NACE Corrosion 2008 Paper No. 08089 - Material Selection for Turnaround Wells an Evaluation of the Impact Upon Downhole Materials When Mixing Produced Water and Seawater - Scoppio

Copyright ©2008 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Copyright Division, 1440 South creek Drive, Houston, Texas 777084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.

MATERIAL SELECTION FOR TURNAROUND WELLS AN EVALUATION OF THE IMPACT UPON DOWNHOLE MATERIALS WHEN MIXING PRODUCED WATER AND SEAWATER

Lucrezia Scoppio 1), Perry Ian Nice 2)

1) Pipe Team srl, Via Resistenza 2, 20070 Vizzolo P. (Mi), Italy

2) StatoilHydro ASA, N 4035 Stavanger, Norway

ABSTRACT

Turnaround (TAW) "switch-over", or conversion wells are utilized for combining oil and gas production and injection of water for either pressure maintenance or disposal. Therefore a well is designed such that it can begin as an oil and gas producer then later be converted to a water injector or vice versa. These wells could be “switched” several times, without any major well intervention, e.g. removal of tubing. Material selection for TAWs sometimes have proven problematic with rapid failures when the incorrect metallurgy was installed, resulting in severe corrosion damage. A study aimed to assess possible production/injection well combination scenarios was performed. Different water injection systems were considered:

A. Deaerated water (variable dissolved oxygen content) B. Raw sea water (with and without chlorination) C. Produced water

Moreover possible commingling of the above three systems were considered, namely: A and C or B and C. The material selection for injection wells is driven by several interdependent factors: temperature, pH, oxygen and residual chlorine concentrations. The challenge is then to combine these injection scenarios with the problems associated with selecting well materials suitable for production. This has to include both “sweet” and “sour” oil and gas production service. This study has resulted in a proposed guideline for the selection of materials for TAWs. Key words: Turnaround wells (TAWs), deaerated water, raw sea water, produced water, pitting corrosion, microbial corrosion (MIC), sweet production, sour oil and gas production, H2S.

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Paper No.

08089

INTRODUCTION

A “Turnaround Well”, TAW, is a term used for a well which can be utilized for both oil & gas production and injection of water for either pressure maintenance or disposal. Therefore in this situation a well will be designed to begin as an oil & gas producer then later converted to water injector or vice versa. This would be planned without major well intervention, that is, removal of tubing or liner section.

There are cases where the wells are switched several times from injection to production and vice-versa, as for example onshore fields in Oman [1] are passed so many times from production to injection, the utilization was stopped only when leakages occurred.

Material selection for TAWs has proven problematic earlier with rapid failures when the wrong metallurgy is used resulting in corrosion failures [1,2,3]. This has led to costly work-overs. Field histories of corrosion with completion equipment reveal that corrosion is strongly influenced by dissolved oxygen. In ’85 the 9Cr-1 Mo equipment of a well near Hobbs in New Mexico was retrieved for unscheduled maintenance after only 3 weeks of services [2]. The 9Cr-1 Mo tubing seal divider showed severe crevice corrosion attack. Injection service water contained more than 50 ppb of oxygen. Corrosion can initiate even when oxygen levels only periodically exceed the concentration of 50 ppb.

In order to tackle these issues the material selection for TAW’s has to combine the assessment of the fluid corrosivity of both injection and production services. A study to assess corrosivity for a number of possible injection scenarios and to evaluate the optimal metallurgical alternatives for the completion was performed. This has lead to an overall recommendation for each scenario.

OIL AND GAS PRODUCTION SYSTEMS

Analysis of the design operating parameters represents the first step in the process in

selecting the optimal materials for a well. The selection of the tubing, casing and downhole equipment materials for a given type of well and operating conditions is performed following the assessment of the fluid corrosivity. Evaluation of the fluid corrosivity consists of the identification of the expected corrosion form(s) and then calculation of the relevant penetration rate and therefore the likelihood of the corrosion occurrence. In addition another important step is the evaluation of the well fluid to determine if it is considered sour or not. This would be in accordance with the guidelines detailed within NACE MR-0175/ISO 15156 [4]. Moreover, the properties of well fluids may change during the lifetime of the well. Events such as reservoir souring can produce more severe service conditions and therefore this must be considered during the material selection process. Assessment of the selected material is dependent apart from upon pressure, temperature and composition of the well fluids upon some critical parameters. These have a strong impact upon the resistance of a material to the different forms of corrosion [5]. These are:

