PETRONAS TECHNICAL STANDARDS DESIGN AND ENGINEERING PRACTICE
MANUAL
CORROSION INHIBITION OF DOWNHOLE PRODUCTION TUBING, PROCESS PIPING AND PIPELINES
PTS 20.210 OCTOBER 1995
PREFACE
PETRONAS Technical Standards (PTS) publications reflect the views, at the time of publication, of PETRONAS OPUs/Divisions. They are based on the experience acquired during the involvement with the design, construction, operation and maintenance of processing units and facilities. Where appropriate they are based on, or reference is made to, national and international standards and codes of practice. The objective is to set the recommended standard for good technical practice to be applied by PETRONAS' OPUs in oil and gas production facilities, refineries, gas processing plants, chemical plants, marketing facilities or any other such facility, and thereby to achieve maximum technical and economic benefit from standardisation. The information set forth in these publications is provided to users for their consideration and decision to implement. This is of particular importance where PTS may not cover every requirement or diversity of condition at each locality. The system of PTS is expected to be sufficiently flexible to allow individual operating units to adapt the information set forth in PTS to their own environment and requirements. When Contractors or Manufacturers/Suppliers use PTS they shall be solely responsible for the quality of work and the attainment of the required design and engineering standards. In particular, for those requirements not specifically covered, the Principal will expect them to follow those design and engineering practices which will achieve the same level of integrity as reflected in the PTS. If in doubt, the Contractor or Manufacturer/Supplier shall, without detracting from his own responsibility, consult the Principal or its technical advisor. The right to use PTS rests with three categories of users : 1) 2) 3)
PETRONAS and its affiliates. Other parties who are authorised to use PTS subject to appropriate contractual arrangements. Contractors/subcontractors and Manufacturers/Suppliers under a contract with users referred to under 1) and 2) which requires that tenders for projects, materials supplied or - generally - work performed on behalf of the said users comply with the relevant standards.
Subject to any particular terms and conditions as may be set forth in specific agreements with users, PETRONAS disclaims any liability of whatsoever nature for any damage (including injury or death) suffered by any company or person whomsoever as a result of or in connection with the use, application or implementation of any PTS, combination of PTS or any part thereof. The benefit of this disclaimer shall inure in all respects to PETRONAS and/or any company affiliated to PETRONAS that may issue PTS or require the use of PTS. Without prejudice to any specific terms in respect of confidentiality under relevant contractual arrangements, PTS shall not, without the prior written consent of PETRONAS, be disclosed by users to any company or person whomsoever and the PTS shall be used exclusively for the purpose they have been provided to the user. They shall be returned after use, including any copies which shall only be made by users with the express prior written consent of PETRONAS. The copyright of PTS vests in PETRONAS. Users shall arrange for PTS to be held in safe custody and PETRONAS may at any time require information satisfactory to PETRONAS in order to ascertain how users implement this requirement.
REVISION REGISTER
REVISION NO.
DATE
DETAIL OF REVISION
A
5/93
Draft document. No registered distribution
B
7/95
General Revision to Draft. No registered distribution
O
Initial Issue
CONTROLLED DISTRIBUTION LIST Copy No.
Registered Holder
01
ETS/4
02
ETS/6
03
PET/3
04
PET/33
05
OPM/41
06
EPD/63, SIPM
07
ME/122, KSLA
08
ETS/43
09
ETS/431
10
ETS/433
11
ETS/434
12 1314 15 16 17 18 19 20
Date Distributed
TABLE OF CONTENTS
1.
INTRODUCTION
1.1
PURPOSE AND SCOPE
1.2
ABBREVIATION .
1.3
CROSS REFERENCES
2
DESCRIPTION OF PRODUCTION AND TRANSPORT SYSTEMS
2.1
SINGLE-PHASE GAS SYSTEMS
2.2
SINGLE-PHASE LIQUID SYSTEMS
2.3
TWO-PHASE GAS-LIQUID SYSTEMS
2.3.1
Annular Dispersed Gas-liquid Flow
2.3.2
Stratified Gas-Liquid Flow
2.3.3
Slug Gas-Liquid Flow
2.4
TWO-PHASE LIQUID-LIQUID SYSTEMS
2.4.1
Dispersed Liquid-Liquid Flow
2.4.2
Separated Liquid-Liquid Flow
2.5
THREE-PHASE GAS LIQUID-LIQUID SYSTEMS
2.5.1
Annular Dispersed Flow With a Very High GLR
2.5.2
Stratified Flow With a Very High GLR
2.5.3
Stratified Flow With a Very Low GLR
3.
