In recent years, there has been a substantial increase in oil and gas exploration and production in deep water regions. These expanded operations have involved many new challenges that have necessitated engineering changes, design adaptations and selection of alternative materials and systems. A major area that has been affected by the current boom in deep water operations is corrosion and materials technology. This paper presents a discussion of the changes in corrosion and materials technology required for deep water operations. These include the use of: (1) alternative alloys to resist corrosion in production environments, (2) higher strength materials for structures, tubulars and flowlines, (3) weight saving materials and composites, (4) flexible materials for flowlines and risers and (5) cathodic protection system design. This paper also highlights specific developments in each of the abovementioned areas.

There has been major growth in offshore development of oil and gas reservoirs which, in recent years, has moved into progressively deeper waters (See Figure 1).¹ In many cases, drilling and production operations in deeper waters have resulted in new engineering challenges particularly from the standpoint of requirements for mitigating corrosion. As water depths have increased, so have costs associated with conventional means of corrosion protection. Examples are the use of corrosion inhibitors and conventional cathodic protection designs. The cost to implement corrosion inhibition in deep offshore areas in many cases has become economically prohibitive. This has resulted in the use of alternative materials with inherent resistance to corrosion in production environments containing H₂S and high levels of CO₂. Cathodic protection of structure in deep water has also required changes in design practices aimed mainly toward making the cathodic protection system more efficient and cost effective.

In addition to changes directly driven by cost factors, changes in corrosion mitigation strategies for deep water developments have also been based on reliability. Deep water wellhead system, pipelines and structures are expensive and typically require long term successful operations to achieve payout. Therefore, once corrosion protection methods have been implemented, they must provide long term reliability for up to 30 years or in some cases longer. Finally, repair costs have also increased dramatically with water depth to the point that sometimes a single failure can result in direct and associated costs in the range of $10 to 100 million.

In response to the changing offshore technical and economic environment, changes in materials selection and corrosion mitigation strategies have been developing. This paper identifies several areas where advances have been made and are continuing. It presents results of a survey of major oil companies which have led the charge into deep water oil and gas development. This paper focuses on the following topics identified to be essential for successful deep water development and operations:

1. High Strength Materials
2. Corrosion Resistant Materials
3. Weight Saving Materials
4. Engineered Materials Systems
5. Cathodic Protection

Effective mitigation of corrosion of downhole and surface components and systems exposed to oil production environments has been conventionally achieved with the use of corrosion inhibitors and, in some cases, internal coatings. In deep water operations, however, this conventional technology has serious limitations relative to the following areas:

1. Logistics - Costs of providing a continual supply of corrosion inhibitor to remote satellite platforms and subsea production system is high and increases greatly with water deep.
   
   
2. Weight and space - Effective inhibition in deep wells, often requires continuous injection. These facilities are an added burden to platforms which have serious space and weight limitations.
   
   
3. Monitoring - Corrosion inhibition programs need monitoring which is difficult in remote areas and is manpower intensive. Additionally, inhibitor procurement must also be monitored so that changes in formulation and inhibitor performance can be identified with time.
   
   
4. Long Term Reliability - Inhibitor programs rarely stop corrosion but merely reduce it to a rate that results in an acceptable service life. Usually this is between 5 and 10 years with workovers at planned intervals. With the increasing project life and desires to reduce or eliminate workovers as associated costs, longer term reliability is a major requirement.

As an alternative to the use of conventional technology involving steel and inhibitors, alloys have been developed which have resistance to the corrosive and embrittlement effects of H₂S and CO₂. Concerns have been on well environments that typically contain high partial pressures of CO₂ or CO₂ in combination with low to moderate H₂S partial pressures. In such cases, stainless steels can be cost effective, longer term alternatives to inhibitors. The use of corrosion resistant alloys (CRAs) allows for corrosion to be effectively reduced to less than 0.05 mmpy. However, this requires substantial knowledge of the performance limits of these materials and long term well production characteristics. This includes being able to evaluate changing well conditions over the entire life to identify worse case conditions of water production, flow conditions and workover and well stimulation requirements. Computer models are now available to assess and predict the corrosion rates of steel and the efficacy of inhibitor treatments (PREDICT^®)² and the performance of CRAs (SOCRATES^®)³ through specification of various operational parameters of the production environment.