• O2, CO2 and H2S concentration, • Water chemistry: e.g. Cl- concentration, • pH, • Service (e.g. changes from oil/water to water or production to injection), • Addition of “new” chemicals: e.g. corrosion inhibitor, biocides etc…, • Presence of elemental sulphur (S0), Mercury (Hg) or other corrosive elements,

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• Watercut, • Water breakthrough: e.g. water production in gas wells, seawater breakthrough in fields

employing seawater injection.

WATER INJECTION SYSTEMS

A water injection system combines a process facility with a distribution system to produce and deliver water to the injection wellbore. There are three reasons to maintain effective corrosion control [8]:

• To obtain an acceptable service life of the equipment; • To minimise generation of suspended solids; • To prevent loss of water to the environment, generating pollution.

Corrosion products are the primarily source of suspended solids generated within bare steel injection systems. Corrosion of carbon steel by injection water generally is attributed to the presence of one or more of the following gasses: H2S, CO2, oxygen (see Table 1).

Generally H2S dissolved in an electrolyte (wet H2S) can induce cracking. Large quantities of H2S can be released from precipitated sulphides leading to locally high partial pressure of H2S. In combination with a low pH the risk of H2S cracking could be high. CO2 is naturally present; prediction of CO2 corrosion rate is possible with several models, e.g. the NORSOK M-506 model 1 [7].

Suspended solid deposition in injection systems accelerates corrosion rates due to under

deposit corrosion, provides a hiding place for bacteria and shields pipe surfaces from effective treatments by corrosion inhibitors and biocides. Water quality often becomes the controlling variable in the selection of a corrosion control strategy, when the purpose is to deliver high quality water to the injection well bore. Filtered, deaerated seawater typically contains less than 0.5 mg/L suspended solids when it leaves the treatment plants [8]. The following types of corrosion, occurring on carbon and low alloy steels, are evaluated in water wells:

• oxygen corrosion (O2 corrosion) • Microbiologically Influenced Corrosion (MIC). In flowing conditions corrosion rate increases by a factor approximately equal to the flow

rate (U) expressed in m/s. Above ambient temperature a further increase of corrosion rate shall be taken into account. The following empirical equation can be used to predict oxygen corrosion rate “RO2” of carbon steels [9]:

RO2 = U2c020.0v)

3030T(

2OCORR ⋅⋅⋅=−

[1] where:

– vCORR= corrosion rate, mm/y; – cO2 = oxygen equivalent, ppm2; – U = flow rate, m/s. It is assumed to be U=1 if U<1; – T = temperature, °C. If T<30°C, T is assumed to be T=30°C.

1 Norsok M506-1 prediction of CO2 corrosion rate model. 2 The corrosion rates obtained with this formula is considered reliable for oxygen concentration above 3 ppm: below 3 ppm the formula underestimates the actual oxygen corrosion rate.

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The oil industry has often reported the presence of Sulphate Reducing Bacteria (SRBs) on major oilfield failures; these type of failures generally involve localised corrosion in deaerated conditions [10,11]. Bacteria corrosion damage is always associated with local attack, involving pits, craters with galvanic coupling between a stable local anode and the cathode which surrounds it.

The conditions for MIC initiation are well known: • presence of SRB; • presence of sulphates; • anaerobic conditions (or under deposit or interstice aerated conditions).