CORROSION INHIBITOR INJECTION DOSAGES
4.
REFERENCES
5.
TABLE
6.
ATTACHMENTS
1.
INTRODUCTION
1.1
PURPOSE AND SCOPE The purpose of this philosophy is to ensure that a structured approach is made and followed during the design stage and/or the production stage, in selecting an effective inhibitor for various production systems and transport systems. Due consideration is given to the possible occurences of corrosion under varying production scenarios particularly the liquid velocities, watercut factors and flow regimes. Corrosion control by inhibition in this case is applicable to carbon steel systems only. Selection of corrosion inhibitors is covered elsewhere (ref. 1,4). This philosophy should be used where it has been determined that a corrosion inhibitor is required, usually by corrosion modelling, field experience or field monitoring data. Other methods of corrosion control that reduce the corrosion rates to acceptable levels (e.g. deoxygenation of seawater injection systems} are not considered here. For any chemical selected, how the chemical portions between oil and water phases and the point of ultimate discharge of the water phase (including some chemical) must be considered. This philosophy gives recommendations for the type of inhibitor to be selected for specific flow environments. There will be cases where the alternative type of inhibitor is selected, even though in theory it is not be the most (cost) effective inhibitor. Typical reason for selection would be desire to minimise the number of different inhibitors used, proven track record, environmental considerations etc.
1.2
1.3
ABBREVIATION CO2
-
Carbon Dioxide
SRB
-
Sulphate Reducing Bacteria
CGR
-
Condensate Gas Ratio
GLR
-
Gas Liquid Ratio
HHP
-
High High Pressure
HP
-
High Pressure
H2S
-
Hydrogen Sulphide
CROSS-REFERENCES Where cross-references to other parts of the main text in this procedure are made, the referenced section number is shown in brackets. Documents referenced by this procedure are listed under references (4).
2.
DESCRIPTION OF PRODUCTION AND TRANSPORT SYSTEMS The production and transport systems in PETRONAS can be distinctly divided into three major systems, (Ref. 2), namely Single-Phase system, Two-Phase system and Three-Phase system. These three systems consists of production, transport and re-injection systems. A critical part of this analysis is to first determine the flow regime present. This can be done by using the hydraulic model “TWOPHASE” or the Shell corrosion models Wetgas7, for wetgas pipelines or Flowline7 for all other conditions.
2.1
SINGLE-PHASE GAS SYSTEMS The principal examples of single phase gas systems are:
2.1 .1
•
downhole tubulars below the level of liquid condensation
•
“dry” gas export pipelines.
Corrosion In single-phase gas systems no aqueous phase is present and aqueous corrosion thus cannot occur. For downhole tubulars generally liquid condensation will occur at some point in the tubulars. The depth where condensation occurs will vary through the life of the well, as pressures and temperatures change. Above the point of condensation the tubulars needs corrosion control measures. This portion of the well that is corrosive drives the corrosion control measures. The portion of the well that is technically non-corrosive, because it is only single phase gas, usually has to be protected to be able to protect the rest of the well, so no account can be made of the fact that this portion is non-corrosive. For "dry" gas export pipelines, where the gas is dried before transport to prevent formation of gas hydrates and corrosion, however an aqueous phase may still be present unintentionally under certain circumstances: -
insufficient drying of a line after hydrotesting,
-
temporarily bypassing or misoperation of the drying units,
-
due to glycol carry over.
-
inadequate drying of condensate reinjected into the line.
This condition will change the single-phase gas system to a two-phase gas-liquid system (2.3).
2.1 .2
Corrosion Control In true single phase gas systems corrosion control by inhibition is normally not required. However, in the event that the presence of a water phase is possible for extended duration, corrosion control measures may be required. In downhole tubulars the single phase portion of the tubulars has inhibitor injected in order to be able to protect the portion of the tubulars that is in two-phase flow. For “dry" gas pipelines, when the gas drying system goes out of specification some pipelines have systems installed to inject inhibitors as a protection system in this system which is now two-phase.