Alloys of high current interest in offshore applications are indicated in Table 1 and are include:

1. 13Cr martensitic stainless steels - This alloy is cost effective since they can be made with similar manufacturing methods used for conventional carbon and low steels. However, they are mainly utilized for resistance to CO₂ corrosion and have limitations in the amount of H₂S they can handle due to susceptibility to sulfide stress cracking (SSC).



2. Modified 13Cr stainless steels - These materials are based on 13Cr composition but depend on alloying additions of Ni and Mo to increase corrosion resistance at high temperatures and in applications involving higher H₂S partial pressures. More importantly, resistance to SSC is improved over 13Cr.



3. Duplex stainless steels - These materials come in 22 Cr and 25Cr varieties and derive their name from their duplex microstructure containing approximately a 50:50 blend of ferrite and austenite. They have higher Cr and Mo content along with N and sometimes W additions and require different processing methods. Consequently, they are correspondingly more expensive than 13Cr alloys. They have higher strength capabilities due to cold working and greater resistance to corrosion than these other materials. They offer advantages in many offshore applications.



4. Austenitic stainless and nickel-base alloys - These include a broad range of materials including higher alloy stainless steels and nickel base alloys. They are typically utilized in applications where very high H₂S partial pressures are being experienced. They have very high levels of Cr. Ni, Mo and sometimes N, W and/or Nb.



5. Titanium alloys - There are many very corrosion resistant Ti-alloys available which also provide high specific strength (i.e. low density and high strength). Ti-alloys include Grades 2 through 29 and are available in a range of strengths up to about 120 ksi. Current vintage alloys can have additions of Ruthenium (Rh) or Palladium (Pd) to enhance resistance to localized corrosion in seawater applications and in exposure to hostile production environments.

The main limitations in use of these newer or modified alloys is the lack of long term operating experience. However, limited service experience has been supplemented by accelerated laboratory tests conducted under closely simulated service conditions. This has helped to define longer-term corrosion performance and operational limits within which these materials can be utilized.

One of the paramount needs in deep water applications is the requirement for higher strength materials in many areas of application including:

1. Downhole oil country tubular goods (OCTG)
2. Drill pipe
3. Risers
4. Linepipe
5. Constructional steels.

Weight savings in deep water applications is critical. One way to accomplish this is with higher strength materials that increase load carrying capabilities while decreasing wall thickness and section size. This approach has helped to extend drilling and production systems into deeper water.

For offshore platforms and structures, higher strength steels must be used. This requires developments in steel making technology which includes the use of thermo-mechanical controlled processed (TMCP) and microalloyed (MA) steels to achieve grain refinement, uniform through wall hardening and uniform microstructures resulting in higher strengths. Steel tendons for tension leg platforms can now be routinely made with yield strengths in excess of 770 MPa. Hydrogen embrittlement (Figure 2)⁴ and accelerated fatigue crack growth rates (Figure 3)⁵ have been a concern in these materials due to the production of hydrogen by either cathodic protection or resulting from seawater contaminated with H₂S from bacterial growth. Efforts have been made to control excessive cathodic protection (CP) currents through more efficient design of CP systems. Also, the use of metallurgical processing to control the microstructure has helped to enhance fracture toughness and resistance to cracking.

In deep water applications, higher strength (Y.S. - 500-900 MPa) plate steels must be utilized that have good weldability and maintain their strength and toughness following welding with minimum requirements for post weld heat treatment. One problem first experienced in the 1980’s with steels for deep water platforms was obtaining acceptable strength and toughness following welding. Problems associated with excessive weld heat affected zone (HAZ) hardness, brittle course grain HAZ and softened base metal regions adjacent to the HAZ complicated performance. Current vintage TMCP steels have over come many of these problems with limits on MA content and ratios of various MA elements have been taken into account.

For downhole tubulars, C-110 grade sour service grades of steel OCTG are now available from several suppliers which provide higher strength (Y.S. - 760-860 MPa). As shown in Figure 4, these materials retaining resistance to sulfide strength cracking (SSC), a common problem common to high strength steels exposed to H₂S-containing production environments.⁶ These materials typically require optimum metallurgical processing and quality control to produce a fine grained, quenched and tempered microstructure through alloying additions of Cr and Mo and MA additions of V, Ti, Nb and B combined with restricted maximum hardness.