GUIDELINES FOR MATERIAL SELECTION FOR TAW Oil & Gas Production Scenario

Materials selection for tubing and downhole equipment for production well systems is commonly based on guidelines generated by the Oil&Gas companies. Basically all the water-wetted parts (e.g. for Down Hole Safety Valves (DHSVs), the flow tube, piston, etc) can encounter corrosion problems. The selection of downhole equipment materials is strongly dependent on the tubing material selection in order to have at a minimum the same equivalent metallurgy. The following downhole equipment is generally considered:

• Tubing hanger; • Permanent downhole equipment (packers, landing nipples, polished bore receptacles

(PBRs), communication devices, Surface Controlled Subsurface Safety Valves (SCSSV)...);

• Sand screen. If sour conditions are anticipated then it is important to ensure that the materials specified

conform to NACE MR-0175/ISO15156 in combination with the Oil&Gas Company internal best practices. NACE MR-0175/ISO15156[4] imposes hardness limits and/or specific material conditions/heat treatments for some materials. In addition, a number of materials (even where they conform to NACE MR-0175/ISO 15156) are only suitable for a limited range of H2S partial pressures, with the limit being dependant upon the in-situ pH, chloride content etc. More specific guidance on alloy limits are generally available within Oil&Gas Companies best practices. Material selection for Production Well Service can be schematised in the logic-diagram illustrated in Figure 1 [5]; the well type must be known in advance of using the flow chart. Water Injection Scenario

The corrosion resistance of tubing and down hole equipment materials for injection water is regulated by several parameters:

• Water Quality: ─ dissolved oxygen concentration, ─ pH, ─ sulphides, ─ solids, ─ chlorination, ─ bacterial activity.

• Injection water temperature. • Well lifetime.

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An example of material selection for injection well service extracted from an internal

guideline is illustrated in Figure 2 [5]. Internal guidelines for water injection materials selection are mostly based on the oxygen concentration. In reality the injection conditions can be more complex:

A. Deaerated water (variable O2 content) • Water chlorinated or not

B. Raw sea water • Water chlorinated or not

C. Produced water • Increased ppH2S • Bacterial corrosion

Moreover it is possible the commingling of the above three conditions: • Commingling of above A & C • Commingling of above B & C

Hereafter all the different scenarios that can be encountered are summarized, taking into

consideration all the possible factors (e.g. temperature, residual chlorine, ppH2S, elemental sulfur, etc…). As an initial screening for seawater application a Pitting Resistance Equivalent Number (PREN) greater than 40 is required for aerobic and aerobic/chlorinated seawater services [12]. The materials suggested below are selected based upon the combination of results from field experience and laboratory tests extracted either from literature or directly from the company. Material Selection Options for Injection Water Systems Injection Water - Deaerated Seawater: Low alloy steel (1%Cr alloyed) tubing and liners are generally utilized for this application. Field failures have been observed when the injection water is not fully deaerated. In the Gullfaks Field (North Sea) a seawater injection the 13%Cr martensitic stainless steel well tubing string, experienced severe pitting, crevice corrosion and galvanic corrosion in the tubing connection. This was due mainly to poor deaeration of the injected seawater, as illustrated in Figure 3 and 4.

In Figure 5, is shown another example of poor deaeration at a seawater injection well on the Statfjord Field. The 9Cr 1 Mo steel safety valve suffered by severe pitting and crevice corrosion.

Replacement materials for equipment in this application that have provided the required corrosion resistance are super duplex stainless steel (UNS S31260 and UNS S32760) and Nickel Alloys UNS N7718. Injection Water – Co-mingled Deaerated Seawater/Produced Water: The impact on downhole material corrosion when mixing produced water and seawater shall be always considered, regardless of the mixing ratio raw water/produced water (RAW/PW). Both MIC and corrosion due to elemental sulphur can occur when commingling waters containing both dissolved oxygen (seawater) and H2S (produced water). Organics from the produced water are nutrient for SRBs, thus the probability of MIC occurrence increases. The material selection must be adequate, CRAs with higher PRENs than 13Cr stainless steels must be selected. Three different scenarios have been considered:

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√ water characteristic: O2< 20 ppb, water temperature < 40°C, pH >7; √ water characteristic: O2 > 20 ppb, 100°C> water temperature > 40°C, pH < 7; √ water characteristic: O2 > 20 ppb, water temperature > 100°C, 5 <pH < 7.

