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 . Nice

Paper No.

08089

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.

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.

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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 = v CORR = 0.020 ⋅ c O 2 ⋅ 2

where: – – – –

(

T − 30 ) 30

⋅U

[1]

vCORR= corrosion rate, mm/y; cO2 = oxygen equivalent, ppm2; U = flow rate, m/s. It is assumed to be U=1 if U 20 ppb, 100°C> water temperature > 40°C, pH < 7; √ water characteristic: O2 > 20 ppb, water temperature > 100°C, 5 7; √ O2< 20 ppb, 100°C > water temperature > 40°C, pH 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 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 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, S2O32-, 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 H2S CO2 Oxygen

3

Sources

Corrosion product

Naturally occurring and/or generated by SRB Iron sulphide (FeS) Naturally present Iron Carbonate (FeCO3) Unintentionally entered from the atmosphere Ferric hydroxide (Fe(OH)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 Liner Equipment with dynamic seal surfaces (*) (DHSV, etc;) Packer Special Equipment (Sand Screen etc) Well Head/ Xmas tree/Tubing Hanger

1%Cr alloyed steel 25Cr SDSS 25Cr SDSS AISI 41XX series Base pipe : 25Cr SDSS Wire wrap: UNS N06625 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 25Cr SDSS 25Cr SDSS

Liner Equipment with dynamic seal surfaces (DHSV, etc;) Packer Special Equipment (Sand Screen etc) Well Head/ Xmas tree/Tubing Hanger

AISI 41XX series Base pipe : 25Cr SDSS Wire wrap: UNS N06625 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 20 ppb, 100°C >T>40°C, pH 40°C pH >7 pH >7 Oxygen < 20 ppb

- Poorly deaerated - Co-mingled Deaerated/PW

- Produced water

- Produced water

100>T> 40°C pH < 7 Oxygen > 20 ppb

100 >T> 40°C pH < 7 Oxygen T> 40°C pH < 7 Oxygen > 20 ppb

- Raw water - Co-mingled Raw water/PW

- Raw Water - Co-mingled Raw water /PW

- Raw water

T 20°C

T< 20°C

No Chlorine

Chlorine

Chlorine

OD

(♣) OD

OD

GC

Carbon steel

Tubing

1%Cr LAS GRE Lined CS

OD

3% Cr 13%Cr L80

OD

OD

OD OD OD

(♦)

(♦)

(♦)

OD

OD OD OD

OD

OD

OD

OD OD OD

OD

OD

S13Cr 25Cr SDSS 1%Cr LAS GRE Lined CSteel 13%Cr L80 S13Cr 25Cr SDSS Titanium alloys

Equip. with dynamic seal

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Liner

Titanium alloys

OD OD

OD

OD

OD

(♦)

OD

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

OD

OD

OD

Legend: 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 .

Table 12 –Material selection for TAW Sour Systems. Conditions Material

- Deaerated or

- Raw water

- Raw water

- Deaerated/ PW

- Raw water/PW

- Raw water/PW

- Produced water

- Produced water

TT>40°C, pH>5

T> 20°C, pH > 5

Oxygen < 20 ppb

Oxygen > 20 ppb

Chlorine

No Chlorine

No Chlorine

(*)

1%Cr LAS GRE Lined CS Tubing

3% Cr 13%Cr L80 S13Cr 25Cr SDSS

OD

(§)

Titanium alloys

OD

OD

1%Cr LAS

(*)

Liner

13%Cr L80 S13Cr

(§)

seal (DHSV)

25Cr SDSS Equip. with dynamic

OD

Titanium alloys

OD

13%Cr

(*)

S13Cr

(*)

UNS S17400

(*)

OD

25Cr SDSS

(§)

Titanium alloys

OD

Packer

13Cr S13Cr

(*)

AISI 41XX

(§)

25Cr SDSS 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].

Injection Service

Combined Water/Gas (WAG, SWAG)

Water

Gas

See Water and Gas Aerated

Yes

”Wet”

No

Deaerated No

See Reservoir Fluid

Yes Well Deaerat. Well Controlled

Yes

See H2S Limit

Yes Yes No

Chlorinated

Yes

T>20°C

Yes

T>100°C

pH > 7

LAS SS

No

Yes LAS

No

No

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Chlorinated No T > 60°C

High Well Intervention Activity ?

Yes

Yes

Yes

Yes

T>20°C

T>100°C

No

No

Yes Yes T>40°C High Well Intervention Activity ?

No

No

No

T>100°C

High Well Intervention Activity ?

Yes

No Containing S or Poor Bacteria Control

Yes No

FRP/GRE Lined LAS

Yes

D.SS S25Cr

No Yes

No

Yes

No

Titanium

1%Cr LAS

FRP/GRE Lined LAS

FRP/GRE Lined LAS and/or D.SS S25Cr

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

D.SS S25Cr

Titanium

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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