Many corrosion resistant stainless steels and alloys have yield strengths that are only 50 to 70 percent of conventional steels. However, progress has been made in modified alloy compositions and processing that effectively increase the useable strength of these materials. One area where this has been over high interest is in OCTG and pipeline materials. For example, 13Cr stainless steels typically have yield strength limits in the range of 550 to 650 MPa. But now, modified 13Cr alloys with lower carbon content, 4 to 6 percent Ni, 1 to 2.5 percent Mo allow for tubulars with high corrosion resistance combined with yield strengths up to 760 MPa which are also tolerant to moderate levels of H₂S (See Figure 5).⁷ For pipeline applications, 22Cr and 25Cr duplex stainless steels can be attractive alternatives in some high CO₂ applications relative to steel that must be used with inhibitors. With H₂S limits similar to those of 13Cr materials, these materials can be used in the annealed and welded conditions up to about 620 MPa yield strength for piping and topside equipment. They can also be coldworked for use as OCTG to yield strength levels up to 950 MPa.

As discussed previously , one way to push existing offshore systems and technology into deep water is to use higher strength materials. However, this is not always possible and alternative materials which provide lower weight must be utilized. In the search lighter system, engineers have taken some the developments of aerospace designers which have included both metallic and non-metallic materials high combine high strength and low weight. In terms of rise components Ti-alloys are very attractive as a result of a density that is about 60 percent of that of steels. Some alloys such as Ti-6Al-4V and Beta-C can also be processed by heat treatment to over 830 MPa yield strength levels further adding to their utility. These materials have been used in risers and swivel components that must have a combination of flexibility and high strength as well as resistance to corrosion (See Figure 6).⁸

However, one concerns with titanium alloys has historically been resistance to hydrogen embrittlement when used in systems under cathodic protection. Ti-alloys have limited solubility for atomic hydrogen and can be susceptible to hydride formation to varying degrees based on their composition and microstructure and the level of hydrogen charging. Embrittlement due to hydrides increases with increasing cathodic potentials beyond -700 mV SCE. Therefore in seawater applications, limiting CP potentials can increase resistance to hydride formation. Additionally, contrary to what is known about steels and SSC susceptibility, lower strength a -Ti alloys such as Grade 2 are the most susceptible to hydrogen embrittlement whereas alloys containing mixed a +b structures (Ti-6Al-4V) offer generally higher resistance with b -Ti alloys (Ti-Beta C) having even higher resistance. The resistance of equipment made from Ti-alloys to hydrogen embrittlement can also be improved by oxidation treatments that thicken the titanium oxide surface layer. This effectively provides a diffusion barrier on the metal surface that is very impervious to hydrogen diffusion at normal oilfield operating temperatures.

Another avenue being pursued in an effort to obtain lighter, high strength and more flexible structures is with the use of fiber composites. Examples of such uses include platform topside structures, vessels, tanks and piping. New grades of fiber reinforced plastic (FRP) pipe products been developed for seawater injection and downhole production service. Most of the materials are based on chemically resistant polymeric epoxy and polyester resins strengthened with glass, kevlar or carbon fibers which are light weight and yet provide high ultimate strength. Typical materials have up to 30 times the strength of steel and 15 times that of aluminum. Due to cost factors, mostly glass and organic fiber materials utilized in oilfield applications. However, carbon fibers are finding increased application especially in critical areas as manufacturing costs come down. The strength and elastic modulus of FRP products and equipment can often be optimized for specific applications using sophisticated fiber lay-up techniques which place the fibers in the orientations of high tensile stress.

Fiber composites are very serviceable, however their differences from conventional materials must be realized. While being high strength, polymeric materials have more serious wear and temperature limitations than do metallic materials. Design temperature limits for polymers range up to about 120 C for most common materials. They are also often damaged unnecessarily during installation or use because they generally do not have the ductility, impact or abrasion resistance of steel. Chemical compatibility is also an important issue with polymeric materials particularly when longer term serviceability is critical. These materials can absorb moisture and other chemicals and also be affected by UV exposure. These effects can produce time dependent degradation of mechanical properties which can reduce serviceability limits as a function of time (See Figure 7).⁹ Therefore, it is important to know how the performance of FRP materials vary with age and operate within these limits. A variety of test ASTM and NACE methods are available for evaluation of aging in these materials.