Injection Water – Produced Water: Both temperature and oxygen are crucial in respect to corrosion resistance of materials when produced water is injected in the field. SRBs activity has to be assessed in order to monitor the occurence of MIC. In Figure 6 is shown the corrosion attack observed to a L80 steel coupon exposed in Heidrun Field to the injected produced water. Coupons were covered by a biofilm both organic and inorganic substances. The SEM-analysis revealed the presence of FeS and MIC occurance was ascertained. When Produced Water is injected three different scenarios have been considered:

√ water characteristic: O2< 20 ppb, water temp < 40°C, pH >7; √ O2< 20 ppb, 100°C > water temperature > 40°C, pH <7; √ O2 > 20 ppb, 100°C > water temperature > 40°C, pH < 7.

Injection Water – Co-mingled Raw Seawater/Produced Water: When co-mingled raw seawater/produced water injections are encountered also chlorine additions should be taken into account. Active corrosion in co-mingled raw seawater/produced water injection systems can be initiated under abnormal service conditions due too dissolved oxygen concentration, or too high chlorine level or combination of both. Four different scenarios have been considered:

√ water temperature < 40°C, pH >6, no chlorine (either not added or consumed); √ 40°C< water temperature <100°C, 5 <pH <7, no chlorine (either not added or consumed); √ water temperature < 20°C, pH >7, chlorine addition; √ 100°C> water temperature > 20°C, any pH, chlorine.

Injection Water – Raw Seawater: Based on the raw seawater injection characteristics different four different scenerios have been considered. The first three cases are seemingly identical to the co-mingled raw seawater/produced water injection systems, except MIC is expected to be more promenant in the latter:

√ water temperature < 40°C, pH >7, no residual chlorine (either not added or consumed); √ 40°C< water temperature <80°C, 5< pH <7, no residual chlorine (either added or

consumed); √ water temperature < 20°C, residual chlorine; √ water temperature > 20°C, residual chlorine.

The injection water combinations that include produced water and/or raw seawater, then, non-metallic materials can be selected, e.g. glass reinforced epoxy (GRE) lined carbon steel for the tubing. Constraints are posed include, temperature, rapid de-pressurisation (for gas systems) and the susceptibility to mechanical damage (thro wireline or tools) to the GRE liner.

As an example, hereafter is presented a field case, where the material selection for a WAG well ( Water Alternate Gas) demonstates to be inappropriate. Whereby the installed tubing and equipment was 13Cr martensitic stainless steel. The well on the Norne Field was in service for approx. 5 years. During this time the well was used as follows:

• Gas injection (dry export gas): 32 months/ 2,6 years at approx 55°C • Water injection (aerated seawater): 19 months/ 1,6 years at approx 9°C • Shut down/no injection: 10 months/ 0,8 years

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Inspection of the retrieved tubing revealed severe corrosion damage on the 13Cr stainless steel tubing, as showed in Figure 7. The13Cr martensitic steel (low PREN) is not suitable for oxygen containing environments. It was therefore concluded that oxygen contamination in the injected seawater was the corrosion failure cause. This means that the effective time for the corrosion failure was extremely rapid: approx. 19 months/ 1.6 years. Material Selection Options for TAW covering Production Well Service With Reservoir Fluid Containing CO2 with Minor Concentrations of H2S (Sweet)

If a deaerated seawater injection well is converted to a “Sweet Production Well”, the material selection needs to consider mainly the produced fluid corrosivity. If the fluid is evaluated to be corrosive due to CO2 the optimal choice is 25 Cr superduplex stainless steel to counter both oxygen and CO2 corrosion, but GRE lined carbon steel tubing is an alternative if the level well intervention activities are considered acceptable w.r.t. the integrity of the GRE liner.

For both deaerated seawater and commingled deaerated seawater/produced water then the material selection proposed, is as shown in Tables 2 and 3. Produced water injected with “Sweet Production Well Service” maintain the same material selection as the produced water injection systems at temperature greater than 40°C, depending on dissolved oxygen contamination: if the O2 <20ppb materials given in Table 4 are suggested whilst materials given in Table 5 are suggested if the O2 >20ppb.

Raw seawater injector is to be converted to a “Sweet Production Well Service” the same material selection options illustrated in the case of raw seawater commingled with produced water for “Sweet Production Well Service” the materials showed in Table 6 are suggested.

