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

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

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

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

Client

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





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





Rev: C Page 4 of 76


1 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 CO2 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 (CO2), hydrogen sulphide (H2S) 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 dont have H2S even in traces, and pH is also high hence only CO2 shall be dominating factor in causing corrosion.





Rev: C Page 5 of 76


2 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





Rev: C Page 6 of 76


3 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

Well - 1

OFF PLOT ON PLOT

CHOKE VALVE - 1

NEW PRODDUCTI

ON HEADE

R

NEW TEST HEADER

IDBH PRODUCTION SEPARATOR

EFFL. TO EVPN PIT VIA . TANK

GAS To PALATANA

CONDENSATE To LOADING via COND.

TANK

(TYP) Total 24 Wells

GAS SCRUBBER

EXIST. GAS LINE

COND. STABILISER

EFFL. STABILISER

GAS TO FG SKID

IG SKID INST. GAS

EXIST. PRODDUCTION

HEADER EXIST.

TEST HEADER EXIST. TEST SEPARATOR

FG TO CANTEEN

EXIST. FLARE HEADER

TO NEW FLARE

HEADER

FLARE NEW FLARE HEADER





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 Value

1 Methane Mole % 96.653 2 Ethane Mole % 1.840 3 Propane Mole % 0.294 4 i-Butane Mole % 0.084 5 n-Butane Mole % 0.067 6 i-Pentane Mole % 0.016 7 n-Pentane Mole % 0.013 8 C6+ Mole % Traces 9 Carbon Di-oxide Mole % 0.832

10 Nitrogen Mole % 0.201 11 Molecular Weight - 16.72 12 Specific Gravity (Avg) - 0.5783 13 GCV kcal/m3 9,177.79 14 NCV kcal/m3 8,269.93

Note-1: Gas analysis data for sample dated June15, 2009.

B) Condensate Property Data Sr. No. Property Unit Value

1 Density gm/cc 0.8174 2 Specific Gravity - 0.8178 3 API Gravity API 41.50 4 Sulphur ppm 52 5 RVP psi (a) 2.4 6 Nitrogen Weight % 0.02 7 Calorific Value (Avg.) kcal / kg 10,996.9

C) Condensate ASTM Data Sr. No. Volume % Temperature,C Sr. No. Volume % Temperature,C

1 IBP 62 11 50 163.5 2 5 88 12 55 173 3 10 104 13 60 179.5 4 15 115 14 65 191 5 20 123 15 70 200 6 25 131.5 16 75 209 7 30 138 17 80 224 8 35 143.5 18 85 236 9 40 150 19 90 245

10 45 155.5 20 93 (FBP) 247





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3.2 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 (PSV-015/016 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 (SD-4) 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.





Rev: C Page 10 of 76


3.3 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

CONDENSATE To LOADING

GAS SCRUBBER

CONDENSATE STABILISER

GAS FROM KONABAN

GGS

OVERHEAD CONDENSATE

TANK

GAS FROM AGARTALA DOME GGS

GAS FROM SONAMURA

GGS

OFF PLOT ON PLOT

GAS METERING

GAS TO OTPC POWER PLANT

GAS TO VENT STACK

PIG RECEIVER

PIG RECEIVER







3.4 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.







Figure 3.4.1 Pipelines Block Diagram







4 Design Basis for Facilities

4.1 Konaban GGS

The following table 4.1.1 gives the capacity of Konaban GGS:

Table 4.1.1: Capacity of Konaban GGS

Capacity Min. / Max. Sr. No.

Item Gas,

MMSCMD Condensate,

Sm3/day Produced

Water, Sm3/day

Remarks

1 Konaban GGS -New

0.1 / 1 1 / 10 10 / 50

2 Konaban GGS-Existing

- / 0.5 10 10 / 50

3 Konaban GGS-after upgradation

0.1 / 1.5 1 / 20 20 / 100

4.2 Palatana Terminal

The following table 4.2.1 gives the capacity of Palatana terminal: Table 4.2.1: Capacity of Palatana Terminal

Capacity Min. / Max. Sr. No.

Item Gas,

MMSCMD Condensate,

Sm3/day Produced

Water, Sm3/day

Remarks

1 Palatana Terminal

2.65 / 3.5

1.5 / - -

Process Parameters

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

Min Temperature : 2C

Max Temperature : 45C

Min Operating Pressure : 1 kg/cm2g

Max Operating Pressure : 80 kg/cm2g

Mole Fraction of CO2 : 0.008

pH : > 6.5







5 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 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 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 Yes As per DeWard Model Oxygen content No Not applicable Content of other oxidizing agents, No Not applicable Operating temperature and pressure, Yes As per DeWard Model Organic acids, pH No Not applicable H2S-content Yes Not applicable Halide, metal ion and metal concentration, No Not applicable Velocity, flow regime Yes Not applicable Sand production, No Not applicable Biological activity, No Not applicable Condensing conditions. No Not applicable

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







7 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:

)O0.67log(pCT

17105.8LogV 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 (60C) 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.







