h a o t i y d b e s n u o t o i s s d i e i l m HOLDS: m p o p c u s 1. FLOW RATE TO MP HEADER & TEST HEADER AT SONAMURA GGS THROUGH 6" MANIFOLD FROM KUNJABAN h a c t i a h d w n y i t r n a o p i s e s h i t r m o o r DESCRIPTION R EV DATE f d o e r r u o r s e s i s n a i : t o n t R e e E m u M u d I c i s A o L d C s h c i i h S h I D T w

Stream Description Vapour Fraction Temperature Pressure Molecular Weight Molar Flow Mass Flow Std Gas Flow Std. Ideal Liq Vol Flow Actual Gas Flow Actual Liquid Flow Mass Density Viscosity P hase mass de nsity

Ove rall Vapour Liquid A queo us P hase viscosity Ove rall V apour Liquid A queo us Master Composition Mole Frac (CO2) Master Composition Mole Frac (H2O) Partial Pressure of CO2 Corrossion Allowance (Unihibited) for 25 years Corrossion A llowance (Ihibited) f or 25 years with 75% eff iciency Net Corrossion Allowancewith 95% Availability Recommended Corrosion Allowance

°C 2 kg/cm g kg/kgmole s kgmole/ hr kg/hr 3 STD_m /d 3 m /hr ACT_m3 /hr 3 m /hr kg/m3 cP 3 kg/m kg/m3 3 kg/m 3 kg/m cP cP cP cP

barg mm mm mm mm

1 Gas From Konaban GGS 1.00 00 21 23.7 7 16.7 8 1762 .0 2956 0.0 1000080.0 95.7 1668.0 17. 7 0.01 2 17. 7 17. 7 0.01 16 0.01 16 0.00 80 0. 0 0 0. 1 9 0 Not Req uired Not Req uired 3

2

3

Gas From From ADB ADB GGS

Gas To Palatan Palatana

1. 000 0 21 23.7 7 16.6 5 3877 .0 64530 .0 2200080.0 210.6 3671.0 17. 6 0.01 2 17. 6 17. 6 0.011 6 0.011 6 0. 003 8 0. 00 0. 09 0

1.000 0 21 23.7 7 16.6 9 5639 .0 94090 .0 3199200.0 306.3 5339.0 17. 6 0. 01 2 17. 6 17. 6

Not Require d Not Require d 3


0.011 6 0. 011 6

0.005 2 0. 00 0. 13 0

CLIENT

OIL AND NATURAL GAS CORPORATION LTD., INDIA

LSTKCONTRACTOR

KazStroyService Infrastructure India Pvt. Ltd. 1st Floor, Vatika Towers, A-Wing Sector 54, Gurgaon - 122002, India

(ONGC). ENGINEERINGSUBCONTRACTOR

PRPD

CHKD

Mott MacDonald Pvt. Ltd., Kothari House, CTS No. 185, J.B. Nagar, Off Andheri - Kurla Road, Andheri (East), Mumbai 400 059, India

A PRD



Annexure - II CORROSSION CALCULATION SHEET FOR NIMBUTALI UKON/COM/PRO/RPT/4/I/005 SHEET 7 OF 11

SONAMURA GGS

n o i s s i m o r o r o r r e y n a g n i n i a t n o c r o , e s o p r u p r e h t o y n a r o f d e s u g n i e b r o , y t r a p r e h t o y n a y b n o p u d e i l e r g n i e b t n e m u c o d s i h t f o s e c n e u q e s n o c e h t r o f y t i l i b i s n o p s e r o n t p e c c a e W . e s o p r u p r e h t o y n a r o f d e s u r o y t r a p r e h t o y n a y b n o p u d e i l e r e b t o n d l u o h s t I . y l n o t c e j o r p d e n o i t p a c e v o b a e h t h t i w d e t c e n n o c s e s o p r u p c i f . NOTES: i s c e e t i p r 1. FOR PROCESS FLOW DIAGRAMS, REFER PFD DRAWING NO. Ukon/SON/PRO/PFD/0/A/100. s r a 2. NORMALLY THERE WILL NOT BE ANY FLOW TO MP HEADER. THE FLOW FROM NEW TEST MANIFOLD TO MP HEA DER TO o p r f e d t n h 3. SCALING OF FECO3 IS NOT TAKEN INTO ACCOUNT AS TEMPERATURE IS BELOW 60 DEG CENTIGRADE a o t i y d b e s n u o t o i HOLDS: s s d i e 1. FLOW RATE TO MP HEADER & TEST HEADER AT SONAMURA GGS THROUGH 6" MANIFOLD FROM KUNJABAN (ONGC). i l m m p o p c u s h t c a i a h d w n y i t r n a i o p s e s h i t r m o o r R EV DATE DESCRIPTION PRPD f d o e r r u o r s e s i s n a i : t o n t R e e E m u M u d I c i s A o L d C s h c i i h S h I D T w