If residual chlorine is present in the raw seawater injection system, then titanium alloys are suggested for liner and equipment with dynamic seal surfaces (see Tables 7 and 8). Material Selection Options for TAW: Reservoir Fluid Containing CO2 with Major Concentrations of H2S (Sour)

If a deaerated seawater injection well is converted to a “Sour Production Well Service”, the material selection is driven by the produced fluid corrosivity. If the fluid is corrosive and contains H2S the optimal choice is 25% Cr superduplex stainless steel for all the equipment except the tubing where also sour service grade alloyed steel with GRE internal lining to counter both oxygen and sulphide stress corrosion cracking.

The choice of 25% Cr superduplex stainless steel is valid if the partial pressure of H2S is lower than 20 mbar. When ppH2S exceeds 20 mbar (3 psi) then the tubing material selection should be in accordance with the ISO15156-3/NACE MR0175 with a PREN > 40.

In the case of commingling raw water with sour produced water the amount of elemental sulphur that can be produced will be limited by the concentration of dissolved oxygen or H2S in the commingled water, which ever of the two components is stoichiometrically limiting in the mixture will determine the concentration of sulphur in the water [13]. However it is unlikely that it will be more corrosive than any residual H2S. Of great concern is the possibility that the by-products of H2S oxidation such as the polythionic acid anions, S2O3

2-, is formed. Polythionic acid ions affect greatly pitting corrosion resistance of CRAs. Produced water injected in “Sour Production Well Services” the suggested material selection is in accordance with produced fluid conditions [5,6]. In Table 9 is summarized the materials selection for sour producers, in deaerated water injection systems.

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For raw seawater and commingled raw seawater/ produced water the material selection suggested for “Sour Production Well Services” is the same as for sweet producers if the ppH2S is lower than 20 mbar (see Table 10).

The raw seawater converted to a “Sour Production Well Service” when residual chlorine is present, for any pH condition, maintains the same suggested material selection options given for the “Sweet Production Well Service” (see Table 8).

DISCUSSION The material selection options suggested for TAW with reservoir fluids containing CO2 (Sweet) and/or with major concentrations of H2S (Sour) are summarized in Tables 11 and 12. The referred temperatures are those of the injected water and not the sweet or sour produced fluids temperatures.

These suggested options are based upon the combination of results obtained from field experience and laboratory tests, extracted either from literature or directly from Statoil ASA. This led to the development of the material selection charts illustrated in Figures 1 and 2.

In the case of sour producer wells then the suggested material selected have utilized the advice given in ISO15156/NACE MR0175 combined with specific Alloy “domain diagrams” developed from the internal companies guidelines [5, 6].

CONCLUSIONS & SUMMARY

Material selection for TAWs has proven problematic in the past with rapid failures when the

wrong metallurgy was used resulting in dramatic corrosion attacks. A study to evaluate the optimal metallurgical alternatives for a number of possible injection scenarios and for the completion of such wells was performed. Factors affecting corrosion initiation in these environments were discussed. and the conclusions can be summarized as follows:

• Temperature, flow velocity, dissolved oxygen and residual chlorine concentrations are critical parameters; nevertheless the interaction between oxygen and chlorine is not fully understood.

• Internal company guidelines for tubing and downhole equipment materials selection for production well systems work well, but concerning the water injection scenario, the existing guideline need to be improved taking into consideration other factors apart from oxygen and chlorine. The materials selection is driven by several interdependent factors.

o Water Quality: ─ dissolved oxygen concentration, ─ pH, ─ sulphides, ─ solids, ─ chlorination, ─ bacterial activity

o Injection water temperature o Well lifetime

• New guidelines for material selection for the different water injection systems are provided in this document. The material selection has been reconsidered for the cases where a deaerated seawater injection well is converted to a Sweet or Sour producer, in light of the produced fluid corrosivity.

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• The impact on downhole materials on reservoir souring when mixing produced water and seawater is discussed.

AKNOWLEDGMENTS

The authors would like to thank StatoilHydro ASA and Pipe Team srl for their permission to publish this paper.

REFERENCES [1] P.I. Nice, Ø. Strandmyr “Materials And Corrosion Control Experience Within The Statfjord

Field Seawater Injection System”, CORROSION/93, Paper No. 64, (Houston, TX: NACE 1993).

[2] G. Chitwood, “Experience With Corrosion of Downhole Completion Equipment In Water Injection”, CORROSION/93, Paper No. 57, (Houston, TX: NACE 1993).