2.2
SINGLE-PHASE LIQUID SYSTEMS
2.2. 1
Corrosion Single-phase liquid systems in production and transport systems are systems where crude oil or gas condensate (usually containing dissolved water and gas) is produced, or where all the liquids are fully emulsified (i.e. no free water phase). The principal examples are: •
oil wells above the bubble point pressure and where the fluids are fully emusified. Note the depth that the well reaches the bubble point will depend on the pressures in the well and the reservoir. The bubble point pressure could be reached at or downstream of the wellhead, at some point in the tubulars or in the formation itself. For most mature oil wells (i.e. PETRONAS wells) the water cut is high and the pressures are relatively low, so that the tubulars contain 3 separate phase, oil, water and gas.
•
export oil lines ("trunklines"), where the gas has been separated from the oil and the water remaining in the oil is at a low enough concentration and high enough velocity to be fully emulsified or disposed (i.e. no free water phase). The minimum velocity to ensure no water dropout in these situation is above a critical value of at least 1 m/s (ref. 5).
•
water injection systems.
In single-phase liquid systems whenever the water content is higher than the amount which can dissolve molecularly the water will be present as a separate phase. From a corrosion stand point this starts to be a concern in a crude system at water cuts of > 40 % and/or at water cuts < 40 % with liquid velocities < 1 m/s Under this condition the system should be regarded as a two-phase liquid-liquid system (2.4). Note that the 40 % limit is believed to be conservative and there is ongoing research to redefine this limit. Further data on the critical water/oil ratio can be obtained by running the Wetgas7 or Flowline7 corrosion modelling programs. The effects of emusification of the crude/water also need to be considered. In the water injection systems, where produced water is re-injected and dissolved corrosive gases (CO2 and/or H2S) are not completely removed, corrosion may occur. In cases where seawater is injected to enhance oil recovery, the injected water is usually de-aerated to remove dissolved oxygen and chemically treated with biocides to suppress SRB-induced corrosion. If oxygen is present in the injected water (through leaks or poor de-aeration), the corrosion rates will be extremely high and unlikely to be economically treatable with inhibition; effort needs to be placed on first reducing the oxygen level in the water.
2.2.2
Corrosion Control In true single-phase condensate or oil systems, there is no free water phase, hence, corrosion control normally will not be needed. However there are few systems that are truely singlephase and these must be treated as two-phase or multi-phase systems. The conditions which would allow water to settle out must be clearly understood, before a system can be called "single-phase". Injection of corrosion inhibitor into water injection systems is generally not favoured because film forming corrosion inhibitors may block the reservoir pores. If this needs to be considered, specific tests with reservoir cores should be carried out.
2.3
TWO-PHASE GAS-LIQUID SYSTEMS An aqueous phase in contact with the steel wall is a pre-requisite for aqueous corrosion. In two-phase gas-liquid systems the systems of concern are where the liquid phase is water or a (single phase) aqueous mixture (e.g. glycol and water mixtures). Two phase systems with no free water phase are non-corrosive, so are not considered further. In these two-phase systems the corrosivity will depend upon the flow regime present.
2.3.1
Annular Dispersed Gas-Liquid Flow At relatively high superficial gas velocities and relatively low superficial water velocities the flow pattern in the two-phase gas-water flow will be annular-dispersed, (ref. 3). This situation occurs in production tubings, flowlines, gathering lines of gas wells with low CGRs and in gaslift lines when water (but no gas condensate) has condensed from the gas or is produced from the formation.
2.3.1.1 Corrosion With respect to corrosion, the two-phase gas-liquid systems being considered with annulardispersed flow have an aqueous phase in contact with the steel pipe wall over the whole circumference of the pipe, and are consequently corrosive.
2.3.1.2 Corrosion Control Continuous injection of corrosion inhibitors soluble in water or water/glycol mixtures is recommended, Ref. 2 and Attachment 2. Corrosion control by continuous injection of an inhibitor soluble in a hydrocarbon phase into the system is not recommended. If a hydrocarbon soluble inhibitor was used, since there is no continuous hydrocarbon phase in this situation, the inhibitor would not be transported to all the locations where it is required.