0.82 48 20 71. 00 17. 25 682 . 4 1177 2.7 387257.3 33.1 163.9 0.24 70 .8 70 .8 57 .7 800 .9 101 3.4 0. 0 13 0. 8 1. 0 0.00 28 0.1 7 0. 2 7.7 1

2 HOLD-1 To Existing Test Header 0.82 47 20 71. 00 17. 25 256 .0 441 6.4 145245.7 12.4 61.5 0.09 70 .8 70 .8 57 .7 800 . 8 101 3.3 0. 0 13 0. 8 1. 0 0.00 28 0.1 7 0. 2 7.7 9

3 HOLD-1 To Existing Test Header 0.82 47 20 71.0 0 17. 2 5 256 .0 4416 .4 145245.7 12.4 61.5 0.09 70. 8 70. 8 57. 7 800 . 8 1013 .3 0.01 3 0. 8 1. 0 0.00 28 0.1 7 0.2 7.7 9

1. 9 3 2.2 2 3

1. 9 5 2. 2 5 3

1. 9 5 2. 2 5 3

1

Stream Number


Stream Description Vapour Fraction Temperature Pressure Molecular Weight Molar Flow Mass Flow Std Gas Flow Std. Ideal Liq Vol Flow Actual Gas Flow Actual Liquid Flow Mass Density Viscosity P hase mass de nsity

Ove rall Vapour Liquid A queo us P hase viscosity Ove rall V apour Liquid A queo us Master Composition Mole Frac (CO2) Master Composition Mole Frac (H2O) Partial Pressure of CO2

°C kg/cm2 g kg/kgmole s kgmole /hr kg/hr STD_m3 /d 3 m /hr 3 ACT_m /hr m3 /hr 3 kg/m cP 3 kg/m 3 kg/m kg/m3 3 kg/m cP cP cP cP

Corrossion Allowance (Unihibited) for 25 years Corrossion A llowance (Ihibited) f or 25 years with 75 Net Corrossion Allowancewith 95% A vailability Recommended Corrosion Allowance

barg mm mm mm mm

4 HOLD-1, NOTE-2

5

To Existing Existing MP Header

Gas To Palatana

0.825 3 20 31.0 0 17.2 8 341. 0 5894 .1 193505.5 16.5 201.7 0.14 29. 1 29. 1 23. 4 818. 8 1012 .2 0.01 2 0. 9 1.0 0.002 8 0.17 0.09 4.54

1.000 0 20 22. 0 0 16.5 6 528. 7 8745 .5 300000.0 28.7 539.7 16.2 0. 0 16.2 16.2 0.0 0. 01 2 0.002 1 0.00 0.05 0

Not Require d Not Require d 4. 5


BE DIVERTED BASED ON THE WELL FTHP. CLIENT


LSTKCONTRACTOR

KazStroyService Infrastructure India Pvt. Ltd. 1st Floor, Vatika Towers, A-Wing Sector 54, Gurgaon - 122002, India ENGINEERINGSUBCONTRACTOR

