P267 Applied Production TechnologyCorrosion Engineering
Tony Cole
EPT-DW
Completions and Multi-lateral Technology Team
RTS Rijswijk
+31 (0)70 311 3049
Completions and Multi-lateral Team
Simon Fisher +31 70 311 3242 [email protected]
Mark Anderson +31 70 311 6149 [email protected]
Marc Amory +31 70 311 3506 [email protected]
Gerard Mulder +31 70 311 6148 [email protected]
Matt Bayfield +31 70 311 6126 [email protected]
Tony Cole +31 70 311 3049 [email protected]
Wes Moore +31 70 311 3550 [email protected]
Multi-lateral wellsmultiple reservoirs single reservoirsmultiple reservoirs single reservoirs
Completions and Multi-lateral Team
Advanced completion design ML well technology
Casing exiting using milling/explosives Novel multi-lateral junction designs
Expandable systems, monobore completions, slim wells
Materials selection/new materials/preparation of standards Materials advice Testing procedures/Industry Standards
New coiled tubing technology Amorphous bonding Use of CRA’s with orbital TIG
ML database/newsletter/web site Dissemination of latest completions technology http://swwrij.siep.shell.com/cc/dw/cmlt/home.htm
Useful URL’s
CMLT Team - http://swwrij.siep.shell.com/cc/dw/cmlt/
Corrosion engineering discussion site - http://sww1.epglobal.shell.com/forums/aca-16/dispatch.cgi
Well engineering discussion site - http://sww1.epglobal.shell.com/forums/welleng/dispatch.cgi
Objectives
Introduction to:
The types of corrosion which may occur in downhole environments
Methods to prevent corrosionMethods to find corrosion
Provide enough background knowledge to allow you to question Corrosion decisions in an intelligent way.
Contents
General Corrosion PrinciplesCorrosion expected in Oil and Gas facilitiesPreventionMaterials selection guidelinesMonitoring and Measuring
Applicable specificationsNon-NACE*
API 5CT / ISO 11960 (under rev.) Steel pipes for casing and tubing of wells
API 6A / ISO10423 Wellhead and christmas tree equipment
API 17D Sub-sea wellhead and christmas tree
equipment ISO 13680 CRA tubes for use as casing and tubing
*NACE = National Association of Corrosion Engineers
Applicable specificationsNACE
MR0175SSC resistant metallic materials for oilfield equipment RP0475 Selection of metallic materials to be used in all phases of water handling
for injection into oil-bearing formations
MR0176 Metallic materials for sucker rod pumps for corrosive oilfield environment
TM0177 Lab. Testing of metals for resistance to specific forms of environmental cracking in H2S environments.
RP0273 Handling and proper usage of inhibited oilfield acids
RP0291 Care, handling and installation of internally plastic-coated oilfield tubular goods
RP0186 Application of CP for external surfaces of steel well casings
Electrochemical cell
Electrochemical in nature
Involves the transfer of electrons Requires electron path and ionic path
Requires two half reactions
Production of electrons Fe Fe2+
+ 2 e-
Allows consumption of electrons H+
+ e-
H
General Corrosion Principles
Must consider two aspects
Thermodynamics - Willingness to corrodeMeasured using potential difference (Voltage)
Kinetics - Rate of corrosionIndicated by electrical current flowIncreases with concentration/temp./fluid velocity
General Corrosion Principles
Thermodynamics
Pourbaix diagrams
For particular conditions these demonstrate the stability of metals
They suggest different methods of mitigating corrosion
Lower potentialRaise pHRaise potential
They do not say anything about the kinetics, or rate, of corrosion
Galvanic Series
Electrochemical series indicates the relative thermodynamic stability of metals under standard conditions
Galvanic series indicate relative stability of metals in “real” environments Note that joining dissimilar metals may lead to
rapid attack of the least noble one, however if there is no aggressive species corrosion will not take place.
This forms the basis for sacrificial anode cathodic protection
Galvanic attack may also happen if there are significant metallurgical differences in one piece of metal (eg. Heavy local cold working such as tong marks)
Kinetics
Evans diagram and related Potential/Current graphs Illustrates the speed of a reaction Illustrates how exposure to different
environments can create a galvanic cell
Can be used to demonstrate how changes in the environment might affect the corrosion rate
Can be determined for simulated conditions and used in the materials selection process
Illustrates a way to measure corrosion “instantaneously” in the field
Electrochemical measurements
Electrochemical measurement, whether done in the lab or in the field, require three electrodes.