[3] T.N. Evans, P.I. Nice, M.J. Schofield, K. C. Waterton “ Corrosion Behaviour Of Carbon Steel, Low Alloy Steel and CRA’s In Partially Deareated Seawater and Commingled Produced Water”, CORROSION/04, Paper No 04139, (Houston, TX: NACE 2004).

[4] NACE MR 0175/ISO 15156, part 1, 2 and 3 “Petroleum and Natural Gas Industries – Materials For Use In H2S Containing Environments In Oil And Gas Production”, International Organization For Standardization, 2001.

[5] “Best Practice for the Selection of Materials for Tubing and Casing” - Statoil doc No. GL0126

[6] “Best Practice for the Selection of Materials for Downhole Equipment”, Statoil doc GL0125, .

[7] “CO2 CORROSION RATE CALCULATION MODEL”, Norsok model M506 rev 1, June 1998.

[8] C.C. Patton, "Corrosion Control in Water Injection System", Mat. Perf., August 1993, p. 46. [9] WELLMATE© 2006 3– Statoil ASA Internal module. [10] J.L. Crolet, M.F. Magot, “Observations of Non SRB Sulfidogenic Bacteria From Oilfield

Production Facilities”, CORROSION/95, Paper No. 188, (Houston, TX: NACE1995). [11] X. Campaignolle et al., “Stabilization of Localised Corrosion Of Carbon Steel By

Sulfate-Reducing Bacteria”, CORROSION/93, Paper No. 302, (Houston, TX: NACE 1993). [12] R.D. Eden et al, “THE RAW WATER PROGRAMME- LITERATURE SURVEY” Capcis

report, February 1994. [13] J.F.D. Stott, “Effect Of Commingling Aerated Seawater With Sour Produced Water”

Capcis Internal Report FTRJQK, April 1998.

Table 1 – Gasses which induce low alloyed steel corrosion [8].

Dissolved gas

Sources Corrosion product

H2S Naturally occurring and/or generated by SRB Iron sulphide (FeS) CO2 Naturally present Iron Carbonate (FeCO3) Oxygen Unintentionally entered from the atmosphere Ferric hydroxide (Fe(OH)3)

3 Wellmate© 2006 is the trade name of a corrosion prediction internal module.

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Table 2 – Material selection for deaerated Seawater and commingled deaerated Seawater/ Produced Water TAW Sweet Systems. O2< 20 ppb, T < 40°C, pH >7.

Equipment Type Selected Material Tubing 1%Cr alloyed steel Liner 25Cr SDSS Equipment with dynamic seal surfaces (*) (DHSV, etc;)

25Cr SDSS

Packer AISI 41XX series Special Equipment (Sand Screen etc)

Base pipe : 25Cr SDSS Wire wrap: UNS N06625

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

Table 3 – Material selection for deaerated seawater and commingled deaerated seawater/ produced

water TAW Sweet Systems.O2< 20 ppb, 100>T > 40°C, pH > 7.

Equipment Type Selected Material Tubing 1%Cr alloyed steel with GRE Internal Lining or

25Cr SDSS Liner 25Cr SDSS Equipment with dynamic seal surfaces (DHSV, etc;)

25Cr SDSS

Packer AISI 41XX series Special Equipment (Sand Screen etc)

Base pipe : 25Cr SDSS Wire wrap: UNS N06625

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

Table 4 – Material selection for for produced water TAW Sweet Systems: O2 < 20 ppb, 100°C >T>40°C, pH<7.

Equipment Type Selected Material Tubing 13Cr Liner 13Cr Equipment with dynamic seal surfaces (*) (DHSV, etc;)

13Cr

Packer 13Cr Special Equipment (Sand Screen etc)

Base pipe : 13Cr Wire wrap: UNS N08825

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

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Table 5 – Material selection for produced water and commingled deaerated Seawater/ produced

water TAW Sweet Systems: O2 > 20 ppb, 100°C >T>40°C, pH<7.