CHKD


A PRD



Annexure - II CORROSSION CALCULATION SHEET FOR SONAMURA GGS UKON/COM/PRO/RPT/4/I/005 SHEET 10 OF 11

2

SUNDALBARI MANIFOLDS: WELL FTHP 154 KG/CM G (HOLD-1) AND I NLET MANIFOLD AT 20°C 1 HOLD-2

Stream Number

n o i s s i m o r o r o r r e y n a g n i n i a t n o c r o , e s o p r u p r e h t o y n a r o f d e s u g n i e b r o , y t r a p r e h t o y n a y b n o p u d e i l e r g n i e b t n e m u c o d s i h t f o s e c n e u q e s n o c e h t r o f y t i l i b i s n o p s e r o n t p e c c a e W . e s o p r u p r e h t o y n a r o f d e s u r o y t r a p r e h t o y n a y b n o p u d e i l e r e b t o n d l u o h s t I . y l n o t c e j o r p d e n o i t p a c e v o b a e h t h t i w d e t c e n n o c s e s o p r u p c i f . i s c e e i NOTES: p t s r r a 1. FOR PROCESS FLOW DIAGRAMS, REFER PFD DRAWING NO. Ukon/KUN/PRO/PFD/0/A/100. o p r f e 2. NORMALLY THERE WILL NOT BE A NY FLOW TO MP HEADER AT SONAMURA GGS. THE FLOW FROM NEW d t n h a o t i y 3. SCALING OF FECO3 IS NOT TAKEN INTO ACCOUNT AS TEMPERATURE IS BELOW 60 DEG CENTIGRADE d b s e u n o t o i s s d i e HOLDS: l m i p m p o u c s 1. SUNDALBARI WELLS FTHP (ONGC). h a c t i a 2. SUNDALBARI MANIFOLD OPERATING TEMPERATURE (ONGC). h d w n y i 3. FLOW RATE TO MP HEADER AT SONAMURA GGS THROUGH 6” MANIFOLD FROM SUNDALBARI (ONGC). t r n a i p o s e s h i t r m o o r DESCRIPTION RE V D AT E f d o r e o r u r s e s i s n a i : t o n t R e E m e u M u d I c i s A o L d C s h c i i h S h I D T w

Stream Description Vapour Fraction Temperature Pressure Molecular Weight Molar Flow Mass Flow Std Gas Flow Std. Ideal Liq Vol Flow Actual Gas Flow Actual Liquid Flow Mass Density Viscosity Phase mass density

Overa ll Vapour Liquid Aqueous Phase viscosity Overa ll Vapo ur Liquid Aqueous Master Composition Mole Frac (CO2) Master Composition Mole Frac (H2O) Partial Pressure of CO2

2 HOLD-2,3 NOTE-2

FROM PIG LAUNCHER FROM PIG LAUNCHER FROM PIG LAUNCHER SUN-L-0101 SUN-L-0102 SUN-L-0102 °C kg/cm2 g kg/kgmoles kgmole/hr kg/hr 3 STD_m /d m3 /hr 3 ACT_m /hr m3 /hr 3 kg/m cP kg/m3 3 kg/m kg/m3 3 kg/m cP cP cP cP

Corrossion Allowance (Unihibited) for 25 years Corro ssion Allo wance (Ihibited) f or 25 yea rs with 75 Net Corrossion Allowancewith 95% Availability Recommended Corrosion Allowance

TEST MANIFOLD TO MP HEADER TO BE DIVERTED BASED ON THE WELL FTHP.

2 HOLD-2,3

barg mm mm mm mm

0.8248 20 74.19 17.25 682.4 11772.7 387257.3 33.1 156.2 0.24 74.3 74.3 60.6 799.8 1013.3 0.013 0. 8 1. 0 0.0028 0. 17 0. 21 8. 08

0.8247 20 73.60 17.25 256. 0 4416.4 6051.9 12.4 59.1 0.09 73.6 73.6 60.0 799.8 1013.2 0.013 0. 8 1. 0 0.0028 0. 17 0. 21 8. 12

0.8253 20 31. 00 17. 28 341.0 5894.1 193505.5 16.5 201.7 0.14 29.1 29.1 23.4 818.8 1012.2 0. 012 0. 9 1. 0 0.0028 0. 17 0. 09 4. 54

2.02 2.33 3

2.03 2.34 3

Not Required Not Required 4. 5

CLIENT


LSTKCONTRACTOR

KazStroyService Infrastructure India Pvt. Ltd. 1st Floor, Vatika Towers, A-Wing Sector 54, Gurgaon - 122002, India

PRPD

CHKD


AP RD



Annexure - II CORROSSION CALCULATION SHEET FOR SUNDALBARI UKON/COM/PRO/RPT/4/I/005 SHEET 11 OF 11



Annexure III

Rev: C

Page 65 of 76

: Material Selection Diagrams

Following sheets shall be referred for material selection diagram Table A: Material Selection Diagrams for Konaban GGS Sr. No.

