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INTRODUCTION ABSTRACT Failure analysis of corroded well tubing steel grade L-80, removed from three separate seawater injection wells on two of our operated fields has revealed the importance of steel microstructure and alloying chemistry. In the first seawater injection well, marked differences in the severity of the corrosion damage between individual tubing joints could be observed. In the other two seawater injection wells it was observed that one well tubing had suffered severe corrosion damage, whereas the other wells tubing had suffered no corrosion damage. This was despite the fact that these two wells were completed within three months of one another and received seawater through the same topside deaeration treatment facility. Analysis of these tubing steels chemistry and microstructure has revealed that the tubing steel containing a mixed microstructure of tempered martensite and bainite suffered severe corrosion damage. Similarly, the tubing steel with a tempered martensitic microstructure without chromium addition (<0.1 wt%) also suffer severe corrosion damage. But, a tubing steel with the combination of a tempered martensitic microstructure and chromium content > 0.5 wt% suffered little or no corrosion damage. These findings stress the significant role that the microstructure and alloying chemistry play in enhancing the corrosion resistance performance of grade L-SO tubing steel for seawater injection service. We are currently responsible for the operation of nine offshore seawater injection systems on five Oil and Gas production fields, A total seawater injection volume of 375000 Sm3/d is injected into 70 dedicated seawater injection wells. The main materials used in the construction of the seawater injection well tubing is low-alloy steel in accordance with API SCT grade L-SO. This material can be used because the seawater to be injected is treated to remove dissolved oxygen by means of both deaeration process equipment and chemical oxygen scavangers. This will effectively reduce the dissolved oxygen concentration in the injected seawater to below 20 ppb, under normal continuous injection. But, as has been reported earlier,ref. 1, these systems suffer from various operational upsets and interruptions, which leads to increased dissolved oxygen concentration within the injected seawater. This inturn results in corrosion damage to both the topside pipework and well tubing. A number of seawater injection wells have been worked over due to internal corrosion damage to the well tubulars. This has consequently resulted in a close analysis of the retrieved tubing from each worked over injection well, which has revealed a number of significant observations. The following describes some of these significant observations and their relevance to improving the corrosion resistance of API 5CT grade L-SO steel for tubing application in seawater injection wells.
- North America > United States > Kentucky > Quality Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Block 33/9 > Statfjord Field > Statfjord Group (0.99)
- Europe > Norway > North Sea > Northern North Sea > East Shetland Basin > Block 33/9 > Statfjord Field > Cook Formation (0.99)
- (4 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
ABSTRACT The effect of organic acid on CO2 corrosion of carbon and Cr bearing steels was investigated. Acetic acid was considered as the organic acid. The temperature(Tmax), which gave a maximum corrosion rate, was observed on pure iron, and 1 and 2°/0Cr steels in the C02 environment with O.S/O CH3COOH as well as in the C02 environment without CH3COOH. The corrosion rate of these steels at Tmax, extremely increased due to the addition of 0.5% CH3COOH, but the Tmax did not change. In 9 and 130/0Cr steels, the Tmax Was observed in the CO2 environment without CH3COOH, but did not in the C02 environment without CH3COOH, and those corrosion rates continued to increase at the temperature above the Tmax in the C02 environment without CH3COOH. These corrosion behaviors were discussed from a viewpoint of pH and FeCO3 formation condition which was led from the calculated-equilibrium volubility of FeC03 at elevated temperatures. Then, those were related to the acceleration of corrosion at the steel surface with heterogeneous FeCO3 film in pure iron, and 1and 2°/0 Cr steels, and the different formation behavior of corrosion products at the temperatures below and above 200C in 9 and 1So/o Cr steels. INTRODUCTION It is well known that carbon and low alloy steels suffer from C02 corrosion which has been one of important problems in oil and gas fields l. The problem in the C02 corrosion called Sweet corrosion has been a high corrosion rate and a severe localized corrosion. The severity of corrosion depends particularly on temperature, C02 partial pressure, pH and material characteristics13 >4. The effect of environmental factors and material characteristics on C02 corrosion is briefly summarized as follows: 1.The temperature where carbon steel shows the highest susceptibility to the severe corrosion is around 100°C3. The corrosion behavior is related to the FeC03 formation behavior which is a corrosion product in C02 environments. The C02 corrosion of carbon steel is classified to three types of corrosion below 60C, at about 10O°C and above 150C. The first is a general corrosion type, the second is a deep pitting and/or a ringworm corrosion type, and the third is a corrosion resistant type through the formation of protective FeC03 film. 2.The corrosion rate of carbon steel increases with the increasing of C02 partial pressure. De Waard et al has proposed a monograph to estimate the corrosion rate from C02 partial pressure and temperature. The effect of Cl ion concentration on the corrosion rate of carbon steel is small in C02 environments. 