Equipment Type Selected Material Tubing carbon steel steel with GRE Internal Lining Liner 25Cr SDSS Equipment with dynamic seal surfaces:DHSV, etc;

25Cr SDSS

Packer 25Cr SDSS Special Equipment (Sand Screen etc)

Base pipe : 25Cr SDSS Wire wrap: UNS N06625

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

Table 6 – Material selection for raw sea water or co-mingled raw Seawater /Produced Water TAW

Sweet Systems: T<100°C, 5<pH<6, no residual chlorine.

Equipment Type Selected Material Tubing carbon steel steel with GRE Internal Lining Liner 25Cr SDSS Equipment with dynamic seal surfaces (DHSV, etc;)

25Cr SDSS

Packer Titanium alloys Special Equipment (Sand Screen etc)

Base pipe : Titanium alloys Wire wrap: UNS N08825

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

Table 7 – Material selection for co-mingled raw seawater /produced water TAW Sweet Systems: T>20°C,any pH, chlorine additions.

Equipment Type Selected Material Tubing 25Cr SDSS Liner Titanium alloys Equipment with dynamic seal surfaces (DHSV, etc;)

Titanium alloys

Packer Titanium alloys Special Equipment (Sand Screen etc)

Base pipe : Titanium alloys Wire wrap: UNS N06686

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

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Table 8 – Material selection for co-mingled raw seawater /produced water TAW Sweet Systems:

T>20°C,any pH, chlorine additions.

Equipment Type Selected Material Tubing GRE Lined carbon steel Liner Titanium alloys Equipment with dynamic seal surfaces (DHSV, etc;)

Titanium alloys

Packer Titanium alloys Special Equipment (Sand Screen etc)

Base pipe : Titanium alloys Wire wrap: UNS N06686

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

Table 9 – Material selection for deaerated seawater and commingled deaerated seawater/produced water TAW Sour Systems: O2< 20 ppb, pH <7, T <100°C.

Equipment Type Selected Material

Tubing (*) Liner (*) Equipment with dynamic seal surfaces (DHSV, etc;)

(*)

Packer (*) Special Equipment (Sand Screen etc)

Base pipe : (*) Wire wrap: UNS N08825

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

(*) depending on Cl-, ppH2S and pH.

Table 10 – Material selection for raw seawater and commingled raw seawater/produced water TAW Sour Systems: O2> 20 ppb, pH <7, 100°C >T > 40°C.

Equipment Type Selected Material

Tubing 1%Cr steel with GRE Internal Lining or 25Cr SDSS (*)

Liner 25Cr SDSS (*) Equipment with dynamic seal surfaces (DHSV, etc;)

25Cr SDSS (*)

Packer 25Cr SDSS (*) Special Equipment (Sand Screen etc)

Base pipe: 25Cr SDSS Wire wrap: UNS N06625

Well Head/ Xmas tree/Tubing Hanger

Low alloy steel with UNS N06625 weld overlay

(*) if pH2S is less than 20 mbar.

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Table 11 – Sweet producer material selection for producer water, co-mingled raw seawater /produced water TAW Sweet Systems. (Temperature is water temperature and no the production one). All results relate to uncoupled specimens.

Conditions

Material

- Deaerated (*) - Produded water

- Poorly deaerated

- Co-mingled Deaerated/PW

- Produced water

- Produced water

- Raw water - Co-mingled Raw water/PW

- Raw Water - Co-mingled Raw water /PW

- Raw water

T< 40°C pH >7

100>T> 40°C pH >7

100>T> 40°C pH < 7

100 >T> 40°C pH < 7

100 >T> 40°C pH < 7

T<100°C

T> 20°C

T< 20°C Oxygen < 20 ppb Oxygen > 20 ppb Oxygen <20

ppb Oxygen > 20

ppb No Chlorine Chlorine Chlorine

Carbon steel GC 1%Cr LAS GRE Lined CS OD 3% Cr 13%Cr L80 S13Cr OD 25Cr SDSS OD OD (♣)

Tubi

ng

Titanium alloys OD OD OD OD OD OD OD OD 1%Cr LAS GRE Lined CSteel

(♦) (♦) (♦) (♦)

13%Cr L80 S13Cr OD 25Cr SDSS OD

Line

r

Titanium alloys OD OD OD OD OD OD OD 13%Cr S13Cr 17 4PH OD 25Cr SDSS OD E

quip

. with

dy

nam

ic s

eal

Titanium alloys OD OD OD OD OD OD ODLegend: CS =carbon steel, SS= sand screen, GC= general corrosion, OD= overdesign.