Drawing No.

Drawing Title

1.

KON-MSD-100

Inlet Manifold, IDBH and HP Separator

2.

KON-MSD-101

Gas Scrubber And Metering

3.

KON-MSD-102

Condensate Stabilizer, Storage And Loading

4.

KON-MSD-103

Effluent Stabilizer, Storage And Loading

5.

KON-MSD-104

Corrosion Inhibitor Dosing System

6.

KON-MSD-105

Instrument Gas System

7.

KON-MSD-106

Fuel Gas System

8.

KON-MSD-107

Borewell Pump

9.

KON-MSD-108

Flare System

10.

KON-MSD-109

OWS and Evaporation Pit

Table B: Material Selection Diagrams for Palatana Terminal Sr. No.

Drawing No.

Drawing Title

1.

PAL-MSD-100

Gas Scrubber & Condensate Stabilizer

2.

PAL-MSD-101

Condensate Storage & Loading

Table C: Material Selection Diagrams for Kunjaban Manifolds Sr. No. 1.

Drawing No. KUN-MSD-100

Drawing Title Inlet Manifolds & Pig Launchers

Table D: Material Selection Diagrams for ADB GGS r. No. 1.

Drawing No. ADB-MSD-100

Drawing Title Pig Receivers, Inlet Manifolds & Pig Launcher




Rev: C

Page 66 of 76

Table E: Material Selection Diagrams for Sundalbari Manifolds Sr. No. 1.

Drawing No. SUN-MSD-100

Drawing Title Inlet Manifolds & Pig Launchers

Table F: Material Selection Diagrams for Sonamura GGS Sr. No. 1.

Drawing No. SON-MSD-100

Drawing Title Pig Receivers, Inlet Manifolds & Pig Launcher

Table G: Material Selection Diagrams for Nimbutali Junction Point Sr. No.

1.

Drawing No. NIM-MSD-100

Drawing Title Pig Receiver for Konaban To Nimbutali Pipeline



Rev: C

Page 67 of 76


Annexure IV

: Material Recommendation for Equipments

Table A: Material Recommendation for Konaban GGS Equipment No.

Title

Area Code

RECOMMENDED MATERIAL

MSD NO.

KON-A-0001

KONABAN GGS PRODUCTION MANIFOLD

KON

SS316L

KON-MSD-100

KON-A-0002

KONABAN GGS TEST MANIFOLD

KON

SS316L

KON-MSD-100

KON-A-0110

INDIRECT WATER BATH HEATER PACKAGE

KON

KON-F-0111

INDIRECT WATER BATH HEATER

KON

SHELL MOC : CS + 3 mm C.A. SHELL HEAD MOC: CS+6mm C.A. VENDOR TO RECONFIRM

KON-MSD-100

TUBE MOC:SS316L VENDOR TO RECONFIRM KON-S-0201

HP PRODUCTION SEPARATOR

KON

MOC : CS + 3 mm C.A.

KON-MSD-100

KON-S-0301

GAS SCRUBBER

KON

MOC: CS + 3 mm C.A.

KON-MSD-101

KON-M-0301

STATIC MIXER

KON

VENDOR TO RECOMMEND MOC

KON-MSD-101



Rev: C

Page 68 of 76


Equipment No.

Title

Area Code


MSD NO.