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







The pH for saturation with magnetite is:

)COlog(17.0130736.1pHmag 2+= t (1.4)

and for iron carbonate:

pHcarb = 5.4 0.66 log (pCO2) (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 Methods of controlling corrosion

There are various methods of mitigating corrosion some of them are: - Corrosion inhibitors - Hydrate preventers - Reduction of water wetting - Increasing pH - Reducing CO2 partial pressure - Selection of materials

8.1 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.







Experiments for qualification of the pH stabilization technique at the IFE have shown that protective films form in a short time at temperatures between 40C and 100C, reducing the corrosion rate to less than 0.1mm/y. At lower temperatures around 20C, 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 20C 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







9 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







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 20C

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








Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


16 Gas from Effluent Water Stabiliser to Canteen DRY GAS NR NR 3

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








Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


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


1 Production Manifold 39.48 9.87 11.36 SS316L

2 IDBH Outlet 48.03 12.01 13.82 SS316L















Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability
















24 Condensate From Gas Dryer Package 4.33 NR NR 4.5


26 Condensate From Instrument Gas Receiver 4.33 NR NR 4.5









Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability



29 Condensate To OWS Header 4.33 NR NR 4.5





DRY GAS NR NR 3




37 Fuel Gas TO Evaporation Pit Package DRY GAS NR NR 3




1 Production Manifold 8.85 2.22 2.56 3

2 IDBH Outlet 24.72 6.18 7.11 SS316L










Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability



























Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability



24 Condensate From Gas Dryer Package 9.45 2.37 2.73 3


26 Condensate From Instrument Gas Receiver 9.45 2.37 2.73 3



29 Condensate To OWS Header 9.45 2.37 2.73 3





DRY GAS NR NR 3















Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


1 Production Manifold 20.9 5.23 6.02 6

2 IDBH Outlet 24.72 6.18 7.11 SS316L























Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability








24 Condensate From Gas Dryer Package 9.45 2.37 2.73 3


26 Condensate From Instrument Gas Receiver 9.45 2.37 2.73 3



29 Condensate To OWS Header 9.45 2.37 2.73 3





DRY GAS NR NR 3









Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability














Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


KONABAN GGS CORROSION SUMMARY

1 Production Manifold SS316L

2 IDBH Outlet SS316L

3 To HP Separator Package 6 (With Inhibitor)

4 Produced Gas To Gas Scrubber 3

5 Condensate From HP Production Separator 3

6 Effluent From HP Production Separator 3

7 Produced Gas From Scrubber 3

8 Condensate From Gas Scrubber 3

9 Gas To Palatana 3

10 To Instrument Gas Header 3

11 Total Condensate To Condensate Stabiliser 3

12 Gas From Condensate Stabilser To Canteen 3

13 Condensate To Storage Tank 3

14 Condensate Transfer Pump Suction 3

15 Condensate Transfer Pump Discharge 3

16 Gas from Effluent Water Stabiliser to Canteen 3

17 Effluent Water To Storage

SEE DETAIL CORROSION SUMMARY (TABLE 9.1 B)

FOR ALL 4 CASES IN KONABAN

3








Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


18 Effluent Loading Pump Suction 3

19 Effluent Loading Pump Discharge 3

20 CI Pump Suction 3

21 CI Pump Discharge 3

22 To Gas Dryer Package 3

23 Instrument Gas To Receiver 3

24 Condensate From Gas Dryer Package 3 (With Inhibitor)

25 Instrument Gas Header 3

26 Condensate From Instrument Gas Receiver 3 (With Inhibitor)

27 Instrument Gas to New Konaban GGS 3

28 Instrument Gas to Existing Konaban GGS 3

29 Condensate To OWS Header 3 (With Inhibitor)

30 Gas To Fuel Gas Scrubber 3

31 Fuel Gas From Fuel Gas Scrubber 3

32 Condensate From Fuel Gas Scrubber 3


3

34 Fuel Gas To IDBH 3

35 Fuel Gas To Flare Package

SEE DETAIL CORROSION SUMMARY (TABLE 9.1B)


3








Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


36 Fuel Gas To Flare Header Purging 3

37 Fuel Gas TO Evaporation Pit Package 3

38 Gas From Existing Konaban GGS 3

39 Gas From Existing LP Sep. & Water Flash Drum



3







Table 9.1 B: Corrosion Summary for Konaban (4 Cases)