− Red fill indicates not applicable material due to localised corrosion pitting (P) or crevice (C) and a corrosion rate higher than1 mm/year. − Green fill indicates no pitting and crevice, corrosion rate on bore surfaces lower than 0.1 mm/year − Orange fill indicates borderline behaviour.

(*) can have oxygen spikes due to upset; (♣) if T is < 35°C, 25CrSDSS can be used for co-mingled only ; (♦) mechanical damages may occur .

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Table 12 –Material selection for TAW Sour Systems.

Conditions

Material

- Deaerated or - Deaerated/ PW - Produced water

- Raw water - Raw water/PW - Produced water

- Raw water - Raw water/PW

T<100 °C 100°C >T>40°C, pH>5 T> 20°C, pH > 5

Oxygen < 20 ppb No Chlorine

Oxygen > 20 ppb No Chlorine

Chlorine

1%Cr LAS (*) GRE Lined CS 3% Cr 13%Cr L80 S13Cr 25Cr SDSS OD (§)

Tubi

ng

Titanium alloys OD OD OD 1%Cr LAS (*) 13%Cr L80 S13Cr 25Cr SDSS (§)

Line

r

Titanium alloys OD OD 13%Cr (*) S13Cr (*) UNS S17400 (*) 25Cr SDSS (§)

Equi

p. w

ith d

ynam

ic

seal

(DH

SV)

Titanium alloys OD 13Cr S13Cr AISI 41XX (*) 25Cr SDSS (§) Pa

cker

Titanium alloys OD

(*)depending on temperature, Cl-, ppH2S and pH. (§) if ppH2S< 20 mbar Legend: PW= produced water CS =carbon steel, SS= sand screen, GC= general corrosion, OD= Over design − Red fill indicates not applicable material due to localised corrosion pitting (P) or crevice (C) and a corrosion rate

higher than 1 mm/year.

− Green fill indicates no pitting and crevice and corrosion rate on bore surfaces lower than 0.1 mm/year

− Orange fill indicates borderline behaviour.

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Note 1:CO2 corrosion rate for standard carbon and low alloy steel as predicted by using [7].

Figure 1 - Material Selection for Production Wells [5].

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Figure 2 - Material Selection for Injection Well Service [5].

Aerated

No

FRP/GRE LinedLAS

Deaerated

T>20°C

No

Yes

D.SS S25Cr

Containing S or Poor Bacteria

Control

Yes

No

1%Cr LAS

T>40°C

T > 60°C

No

pH > 7

Yes

Well Deaerat.Well Controlled

Yes

No

Yes

Titanium

Chlorinated

Yes

No

No

No

Yes

FRP/GRE Lined LAS

and/orD.SS S25Cr

No

Chlorinated Yes

No

Yes

T>100°C

Titanium

No

Yes

Yes

High Well Intervention

Activity ?

T>100°CYes

High Well Intervention

Activity ?

No

Yes

Yes

Water

Injection Service

Gas

”Wet”Yes

SeeReservoir

Fluid

No

See H2S Limit

No

Yes

LAS SS

LAS

Combined Water/Gas(WAG, SWAG)

SeeWater

and Gas

FRP/GRE Lined LAS

T>20°C

High Well Intervention

Activity ?

No

No

YesYes

T>100°C

Yes

D.SS S25Cr

No

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Figure 3– Crevice corrosion attack of a Gullfaks Field seawater injection tubing: 13%Cr box end joint.

Figure 4 - Crevice and galvanic corrosion attacks of a 13%Cr tubing and connection in a seawater

injection well at Gullfaks Field.

Figure 5 – Severe pitting and crevice corrosion attack of a 9Cr 1Mo Safety valve Statfjord Field

seawater injection well.

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Figure 6- Corrosion of a L-80 corrosion coupon exposed to Production Water injection.

Figure 7 – Corrosion damage to 13%Cr tubing due to dissolved oxygen in the injected raw seawater in WAG well service Norne Field.

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