One of the advances made within the past several years has been the use of engineered materials systems which bring together specific performance properties of various materials to perform specific functions not previously possible by conventional materials. These types of systems have made a significant impact on offshore operations particularly in the quest for deeper water production. Three types of engineered materials systems which have extended offshore depth capabilities are:

1. Umbilical lines
2. Flexible pipe
3. Risers

Examples of these systems are shown graphically in Figure 8.¹⁰ They have utilized many of the elements of the materials and corrosion technologies given in this presentation combining materials with corrosion resistance, high strength, low weight and flexibility.

A particularly good example of how the abovementioned attributes have been integrated into a single product is illustrated in flexible pipe products such as that shown schematically in Figure 9. It is used for many offshore applications including flexible flowlines linking subsea production and wellhead systems to satellite platforms. Flexible pipe can be reeled for easy transport and field installation. It utilizes multiple ply construction to incorporating high strength steel armor and strength plies, polymeric materials and corrosion resistant alloys. A typical lay-up and cross-section of a section of flexible pipe is shown in Figure 10. The system shown involves eight metallic and non-metallic layers to provide resistance to corrosion, wear and collapse resistance in combination with high tensile strength, flexibility and a barrier to gases and fluids. This is no simple task particularly when the environment contains raw well fluids with high levels of corrosives such as H₂S, CO₂ and brine. Concerns for this system have been resistance of the strength steel plies to HIC and SSC. However, substantial development effort has been made to qualify materials in standard H₂S-containing solutions (NACE TM0177 and TM0284) and various simulated service environments. This work has required the careful selection of steel composition, heat treatment and welding procedures to optimize cracking resistance when exposed to H₂S.

One of the most basic corrosion prevention technologies making offshore operations possible has been cathodic protection. This technology utilizes application of a cathodic polarization originating from either sacrificial anodes or impressed current to the pipe or structure submerged in seawater. This cathodic current works counter to the normal electrochemical corrosion reaction and thereby reducing corrosion rates of the steel cathode to a tolerable level. Local shifts in the pH at the cathode to more alkaline levels also assists in limiting corrosion by inducing the formation of a calcareous scale. In shallow water, cathodic protection system designs are relatively simple, easy to maintain and come with substantial experience in many locations around the world. However, with the advent of deep water operations, there has developed a greater emphasis on design for long term service and reliability. Retrofitting anodes on depleted or poorly designed CP systems in deep water is usually an expensive endeavor. Likewise, with the weight constraints on new deep water platforms, costly over-design of sacrificial anode systems must also be prevented Therefore, greater initial effort is needed to understand the complexities associated with deep water systems.

For example, shallow water systems up to about 200 meter water depths can usually be handled with existing CP technology. Industry standards and years of experience are available which make design of CP systems straight forward. However, for deep water structures, the range of ambient conditions is subject to greater variation with water depth. The local conditions such as water temperature, oxygen content, pH and resistivity may be much different on the sea floor than at the surface. Therefore, the CP system usually has to be designed in zones specifically focusing the CP design for shallow, medium and deep portions separately.

One of the most dramatic effects is the difference in cathodic protection requirements in deep water versus at the surface. Generally, the low temperature (5-10 C) sea bottom conditions result in changes seawater resistivity which is a major factor in CP design. Additionally, the tendency to form protective calcareous deposits on the steel also varies with depth. In the colder seawater, there is a reduction in the rate of calcareous deposition and the composition changes as a result of increased solubility of CaCO₃ and decreased Mg(OH)₂ (See Figure 11).¹² These changes reduce calcareous deposition at low temperature which, in turn, can change polarization characteristics and increase CP current requirements.

The cathodic protection criteria provided in NACE RP-01-76 that are widely used in shallow waters still apply for deep water applications. The difference comes in the greater current requirements to achieve these criteria in deep water as a result of the decrease in protection obtained from calcareous deposition and changes in seawater resistivity at low temperature. However, there are still questions regarding the influence on initial polarization currents on maintenance currents and the output performance of many of the various Al-anode systems with varying Zn content in under low temperature sea bottom conditions. These and other topics are still the subject of ongoing research efforts. Both field and laboratory studies are in progress to better define cathodic protection requirements for deep water in terms of (1) consumption rates for various anode materials (conventional and high performance), (2) anode efficiency, (3) the influence of initial polarization, (4) service temperature and (5) flow rate.