KON-A-0410

CORROSION INHIBITOR PACKAGE

KON

KON-T-0411

CORROSION INHIBITOR STORAGE TANK

KON

KON-P-0411A/B

CORROSION INHIBITOR DOSING PUMPS

KON

S-6 / API610 VENDOR TO CONFIRM

KON-MSD-104

KON-P-0401

CORROSION INHIBITOR TRANSFER PUMP

KON

S-6 / API610 VENDOR TO CONFIRM

KON-MSD-104

KON-A-0420

SAFETY SHOWER & EYE WASH PACKAGE

KON

KON-T-0421

WATER TANK

KON

MOC : LDPE

KON-S-0501

CONDENSATE STABILIZER

KON


KON-MSD-102

KON-T-0601 A/B

CONDENSATE STORAGE TANK

KON


KON-MSD-102

KON-P-0601A/B

CONDENSATE TRANSFER PUMPS

KON

MOC: S-6/ API 610

KON-MSD-102

KON-A-0710

CONDENSATE LOADING ARM PACKAGE

KON

KON-Z-0711

CONDENSATE LOADING ARM

KON

SS304 CLADDED VESSEL / SS304

VENDOR TO CONFIRM

KON-MSD-103

---

KON-MSD-102 VENDOR TO RECOMMEND MOC

KON-MSD-102



Rev: C

Page 69 of 76


Equipment No.

Title

Area Code


MSD NO.

KON-A-0720

SAFETY SHOWER & EYE WASH PACKAGE

KON

KON-T-0721

WATER TANK

KON

MOC : LDPE

KON-S-0801

EFFLUENT WATER STABILIZER

KON


KON-MSD-103

KON-T-0901

EFFLUENT STORAGE TANK

KON


KON-MSD-103

EFFLUENT TRANSFER PUMPS

KON

MOC: S-6/ API 610

KON-MSD-103

KON-Z-0901

EFFLUENT LOADING ARM

KON


KON-MSD-103

KON-A-1510

GAS DRYER PACKAGE

KON

INSTRUMENT GAS PRE-FILTERS

KON

MOC : CS+3mm C.A. VENDOR TO RECONFIRM

KON-MSD-105

ACTIVATED CARBON FILTER

KON


KON-MSD-105

KON-S-1513A/B

INSTRUMENT GAS AFTER FILTERS

KON


KON-MSD-105

KON-D-1511A/B

GAS DRYERS

KON


KON-MSD-105

KON-P-0901A/B

KON-S-1511A/B

KON-S-1512

-----

KON-MSD-105



Rev: C

Page 70 of 76


Equipment No.

Title

Area Code


MSD NO.

KON-V-1501

INSTRUMENT GAS RECEIVER

KON


KON-MSD-105

KON-S-1701

FUEL GAS SCRUBBER

KON


KON-MSD-106

FUEL GAS FILTERS

KON


KON-MSD-106

KON-A-1810

EVAPORATION PIT PACKAGE

KON

KON-T-1811

EVAPORATION PIT

KON

MOC: Concrete Pit.

KON-MSD-109

KON-A-1811

FLAME FRONT GENERATOR

KON


KON-MSD-109

KON-S-2001

FLARE KNOCK OUT DRUM

KON


KON-MSD-108

FLARE KOD CONDENSATE TRANSFER PUMPS

KON

MOC: S-6/ API 610

KON-MSD-108

KON-A-2110

FLARE PACKAGE

KON

KON-V-2111

WATER SEAL DRUM

KON

MOC : CS + 3 mm C.A.VENDOR TO RECONFIRM MOC

KON-MSD-108

KON-A-2111

FLAME FRONT GENERATOR

KON


KON-MSD-108

KON-S-1702A/B

KON-P-2001A/B



Rev: C

Page 71 of 76


Equipment No.

Title

Area Code


MSD NO.

KON-A-2112

FLARE STACK

KON


KON-MSD-108

KON-A-2113

MOLECULAR SEAL

KON


KON-MSD-108

KON-F-2111

FLARE TIP

KON


KON-MSD-108

AIR BLOWER

KON


KON-MSD-108

KON-S-2201

OWS PIT

KON

MOC : Concrete Pit

KON-MSD-109

KON-P-2201

OWS CONDENSATE TRANSFER PUMP

KON

MOC: S-6 / API 610

KON-P-2202

OWS EFFLUENT WATER TRANSFER PUMP

KON

MOC: S-6 / API 610

KON-P-2301

BORE WELL PUMP

KON

MOC: S-6/ API 610

KON-A-2410

DIESEL GENERATOR PACKAGE

KON

KON-T-2411

DIESEL GENERATOR DAY TANK

KON

MOC: CS + 3mm CA

---

DIESEL ENGINE

KON


---

KON-K-2111A/B

KON-DG-2411

KON-MSD-107



Rev: C

Page 72 of 76


Equipment No.