A. Sample
B. Reference
C. Auxillary
They are used to determine:
a. corrosion rates
b. current required for CP
c. polarization behaviour
High impedance voltmeter
Ammeter
Types of corrosion
Unusual types of corrosion
Ring-worm corrosionLocalized corrosion around box end
Wireline attack (also in coated tubing) Internal scratches along the tubular corrode rapidly
Caliper track corrosionSimilar to wireline attack, but caused by the feelers of the
caliper tools
Sucker rod failureOften caused by pitting, then fatigue
Tong damageMay lead to localised corrosion
Wireline damage - WI well ExPro
What makes Wells special…...
Geometry There are usually concentric strings of casingDirect corrosion monitoring is difficult, preferably non-
intrusive (or it’s usually high cost)
To a certain extent the annulus environment can be controlled
Completions designs are determined by: tubing size required for flow performancemechanical integrity (principally tension, burst and collapse)
Life expectancy (typically the time to a workover, usu. 10 years)
Tubing, casing and jewelry to considerAcidisation for stimulation may be a factor
Potential corrosion sites in a well...
Internal casing corrosion
Internal casing corrosion can occur in the absence of a packer or if the packer fails.
Water can condense at cool areas on the casing and H2S and/or CO2 can corrode the steel.
The tubing wouldn’t necessarily be corroded at the same area because fluid travelling along it may keep its temperature above the dew point
Factors influencing corrosion
Aggressive species Water plus
O2
CO2
H2S
Cl-
Others Pressure Temperature Flow rate pH Bicarbonate Bacteria Galvanic couples Differential concentration Dew point Inhibitor Coating/lining
Corrosion rates - Species dependency
O2 is about 80 times more corrosive than CO2 and 400 times more corrosive than H2S
Common corrosion reactions
Sweet corrosion
CO2+ Fe + H
2O FeCO
3 +
H2
Half reactions
CO2+ H
2O 2H
+
+
CO3
2-
Fe Fe2+
+ 2e-
Sour corrosion
H2S + Fe FeS + H
2
Half reactions
H2S 2H
+
+ S
2- 2H
+ + 2e
-
H
2
(disassociates in water)
Fe Fe2+
+ 2e-
Sweet
General corrosion (calculate using model. Shell uses Hydrocor
which has been provided)
Pitting Leaks Grooves
Scaling
The types of corrosion caused
Sour
Hydrogen induced cracks Sulphide stress
cracking (esp. < 80 C) Blistering
The types of corrosion caused
Chloride
Pitting Stress corrosion cracking of
corrosion resistant alloys(esp. above 80 C)
Mitigation methods
Engineer Permanent solution particularly for corrosion
which can cause rapid/sudden failure Increases CAPEX
Operate Adds to OPEX Requires confidence in Operations and
commitment
Mitigation methods:Operations
Remove the corrosive species Downhole dehydration? Injection of chemicals to prevent or remove H2S
Inhibit Continuous Batch
Cathodic protection (for casing) Impressed (continuous or pulsed for casing protection) Sacrificial
Inhibitor application: Batch
Tubing displacement and Squeeze treatments Inhibitor flowed through tubing For displacement the tubular is filled and the
well shut-in. With squeeze the inhibitor is injected through the tubular into the reservoir
Typically shut-in for a day Inhibitor residuals monitored at wellhead Another treatment is necessary when ppm falls
below a pre-determined level May require one treatment every 3 or 4 months Squeeze protects below the packer
Inhibitor application Batch
Weighted inhibitors Intended to fall to rat hole and slowly release
Encapsulation Inhibitors encapsulated in polymer gel are introduced into the well, either in a
basket or in the rat hole.
Inhibitor applicationContinuous
Continuous Through the production annulus Into the casing through a valve
positioned in a side pocket It’s possible to inject into a specific
region of the string Can simply fill the annulus with
inhibitor and inject through a gas lift valve, but this lacks control.