2.3.2
Stratified Gas-Liquid Flow In horizontal and inclined pipes the annular-dispersed flow pattern can change to a stratified flow pattern upon a decrease of the superficial gas velocity. For vertical flow such a transition does not occur. The stratified gas-water flow pattern is usually found: - in trunklines where an aqueous phase (but not gas condensate) has condensed from the gas which has been insufficiently dried, or dried with glycol such as in gaslift lines from compression platforms, or - when natural gas separated from co-produced liquids, but not dried, is transported such as in gaslift lines from HHP and HP separators.
2.3.2.1 Corrosion In a non-vertical pipeline operating in stratified two-phase gas-liquid flow the bottom of the line will be in contact with the aqueous phase. The top of the line will be in contact with the flowing vapour phase of the system. In practical situations this means that the top of the line will be wet due to water condensation. The latter may occur due to temperature gradient across the pipe wall or due to capillary condensation of water vapour in the pores of the corrosion products present on the pipe wall.
2.3.2.2 Corrosion Control With respect to the control of corrosion in the bottom of the line in pipelines operating in stratified two-phase gas-water flow, addition of corrosion inhibitors soluble in water or water/glycol mixtures is recommended, (Ref. 2). Corrosion control by continuous injection of an inhibitor soluble in a hydrocarbon phase into the system is not recommended, (2.3.1.2) Control of corrosion in the top of the line is only possible by: -
addition of a vapour phase corrosion inhibitor to the gas phase, or
-
mechanical transport of water soluble or water/glycol soluble corrosion inhibitors to the top of the line. Transport of corrosion inhibitor to the full bore of the pipeline is possible by batching a volume of corrosion inhibitor between two batching pigs through the line.
2.3.3
Slug Gas-Liquid Flow
2.3.3.1 Corrosion With respect to the occurrence of corrosion, systems operating in slug flow of gas and liquid have to be regarded as being in single-phase liquid flow for a time fraction, t, and in stratified flow for a time fraction, 1-t. The fraction t is determined by Eq(1) as follows:
t = f × (L / v )
Eq(1)
where: L
= length of pipeline ft
v
= mixed gas/liquid velocity ft/s
f
= frequency of the slugs
2.3.3.2 Corrosion Control With respect to corrosion control methods a two-phase gas-liquid system operating in slug flow has to be treated either as a: -
two-phase gas-liquid system operating in annular-dispersed flow or
-
two-phase gas-liquid system operating in stratified gas-liquid flow.
The choice will depend on the value of t in Eq(1) above. For both cases, continuous addition of the corrosion inhibitors soluble in water or water/glycol mixtures is recommended, (Ref. 2). Corrosion control by continuous injection of an inhibitor soluble in a hydrocarbon phase into the system is not recommended.
2.4
TWO-PHASE LIQUID-LIQUID SYSTEMS In practical situations the liquid phases are an aqueous phase and a hydrocarbon phase. The local flow condition of this system will affect the place and rate of corrosion. The extremes of the possible flow conditions are separated flow and dispersed flow of both liquids.
2.4.1
Dispersed Liquid-Liquid Flow Dispersed flow of two-immersible liquids, such as oil and water for horizontal/inclined flow and vertical flow regime are described in detail in ref. 3. Either the aqueous phase or the non-aqueous phase can be regarded to be the continuous phase. In crude systems with a high water to oil ratio i.e. a water cut > 40% and/or a water cut < 40% with liquid velocities < 1 m/s, the aqueous phase (water) will generally form the continuum (see comment on the 40% limit in 2.2.1).
2.4.1.1 Corrosion For aqueous corrosion to occur the aqueous phase must be in continuous contact with the steel wall.
2.4.1.2 Corrosion Control The choice of inhibitors is between either water soluble/oil dispesible inhibitors or oil soluble/water dispesible inhibitors. In deciding on which type of inhibitor to use, consideration should be made for: -
which is the continuous phase, i.e. will the inhibitor reach all areas where it is required?
-
what are the economics for the two types of inhibitor.
No definite guidelines can be given - each case must be reviewed separately. Generally for high water cuts a water-soluble/oil dispesible corrosion inhibitor is used and for low water cuts an oil-soluble/water dispesible corrosion inhibitor is used. There is a middle range of water cuts where either type of inhibitor can be used.
2.4.2
Separated Liquid-Liquid Flow In horizontal and inclined pipeline at moderate flow velocities, separation of the dispersed flow will occur. The resulting separated flow condition can be described as a dispersed two-phase liquid-liquid system, (2.4.1).