Title

Area Code


KON-G-2411

GENERATOR

KON


KON-L-2601

PIG LAUNCHER FOR KONABAN GAS PIPELINE

KON


KON-P-2701

JOCKEY PUMP

KON


MSD NO. --KON-MSD-101 ---

Table B: Material Recommendation for PALATANA Equipment No.

Title

Area Code


MSD NO.

PAL-R-0001

PIG RECEIVER FOR ADB GAS PIPELINE

PAL


PAL-MSD-100

PAL-R-0002

PIG RECEIVER FOR SONAMURA GAS PIPELINE

PAL


PAL-MSD-100

PAL-S-0101

GAS SCRUBBER

PAL


PAL-MSD-100

PAL-S-0102

CONDENSATE STABILIZER

PAL


PAL-MSD-100

PAL-A-0210

GAS CUSTODY TRANSFER METERING SKID

PAL


PAL-MSD-100



Rev: C

Page 73 of 76


Equipment No.

PAL-T-0301

Title

Area Code


MSD NO.

CONDENSATE STORAGE TANK

PAL


PAL-MSD-101

CONDENSATE TRANSFER PUMPS

PAL

MOC: S-6/ API 610

PAL-MSD-101

PAL-A-0410

VENT STACK PACKAGE

PAL

PAL-A-0411

VENT STACK

PAL

MOC : CS + 3 mm C.A. VENDOR TO RECONFIRM MOC

PAL-MSD-101

PAL-P-0301A/B

Table C: Material Recommendation for KUNJABAN Equipment No.

Title

Area Code


MSD NO.

KUN-A-0001

KUNJABAN PRODUCTION MANIFOLD

KUN

MOC : CS + 3 mm C.A. WITH CORROSION INHIBITOR

KUN-MSD-100

KUN-A-0002

KUNJABAN TEST MANIFOLD

KUN

MOC: CS + 6mm C.A.

KUN-MSD-100

KUN-L-0101

PIG LAUNCHER FOR KUNJABAN PRODUCTION MANIFOLD

KUN


KUN-MSD-100

KUN-L-0102

PIG LAUNCHER FOR KUNJABAN TEST MANIFOLD

KUN


KUN-MSD-100



Rev: C

Page 74 of 76


Table D: Material Recommendation for ADB Equipment No.

Title

Area Code


MSD NO.

ADB-R-0001

PIG RECEIVER FOR KUNJABAN PRODUCTION MANIFOLD

ADB


ADB-MSD-100

ADB-R-0002

PIG RECEIVER FOR KUNJABAN TEST MANIFOLD

ADB


ADB-MSD-100

ADB-L-0101

PIG LAUNCHER FOR ADB GAS PIPELINE

ADB


ADB-MSD-100

Table E: Material Recommendation for SUNDALBARI Equipment No.

Title

Area Code


MSD NO.

SUN-A-0001

SUNDALBARI PRODUCTION MANIFOLD

SUN


SUN-MSD-100

SUN-A-0002

SUNDALBARI TEST MANIFOLD

SUN


SUN-MSD-100

SUN-L-0101

PIG LAUNCHER FOR SUNDALBARI PRODUCTION MANIFOLD

SUN


SUN-MSD-100

SUN-L-0102

PIG LAUNCHER FOR SUNDALBARI TEST MANIFOLD

SUN


SUN-MSD-100



Rev: C

Page 75 of 76


Table F: Material Recommendation for SONAMURA Equipment No.

Title

Area Code

SON-R-0001

PIG RECEIVER FOR SUNDALBARI PRODUCTION MANIFOLD

SON


SON-MSD-100

SON-R-0002

PIG RECEIVER FOR SUNDALBARI TEST MANIFOLD

SON


SON-MSD-100

SON-L-0101

PIG LAUNCHER FOR SONAMURA GAS PIPELINE

SON


SON-MSD-100


MSD NO.

Table G: Material Recommendation for NIMBUTALI Equipment No.

NIM-R-0001

Title

PIG RECEIVER FOR KONABAN TO NIMBUTALI PIPELINE

Area Code

NIM



MSD NO.

NIM-MSD-100


Final MSR Rev[1]. C

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