CASE I FOR 25 YEAR CASE II FOR 25 YEAR CASE III FOR 25 YEAR CASE IV FOR 25 YEAR

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended CA

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended

CA

CA Uninhibi

ted

CA Inhibited

Net CA

95% Availability

Recommended

CA

CA Uninhib

ited

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

MAX RECOMMEDED

CA


mm mm mm mm mm mm Mm mm Mm mm mm mm mm 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 2.56 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 To HP Separator Package 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 Produced Gas To Gas Scrubber Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

5 Condensate From HP Production Separator 1.37 NR NR 3 1.37 NR NR 3 2.86 NR NR 3 2.85 NR NR 3 3

6 Effluent From HP Production Separator 1.47 NR NR 3 1.48 NR NR 3 2.98 NR NR 3 2.98 NR NR 3 3

7 Produced Gas From Scrubber Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

8 Condensate From Gas Scrubber 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









CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended CA

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended

CA

CA Uninhibi

ted

CA Inhibited

Net CA

95% Availability

Recommended

CA

CA Uninhib

ited

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

MAX RECOMMEDED

CA



10 To Instrument Gas Header Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

11 Total Condensate To Condensate Stabiliser 1.37 NR NR 3 1.37 NR NR 3 2.85 NR NR 3 2.85 NR NR 3 3

12 Gas From Condensate Stabilser To Canteen Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

13 Condensate To Storage Tank 1.36 NR NR 3 1.36 NR NR 3 2.85 NR NR 3 2.84 NR NR 3 3

14 Condensate Transfer Pump Suction 1.36 NR NR 3 1.36 NR NR 3 2.85 NR NR 3 2.84 NR NR 3 3

15 Condensate Transfer Pump Discharge 1.36 NR NR 3 1.36 NR NR 3 2.85 NR NR 3 2.84 NR NR 3 3

16 Gas from Effluent Water Stabiliser to Canteen

Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

17 Effluent Water To Storage 1.48 NR NR 3 1.48 NR NR 3 2.99 NR NR 3 2.99 NR NR 3 3

18 Effluent Loading Pump Suction 1.48 NR NR 3 1.48 NR NR 3 2.99 NR NR 3 2.99 NR NR 3 3









CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended CA

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended

CA

CA Uninhibi

ted

CA Inhibited

Net CA

95% Availability

Recommended

CA

CA Uninhib

ited

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

MAX RECOMMEDED

CA



19 Effluent Loading Pump Discharge 1.48 NR NR 3 1.48 NR NR 3 2.99 NR NR 3 2.99 NR NR 3 3

20 CI Pump Suction Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

21 CI Pump Discharge Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

22 To Gas Dryer Package Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

23 Instrument Gas To Receiver Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

24 Condensate From Gas Dryer Package 4.3 NR NR 4.75 4.33 NR NR 4.75 9.45 2.37 2.73 3 9.45 2.37 2.73 3 4.75

25 Instrument Gas Header Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

26 Condensate From Instrument Gas Receiver

4.3 NR NR 4.75 4.33 NR NR 4.75 9.45 2.37 2.73 3 9.45 2.37 2.73 3 4.75

27 Instrument Gas to New Konaban GGS Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3









CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended CA

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended

CA

CA Uninhibi

ted

CA Inhibited

Net CA

95% Availability

Recommended

CA

CA Uninhib

ited

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

MAX RECOMMEDED

CA



28 Instrument Gas to Existing Konaban GGS Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

29 Condensate To OWS Header 4.3 NR NR 4.75 4.33 NR NR 4.75 9.45 2.37 2.73 3 9.45 2.37 2.73 3 4.75

30 Gas To Fuel Gas Scrubber Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

31 Fuel Gas From Fuel Gas Scrubber Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

32 Condensate From Fuel Gas Scrubber 0.97 NR NR 3 0.98 NR NR 3 2.16 NR NR 3 2.16 NR NR 3 3



34 Fuel Gas To IDBH Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

35 Fuel Gas To Flare Package Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

36 Fuel Gas To Flare Header Purging Dry Gas NR NR 3 0 NR NR 3 0 NR NR 3 0 NR NR 3 3









CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended CA

CA Uninhibi

ted

CA Inhibit

ed

Net CA 95%

Availability

Recommended

CA

CA Uninhibi

ted

CA Inhibited

Net CA

95% Availability

Recommended

CA

CA Uninhib

ited

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

MAX RECOMMEDED

CA



37 Fuel Gas TO Evaporation Pit Package


38 Gas From Existing Konaban GGS Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 3

39 Gas From Existing LP Sep. & Water Flash Drum








Table 9.1C Corrosion Summary For Utilities (Konaban)