2.4.2.1 Corrosion For aqueous corrosion to occur the aqueous phase must be in continuous contact with the steel wall.
2.4.2.2 Corrosion Control Corrosion control in for flow regime is the same as for dispersed liquid-liquid flow (2.4.1.2).
2.5
THREE-PHASE GAS-LIQUID-LIQUID SYSTEMS In the majority of practical situations the prevailing systems have three phases in equilibrium: -
saline water,
-
liquid hydrocarbon phase and
-
gas phase
In systems producing crude oil, the crude oil may act as a “natural inhibitors”; note however that it is very unlikely that condensate will act as a natural inhibitor in gas production systems.
2.5.1
Annular Dispersed Flow With a Very High GLR Fluid flows with a high to very high gas-liquid-ratio (GLR) can be described as two-phase gasliquid systems. In annular dispersed flow, droplets of water and gas condensate or oil will be entrained in the gas core. On the wall of the pipe a liquid film will be present.
2.5.1.1 Corrosion If there is separate flow of water and gas condensate or oil and the water phase is in contact with the pipe wall the corrosion characteristics of the system can be described as for the case of an annular dispersed two-phase gas liquid system (2.3.1).
2.5.1.2 Corrosion Control Corrosion control for this flow regime is generally the same as for two-phase gas liquid systems (2.3.1.2). However, for this flow regimes if the water in the film is dispersed i.e. water is dispersed in the gas condensate or oil phase then an oil-soluble/water-dispersable corrosion inhibitor is recommended because the continuous phase in the liquid film is hydrocarbon.
2.5.2
Stratified Flow With a Very High GLR In stratified flow in horizontal and inclined pipes the corrosion and inhibition aspects can be described by a two-phase gas-liquid model with respect to the corrosion mechanism and control (2.3.2).
2.5.3
Stratified Flow With a Very Low GLR Three-phase gas-liquid-liquid systems with a very low GLR can be in most cases be described as two-phase liquid-liquid systems with respect to the corrosion mechanism and corrosion control (2.4).
3.
CORROSION INHIBITOR INJECTION DOSAGES The initial injection rates of the corrosion inhibitors shall be governed by the minimum recommended level of residual concentrations required in the hydrocarbon phase and the water phase for optimum protection. This criteria shall be provided by the individual corrosion inhibitor Suppliers specific for their respective products and verified by Company laboratories. These rates need to be later optimised by the use of field tests and review of corrosion rates.
4.
5.
REFERENCES/RELATED GUIDELINES 1.
Engineering Guideline No DIN:ECG.XXX.4001 Selection of Corrosion Inhibitor Systems for Downhole Production Tubing, Process Piping and Pipelines.
2.
Flow effects on corrosion of carbon steel by L. Van Bodegom and U. Lotz, KSLA, Corros. Prev. Process Ind., Proc NACE Int. Symp., 1 st Meeting date 1988, page 123-138, Editor Parkins and N. Redvers, Publisher, NACE Houston Texas USA.
3.
Production Handbook, Vol. 8
4.
Selection and set-up of laboratory test methods for corrosion inhibitors for sweet oil and gas production and transport, S.F. Keij, KSLA report AMGR.95.236.
5.
Fluid flow aspects of corrosion - Field measurements of water distribution in eight PDO pipelines, J.F. Hollenberg and B.F.M. Pots, AMGR.95.014.
TABLE 1.
6.
Summary of Systems, Corrosion and Corrosion Control.
ATTACHMENTS 1.
Single Phase Systems
2.
Two Phase Gas-Liquid (water) Systems
3.
Two Phase Liquid (oil) - Liquid (water) Systems
4.
Three Phase Gas-Liquid (oil) - Liquid (water) Systems
TABLE 1 – SUMMARY OF SYSTEMS, CORROSION AND CORROSION CONTROL
ATTACHMENT 1 – SINGLE PHASE SYSTEM
ATTACHMENT 2 – TWO PHASE GAS-LIQUID (WATER) SYSTEMS
ATTACHMENT 3 – TWO PHASE LIQUID (OIL) – LIQUID (WATER) SYSTEMS
ATTACHMENT 4 – THREE PHASE GAS-LIQUID (OIL) – LIQUID (WATER) SYSTEMS