Doesn’t protect below the packer
Casing cathodic protection
Usually requires quite large currents Is difficult to directly measure the affect of applying current
Often attenuation calculations are used to give a comfortable feelingCasing pressure surveys may be used to measure success, provided
enough baseline data existsRemote well-head measurements are often used
Can cause interference with flowlines, other wells or surface equipment. For this reason well-heads require good electrical insulation (also to prevent galvanic problems)
Groups of wells are usually protected simultaneouslyTo ensure CP to the bottom of the casing, current is sometimes
pulsed
E lg i for cathodic protection - Equipment
Well casings may need cathodic protection
Obtaining E lg I data is an accepted method of determining current requirements.
“Instant off” readings should be used
The reference electrode should be remote from the well head
Note the similarity between this set-up and that shown earlier regarding determination of corrosion rate and V-i graphs.
E lg i for cathodic protection Results
Results look similar to lab’ tests on small coupons
The change in gradient as the Tafel portion of the slope is reached gives an indication of current
However it is only an indication and should be supported by other techniques to provide greater confidence
Monitoring and measuring
Split into two categories Intrusive
Those which require production to stop
Non-intrusiveCan be done without interrupting flow
Monitoring and measuring
Downhole calipers, mechanical, magnetic, ultrasonic Video cameras Downhole CP logging tools Weight loss coupons Electrochemical techniques (LPR, EIS, potentiodynamic)
Hydrogen probes Electrical resistance probes Field signature monitoring Intelligent pigging of pipelines Conventional non-destructive test techniques (UT etc..)
Monitoring and measuring: Intrusive
Downhole calipers: mechanical, magnetic, ultrasonic Video cameras Weight loss coupons/Electrical resistance probes Electrochemical techniques (LPR, EIS, potentiodynamic)
Downhole CP monitoring using logging tools (casing potential profile tool)
Inspection of recovered tubing Pressure testing
Kinley Mechanical Caliper tool (www.kinley.com)Other similar tools available eg. www.read-well.co.uk/mfctool.htm - electronic versionwww.mws.no/mws.nsf/pages/FrameSet3
Simultaneous, Continuous and Independent movement of each feeler is recorded on
a “CHART” housed inside the Caliper .
Feeler Section
Drive Section
Rotation of Drive Wheel is transmitted through a
Transmission system which feeds the
“CHART” past the recording Stylus’.
Trip Section operates like a
Tubing End Locator. Once the survey depth is reached, pick up,
shear pin and begin survey.
Trip Section
Centralizer
Male Quick-Lok Connection on Top
Three Centralizer Shoes one each 120O
Kinley caliper - Fingers
The movement of the Feeler is transmitted through the Feeler Spring to the recording Stylus and this action is “SCRIBED” on the Chart for each of the Feelers. The recordings are wrapped around the outside of the Survey Chart.
Kapuni Caliper corrosion.
Kapuni Caliper Corrosion
Ultrasonic corrosion inspection tool (Schlumberger)http://www.connect.slb.com
Features:
Rotating pulse-echo transducer gives 360° coverage. High-resolution focused transducer quantifies even small defects on bothinternal and external casing surfaces. Precise first echo time gives accurate and detailed internal radiusmeasurement. Second echo time gives casing thickness. Internal and external surface echo amplitudes give a qualitative visual image of casing condition. Well-site presentation is corrected for tool ex-centralization effects.
Features:
Rotating pulse-echo transducer gives 360° coverage. High-resolution focused transducer quantifies even small defects on bothinternal and external casing surfaces. Precise first echo time gives accurate and detailed internal radiusmeasurement. Second echo time gives casing thickness. Internal and external surface echo amplitudes give a qualitative visual image of casing condition. Well-site presentation is corrected for tool ex-centralization effects.
Detailed examination of both inner and outer casing surfaces, ranging indiameter from 4 1/2 to 13 3/8 in.Detailed examination of both inner and outer casing surfaces, ranging indiameter from 4 1/2 to 13 3/8 in.
Multi-finger calipers can examine only the internal surface and may even damagethe casing. Flux leakage instruments presently offer limited accuracy and coverage.
Good resolution of the UCI tool is due to the very high transducer frequency of 2 MHz. The signal is, however, attenuated by the bore-hole fluid, and for best results brine, oil or very light muds should be used (no solids).