3.The fluid produced in oil and gas fields and the solution used for tiled operation have various organic acids. The effect of acetic acid and formic acid in C02 environments with condensed water, which was taken from a gas well, was investigated by Legezin et al, and they reported the increasing of corrosion rate due to the addition of those organic acids 6. However, the effect of other environmental factors and material characteristics in the C02 environments with organic acids is not enough investigated. 4.Low Cr bearing steel with Cr content below about 2mass% is an allowable corrosion resistant steel to general and localized corrosion below about 60C. The result of the loop tests in a CO2 environment at 60°C showed the Cr dependence on corrosion rate: that is, the higher the Cr content in steels, the lower the corrosion rate3. Because the low Cr bearing steel has Cr enriched corrosion product in C02 environments. Then, it is well known that API 13Cr steel with Cr oxide passive film at room temperature has good corrosion resistance in C02 environments below 150°C and its application to oil and g
Effect of Chromium and Molybedenum on Corrosion Resistance of Super 13Cr Martenistic Stainless Steel in CO2 Environment
Amaya, Hisashi (Sumitomo Metal Industries Ltd.) | Mori, Tomoki (Sumitomo Metal Industries Ltd.) | Kondo, Kunio (Sumitomo Metal Industries Ltd.) | Hirata, Hiroyuki (Sumitomo Metal Industries Ltd.) | Ueda, Masakatsu (Sumitomo Metal Industries Ltd.)
ABSTRACT The effect of Cr and MO on the corrosion resistance of super 13Cr stainless steel in CO, environment has been investigated by the electrochemical technique and the surface film analysis. The corrosion rate in CO, environment at elevated temperatures is reduced with the increase in the effective Cr content. The pitting resistance is improved by the addition of more than 0.25 mass% MO, because MO is effective to stabilize the passive film in the CO, environment. The effect of the MO content on the SSC susceptibility in CO, environment with a little amount of H,S has been also studied. MO is also effective to improve the SSC resistance by the formation of MO sulfide in the outer layer of the surface film, because the MO sulfide film can assist the formation and/or stabilization of the Cr oxide passive film in the inner layer even in the CO, environment with a little amount of H,S at room temperature. Based on these results, O.OlC-13Cr-5.2Ni-0.7Mo steel chemical compositions has been determined to improve the corrosion resistance of 13Cr martensitic stainless steel. The applicable environment of the developed steel will be discussed compared with super 13Cr stainless steel containing 2mass% MO and conventional 13Cr steel. INTRODUCTION The field application of martensitic stainless steel containing 13% Cr (AISI 420, hereafter referred to as conventional 13Cr) has been increasing due to its good corrosion resistance in CO, (sweet) environment [l]. It is widely recognized that the conventional 13Cr stainless steel is susceptible to sulfide stress cracking (SSC) in the CO, environment with H,S partial pressure more than 0.0003MPa and less resistant to general and localized corrosion at elevated temperatures (>15Oc) [2]. Recently, a number of new enhanced 13Cr martensitic stainless steels with the higher resistance to general and localized corrosion in CO, environment at elevated temperatures and to SSC resistance in the environment with a little amount of H,S at room temperature have been proposed by some researchers [3-51. In a super 13Cr martensitic stainless steel, the carbon content is reduced to below 0.03 mass% in order to suppress the reduction of Cr concentration in the matrix as the Cr carbide precipitation, 5.5 mass% Ni content is added to obtain the martensitic single phase and 2 mass% Mo content is added to improve SSC and localized corrosion resistance [6]. The super 13Cr martensitic stainless steel has the higher resistance to the general and localized corrosion in CO, environment at the elevated temperatures up to around 180°C than that of conventional 13Cr stainless steel, and is immune to SSC in the environment with 0.001 to 0.003MPa partial pressure of H,S at room temperature. The super 13Cr steel can be applied to not only OCTG but also flow line materials, because the welded joints without PWHT have superior properties due to low C concentration.[7]. Because of these superior properties, the super 130 stainless steel has been widely applied for OCTG [8] and for flow line materials [9]. Thus, the super 13Cr steel can play an intermediate role between conventional 13Cr and duplex stainless steels as regards both the corrosion resistance and the material cost. The requirement of the optimum material for each field condition has been increased recently in order to reduce the cost of well developments. Therefore, a new 13Cr martensitic stainless steel has been investigated by modifying the super 13Cr stainless steel for OCI?G (O.O2C-12Cr-5.5Ni-2Mo). The most important corrosion problems for 13Cr martensitic stainless steel are both general and localized corrosion at elevated temperatures and SSC at ambient temperature in CO, environment with a little amount of H,S. Th