Corrossion Allowance

(Unihibited) for 25 years

Corrossion Allowance

(Ihibited) for 25 years with 75%

efficiency

Net Corrossion Allowancewith

95% Availability


Stream Number

Stream Description

Mm Mm mm mm

50 Feed From New Konaban GGS to Flare KOD

0.49 NR NR 3

51 Flare Gas to Flare Package 0 NR NR 3

52 Condensate Transfer Pumps Suction 0.51 NR NR 3


54 Effluent Water From Flare Package to OWS System

0 NR NR CS (Galv.) C.A. 0mm

55 Oily Water from New OWS Header 2.92 NR NR 3

56 Oily Water from Existing OWS Header 2.92 NR NR 3

57 Condensate From OWS to Condensate Storage Tank

2.91 NR NR 3

58 Effluent Water From OWS to Effluent Storage Tank

0 NR NR 3

59 Bore well Pump Dischage 0 NR NR CS (Galv.) C.A. 0mm

60 Service Water To Flare Package 0 NR NR CS (Galv.) C.A. 0mm

61 Service Water To IDBH Package 0 NR NR CS (Galv.) C.A. 0mm

62 Potable Water To Safety Shower & Eye Wash Package KON-A-0420


63 Feed From Existing Konaban GGS to Flare KOD

2.2 NR NR 3

64 Potable Water To Safety Shower & Eye Wash Package KON-A-0720








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


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


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

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




9 Vent Gas DRY GAS NR NR 3














Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability



























Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability








PALATANA CASE SUMMARY

1 Gas From Sonamura GGS 3

2 Gas From ADB & Konaban GGS 3

3 To Gas Scrubber 3

4 Gas To OTPC Power Plant 3

5 Condensate To Condensate Stabiliser 3

6 Condensate To Storage Tank 3

7 Condensate Transfer Pump Suction 3

8 Condensate Transfer Pump Discharge 3

9 Vent Gas


FOR ALL 4 CASES IN PALATANA

3







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


CA Uninhibite

d

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibited

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibited

Net CA 95%

Availability

Recommended CA

MAX RECOMMED

ED CA


mm mm mm mm mm mm mm mm Mm mm mm mm mm mm mm mm mm

1 Gas From Sonamura GGS Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR NR 3

2 Gas From ADB & Konaban GGS 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 Gas To OTPC Power Plant Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR NR 3

5 Condensate To Condensate Stabiliser 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR NR 3

6 Condensate To Storage Tank 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR 3 0.98 NR NR NR 3

7 Condensate Transfer Pump Suction 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR 3 0.98 NR NR NR 3

8 Condensate Transfer Pump Suction 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR 3 0.98 NR NR NR 3








CA Uninhibite

d

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibite

d

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibited

Net CA 95%

Availability

Recommended CA

CA Uninhibite

d

CA Inhibited

Net CA 95%

Availability

Recommended CA

MAX RECOMMED

ED CA


mm mm mm mm mm mm mm mm Mm mm mm mm mm mm mm mm mm

9 Condensate Transfer Pump Discharge 0.99 NR NR 3 0.99 NR NR 3 0.99 NR NR 3 0.98 NR NR NR 3

10 Vent Gas Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR 3 Dry Gas NR NR NR 3







Table 9.3 : Corrosion Allowances Calculated for KUNJABAN MANIFOLDS


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


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

1 From Pig Launcher KUN-L-0101 7.54 1.89 2.18 3

2 From Pig Launcher KUN-L-0102 5.85 NR NR 5.75

3 From Pig Launcher KUN-L-0102 4.46 NR NR 4.5







Table 9.4 : Corrosion Allowances Calculated for ADB GGS


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


1 To Existing HP Header 6.51 NR NR 6

2 To Existing Test Header 6.65 NR NR 6

3 To Existing Test Header 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







Table 9.5 : Corrosion Allowances Calculated for SUNDALBARI MANIFOLDS


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


1 From Pig Launcher SUN-L-0101 8.08 2.02 2.33 3

2 From Pig Launcher SUN-L-0102 8.12 2.03 2.34 3

2 From Pig Launcher SUN-L-0102 4.54 NR NR 4.5







Table 9.6 : Corrosion Allowances Calculated for SONAMURA GGS


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


1 To Existing HP Header 7.71 1.93 2.22 3

2 To Existing Test Header 7.79 1.95 2.25 3

3 To Existing Test Header 7.79 1.95 2.25 3

4 To Existing MP Header 4.54 NR NR 4.5








Table 9.7 : Corrosion Allowances Calculated for NIMBUTALI JUNCTION POINT


Corrosion Allowance


Corrosion Allowance


75% efficiency


Availability


1 Gas From Konaban GGS DRY GAS NR NR 3

2 Gas From ADB GGS DRY GAS NR NR 3


Refer Annexure II for CORROSION CALCULATION SHEET FOR Various Streams.







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 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 cal

Documents

Final MSR Rev[1]. C