Logging rate is 425 to 3000 ft/hr depending on sampling rate.
Not much use if solids are present in the fluids (noise!)
Multi-finger calipers can examine only the internal surface and may even damagethe casing. Flux leakage instruments presently offer limited accuracy and coverage.
Good resolution of the UCI tool is due to the very high transducer frequency of 2 MHz. The signal is, however, attenuated by the bore-hole fluid, and for best results brine, oil or very light muds should be used (no solids).
Logging rate is 425 to 3000 ft/hr depending on sampling rate.
Not much use if solids are present in the fluids (noise!)
Schlumberger UCI
The UCI takes 180 highly focused measurements during each revolution of the ultrasonic sensor. It has up to 5 rotations every inch of travel inside the casing and can measure pits and other anomalies down to diameters of approximately 8 mm on either the inside or outside surface.
The UCI takes 180 highly focused measurements during each revolution of the ultrasonic sensor. It has up to 5 rotations every inch of travel inside the casing and can measure pits and other anomalies down to diameters of approximately 8 mm on either the inside or outside surface.
Casing potential profile - Equipment
A casing potential profile is a measurement of the difference in potential between two points inside the casing not a measure of the casing to soil potential which is indicative of the likelihood of corrosion.
Typically the contacts are 3 to 10 metres apart with wires brought up to surface and connected across a voltmeter
The tool is moved along the inside of the casing with potential difference measurements taken as needed.
Casing potential profile - Results
It is usual to run the tool without CP to get baseline data and then with CP.
A positive shift indicates current flow up the casing
In the example on the left the entire casing appears to be receiving current
Note that the tool does not indicate the casing to soil potential and therefore does not provide direct information about external corrosion.
Corrosion monitoring - Application limits
A variety of monitoring devices can be inserted downhole. The amount of time between insertion and retrieval with useful information depends on the sensitivity of the probe
Downhole corrosion monitoring
Monitoring and measuring: Non-intrusive
Wellhead and remote CP monitoring (external casing)
Inspecting tubulars retrieved for some other purpose Iron, Mn or bacterial counts Inhibitor concentration monitoring Annulus pressure monitoring Monitoring of flowlines and/or other surface equipment
using conventional methods to infer well conditions Electrical resistance probes Electrochemistry UT etc..
Mitigation methods
Corrosion allowance Remove the corrosive species
Prevent ingress/gas blanket Scavenge Kill bacteria
Cathodic protection Impressed (continuous or pulsed for casing protection) Sacrificial
Resistant materials Solid corrosion resistant material CRA Clad CRA (low alloys to nickel alloys) Coatings/linings Composite materials (fibre reinforced plastics)
Inhibitors A combination of these methods
…the damage they cause….
Sweet corrosion Pitting
At best - pin hole leaks
Deep grooves along wetted areas of gas lines
May lead to rupture
Often accompanied by severe scaling
Susceptibility increases with; Increasing pp(CO2) Increasing velocity Increasing Temperature Presence of particulates
Sour corrosion Hydrogen induced cracking
Sulphide stress cracking Step-wise cracking Blistering Hydrogen assisted ductile failure
FeS dust can also block gas line filters
Susceptibility increases with; Increasing pp(H2S) Increasing hardness/strength Decreasing pH/Temperature Increasing stress (residual or applied)
Mid-wall cracking caused by H2S
….and how to prevent it
Sweet corrosion Dehydration Corrosion resistant material
13 Cr or better Non-metallic
Use inhibitor Prefer continuous application Batching is possible Require tests to determine most effective Need to ensure it gets to the correct
location
Coat/line Insert lining into new/existing line
(particularly for water disposal) Coat with GRE/FBE/PE (sometimes used
for down hole eqpt.)