The authors wish to thank the following for their technical contributions and suggestions for this paper: Dr. B. Kermani (BP International), Mr. C. Joia (Petrobras), Mr. G. Farquhar (Texaco GED), Mr. J. Skogsberg (Chevron R&T), Dr. M. Watkins (Exxon Production Research), Mr. A. Erthidge (Wellstream), and Mr. R. Schutz (RMI Titanium).

1. "World Water Depth production Records", Brasil Energy, No. 302, Rio de Janeiro, August 1997.
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3. S. Srinivasanand, and R. D. Kane, "Methods of Data Synthesis in a Rule-based Representation for Characterization of Corrosion and Cracking in CRAs", Corrosion 92, Paper No. 267, NACE, April 1992.
4. R.D. Kane, "Hydrogen Embrittlement of Steels", Corrosioneering On-line Newsletter, CLI International, Inc., No. 1 Vol. 1, (Internet - http://www.clihouston.com/hec.html), Houston, Texas, November 1996.
5. I.S. Cole, et.al., "The Stress Corrosion and Corrosion Fatigue Properties of Two High Strength Steels for Tubulars", Engineering Solutions for Corrosion in Oil and Gas Applications, Proceedings of the 2nd NACE International Symposium, Houston, Texas, Nov. 1989.
6. Kaneko, et.al., "Influence of Microstructure on SSC Susceptibility of Low Alloy High Strength Oil Country Tubular Goods", Corrosion, Vol. 45, No. 1, Jan 1989, pp 2-6.
7. M.S. Cayard and R.D. Kane, "Serviceability of 13Cr Tubulars in Oil and Gas Production Environments", Proceedings Eurocorr'97 (Event No. 208), European Federation of Corrosion, Sept. 1997, pp 109-115.
8. R. Schutz , "Recent Developments in Titanium Alloy Applicatio in the Energy Industry", presented at the International Symposium on TMP and Metallurgy of TitaniumAlloys at TMS THERMEC’97, Wollongong, Australia, July 7-11, 1997
9. A.J. Sedricks, "Minimizing Marine Corrosion Problems by Using Advanced Materials", Proceedings of ADVMAT/91, First International Symposium on Environmental Effects on Advanced Materials, NACE International, Houston, Texas, June 1991. p4-1/17.
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11. A.D. Ethridge and M.S. Cayard, "Application of Standard SSC Test Methods for Evaluating Metallic Components of Non-bonded Flexible Pipe", Paper 55, Corrosion/97, NACE International, Houston, TX, March 1997.
12. W.H. Hartt, et. al., "The Influence of Temperature and Exposure Time Upon Calcareous Deposits", Corrosion/86, Paper No. 291, NACE International, Houston, TX, March 1986.

Figure 1 - World water depth production records

Figure 2 - Hydrogen embrittlement during cathodic charging versus hardness and hydrogen concentration for high strength steel.

Figure 3 - Fatigue crack growth of high strength steel (HSLA80) in seawater, seawater with cathodic protection (-1.0 V SCE), and H₂S contaminated seawater.

Figure 4 - SSC resistance of C-110 versus conventional high strength casing grade steel.

Figure 5 - Data on SSC of 13Cr and Modified 13Cr alloys versus H₂S partial pressure and pH.

Figure 6 - Grade 23 titanium taper stress joints manufactured for the Oryx-Neptune Spar Production Riser System, showing flange connection to steel wellhead tie-back connectors (right side) (Courtesy of RMI Titanium)

Figure 7 - Strength retention of FRP composites with time due to moisture absorption during seawater.

Figure 8 - Various types of offshore systems. (Courtesy of Wellstream)

Figure 9 - Spool of flexible pipe. (Courtesy of Wellstream)

Figure 10 - Typical lay-up of flexible pipe system. (Courtesy of Wellstream).

Figure 11 - Variation in CaCO₃ and Mg(OH)₂ solubility limits with temperature.