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 s.l.fisher@siep.shell.com

Mark Anderson +31 70 311 6149 m.anderson@siep.shell.com

Marc Amory +31 70 311 3506 m.e.amory@siep.shell.com

Gerard Mulder +31 70 311 6148 g.mulder@siep.shell.com

Matt Bayfield +31 70 311 6126 m.bayfield@siep.shell.com

Tony Cole +31 70 311 3049 t.cole@siep.shell.com

Wes Moore +31 70 311 3550 w.r.moore@siep.shell.com

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.