Sour corrosion Dehydration Resistant material
SSC NACE qualified materials Bear in mind the potential for other
kinds of failure Requires qualification; slow strain and
ripple strain tests now used
Apply inhibitor (As sweet, opposite)
Coat/line (ie. Isolate from environment)
Remove hydrogen sulphide Use NACE criteria (see next slide)
Factors influencing the choice of materials
Mechanical properties required Dimensions and strength of material governed by well characteristics Corrosion allowances are not normally used
Require lowest life cycle costs (often emphasise is on capex) Corrosion which may cause sudden failure (eg. SCC, SSC) must be designed
out Cost of failure (eg. offshore v onshore)
Worst case composition, pressure, temperature and flow velocity of fluids Differences between tubing/casing/wellhead Internal and external
Confidence in ability to operate within boundary conditions How accurate is the well data (esp. during the engineering phase) Can inhibition continuity be guaranteed Will water break through occur, will H2S levels increase with age
NACE MR 0175-97 Criteria for Sour Service
API 5CT Compositions
Corrosion and API5CT/ISO 11960
For sweet service, where calculated CO2 corrosion rates are high L80 type 13 Cr should be the minimum grade specified. If H2S is also present the synergistic effect can require a higher alloy.
Consult NACE MR 0175 for temperature limitations on the use of carbon steel materials in sour environments.
At low temperatures the relatively high strength materials C90 and T95 may be used in sour environments because they are tested for resistance against SSC during the manufacturing procedure. Specify NACE type D testing.
API 5CT and SSC
Paragraph 6.2.12 of 5CT - Refers to SSC
Effect of temperature on CO2 corrosion
Note: CO2 corrosion is flow sensitive, turbulence can remove the protective carbonate scale. It’s not good practice to rely on high temperature alone to reduce corrosion to an acceptable level.
Manufacturers selection guide
Based on NACE, with additional data to allow selection of CRA’s.
Manufacturers materials selection guideline
NAM Materials Selection Guide
NB. Should be used in conjunction with the .DOC guideline document .
Draft Shell Oil Guidelines
See the .xls spreadsheet CRA from Shell Oil.
Bear in mind that this is a guide only and that the recommendations are incomplete.
Relative costs of common OCTG materials(carbon steel = 1).
GRE 2.513% Chrome 3.5Super 13% Chrome 722% Chrome 9.525% Chrome 10Incoloy 825/Sanicro 28 20Inconel 625/C276 40
Tests for materials selection
First phase
Expose in the (simulated) environment and determine weight loss, pit density/depth
For SSC determine hardness
Second phase
Sulphide stress crackingDouble cantilever beam testing to determine K1ssc (NACE type D
pass 33 MPam)
For stress corrosion cracking use ripple testing
You now know:
Types of corrosion and how to prevent them
Data required to select an appropriate corrosion mitigation technique
Some fundamental corrosion knowledge to allow you to challenge corrosion decision in an intelligent way.
Glossary
AC Impedance spectroscopy- A technique used to measure corrosion rates over a short period of time (half an hour test). Also known as electrochemical impedance spectroscopy or EIS.
Carbon dioxide corrosion - dissolved in water, carbon dioxide forms an acid which reacts to corrode steel and form a scale, the scale becomes protective at higher temperatures. Cathodic protection - A means of reducing or preventing corrosion by altering the electrical potential of the structure being protected so that it is thermodynamically stable. This
can be achieved by either deliberately forming a galvanic cell with a more reactive material (eg. Zn, Mg or Al) or by applying an impressed current. When applying an impressed current it is important that the potential of the structure is controlled to prevent excessive production of hydrogen which may cause cracking.
Differential concentration - corrosion cells may be set up because different potentials are caused when varying concentrations of aggressive species are present across a metal surface. One of the most common types of differential concentration cell is the “differential aeration cell.” where differences in oxygen concentration lead to higher corrosion rates where there is less oxygen (this is why corrosion is often found under washers and at crevices)
Environmentally assisted failure - A general term used to describe failure mechanisms where the co-joint action of stress and corrosion caused by the environment results in an apparent loss of ductility. Eg. Hydrogen induced cracking, hydrogen assisted ductile failure, stress corrosion cracking, corrosion fatigue, hydrogen blistering, liquid metal embrittlement
Erosion corrosion - Corrosion products may be removed by fast moving fluids or solids. Once removed the corrosion product re-forms and this repeated removal/reforming can lead to rapid failure. Often occurs in combination with carbon dioxide and hydrogen sulphide corrosion where a carbonate scale or sulphide film, which may otherwise protect against further corrosion, is removed.
General Corrosion - Corrosion which occurs over a large surface area, as opposed to forming pits, cracks etc. In practice very few instances of corrosion are really “general,” most “general” corrosion starts life as discrete pits which then broaden and merge.
Galvanic corrosion - When two metals which have adopted different natural potentials are electrically connected the voltage between them can accelerate corrosion of one and reduce it in the other. This is known as galvanic corrosion. High alloy valves connected to carbon steels pipe with a conductive fluid passing through may allow galvanic corrosion to take place.Under some circumstances, where a piece of corroded steel is connected to a clean piece of steel for example, the galvanic couple can cause rapid failure of the “new” piece of metal.
Hydrogen induced cracking (HIC) - Cracks caused by the accumulation of hydrogen in metals. Hydrogen may result from reactions with hydrogen sulphide gas but may also be created by over enthusiastic application of a cathodic protection system.
Hydrogen sulphide - A corrosive species which reacts to form FeS and hydrogen. Particularly nasty because it a. produces monotonic hydrogen and b. sulphur poisons the hydrogen re-combination reaction. This allows hydrogen to travel into the metal lattice where it can cause serious damage. In addition to general corrosion and pitting, dramatic failures can occur because hydrogen in lattice can cause blistering, cracks and significant reductions in ductility. In general, cracking becomes more of a problem as strength increases. However, if the temperature is high then hydrogen tends to diffuse more readily, it then doesn’t accumulate and hydrogen damage is less likely to occur. In fact it is possible to “bake out”hydrogen and return affected materials to their original condition, but this isn’t an option in a well!
Intergranular corrosion - During heat treatment, manufacture or welding metallurgical changes can take place which cause grain boundaries to adopt a significantly different electrical potential to grains. This can lead to accelerated corrosion at the boundary and may lead to cracking.
Glossary (Cont.)
LME Liquid metal embrittlement - Liquid metal (eg mercury or other metals (eg. lead, aluminium, tin, zinc) at higher temperatures) wets the grain boundary of metal and causes grains to separate. Unusual in EP, although there have been instances where lubricants containing these metals have been used at high temperatures and LME has caused failure!
Microbially induced corrosion - Degradation as the result of the metal reacting with products created by bacteria, particularly sulphate reducing bacteria (SRB’s) which are found in anaerobic conditions. Typically at temperatures below 80 Celsius.
NACE - National Association of Corrosion Engineers. A professional institute which has developed Recommended Practices, Materials Requirements and Test Methods in the field of corrosion. Now known as NACE International.
Oxygen - A corrosive species which is not usually found downhole although it may be present (particularly in beam pumped wells) and may present in injection waters.
Pitting - A form of localised corrosion in which the depth of metal removed from the surface is significantly greater than the width of the corroded area. Environments within pits can become extremely aggressive (pH 1or less in some stainless steels) and this can lead to rapid penetration of casing/tubing/vessels etc.. Because of the changes in local environment and geometry of the defect this type of corrosion can be particularly difficult to stop once it has started. Pits may also act as stress concentrators enhancing fatigue and/or hydrogen cracking.
SCC Stress corrosion cracking - One of a number of failure modes resulting from the combined effects of tensile stress (applied or residual) and the environment. Often leads to catastrophic failure because the cracks are not easily detected. Occurs readily in metals and alloys which passivate in combination with a species which breaks down the passive layer. Combinations include Brass with Ammonia (the first to be discovered) and austenitic stainless steels with chlorides. May be intergranular or transgranular depending on the alloy/environment combination. Unlike hydrogen induced cracking, SCC is more severe at higher temperature and in stainless steel is rare below approx. 65 Celsius.
SSC Sulphide stress cracking - A form of HIC which develops in sour service through the presence of hydrogen sulphide gas. A particular problem where operating conditions are below 60 Celsius and in high strength steels.
Sour Service - See detailed definition in NACE MR0175. Note that it is the purchasers responsibility to ensure that materials are suitable for use in sour service, and that they are resistant to other forms of corrosion which may occur in the environment. Rigorous materials qualification through laboratory testing is often required.
Weld decay - The rapid heating and cooling of stainless steels associated with welding can lead to the formation of chromium carbides in an area adjacent to the weld. This depletes the area of free chromium and prevents formation of a passive film allowing corrosion. This phenomena can be avoided by specifying very low carbon or stabilised steels.