Sour gas and high-strength steel are generally accepted to be incompatible. However when drilling beyond 20000ft S135 and higher steel grades become necessary to support their own weight, and due to the elevated down hole pressures in the range of 15–20ksi, even minimal concentrations of H2S result in partial pressures that are considered hostile for these steel grades. The paper presents initial results from a joint industry project exposing S-grade drill pipe samples to various H2S concentrations in temperature ranges from 70–170°C and exposure times of 1–3 hours, representing typical conditions when circulating a gas kick to surface. Test conditions have been designed to closely recreate actual down hole conditions, with actual potassium carbonate drilling fluids saturated with hydrogen sulphide and an additional free gas phase. After exposure to the sour environment, the samples have then been taken to fatigue testing to evaluate actual damage against undamaged base-line fatigue results. Introduction Sour drilling environments where H2S gas is present and sour-gas kicks are possible can lead to Sulfide Stress Cracking (SSC) failures in steel drill pipe. In practice, a combination of stress, an environment containing H2S and a susceptible material are required for SSC to occur. SSC occurs as a result of atomic hydrogen entering the steel. Once inside the metal, the atomic hydrogen diffuses to initiation sites where in can cause localized increases in stress or a reduction in the strength of the material lattice. It is generally agreed that brittle H2S induced cracking is closely related to hydrogen embrittlement as a result of the ingress of hydrogen into the stressed material. Hydrogen is a problem in most steels because it is highly mobile in atomic form and can both diffuse through and be transported by the movements of dislocations. Hydrogen embrittlement can result in either a loss of ductility or a cracking phenomenon. Conditions that promote SSC in drill pipe include high tensile stress, high concentrations of H2S, low pH, high pressure, high chloride content, lower temperatures and high material hardness (higher strength steels generally have higher hardness properties). Material selection for drill pipe in sour applications is significantly more complex than material selection for production casing and tubing in similar well applications due toa more close controlled and known environment by the time casing and especially tubing strings are run, andthe defined requirement for these strings to survive long-term exposure to corrosive atmosphere whereas drill strings will only be exposed for a short time during a loss of hydrostatic equilibrium in the well. Production casing and tubing designers determine if the well parameters create a sour service environment as defined by NACE MR0175. Production casing and tubing materials resistant to SSC are required if the system contains water as a liquid, the H2S partial pressure exceeds 0.05 psi and the system pressure is greater than or equal to 65 psi or 265 psi depending on the gas:oil ratio of the system.

A new testing facility for a high-velocity, three-phase fl ow consisting of a gas fl ow loop and a jet impingement rig is described. Flow velocities between the nozzle and specimen have been determined through computational fl uid dynamics (CFD) simulations and by particle image velocimetry. Tests were conducted on typical carbon steels (J55 and C95) that are used in tubings for the gas and oil industry. Flow conditions of a sweet gas condensate well have been applied. Mass-loss rates have been determined after testing times of between 4 h and 168 h using optical profi lometry. Damaged surfaces were investigated using optical and scanning electron microscopy. The effects of material and fl ow velocity on the mass-loss rate have been investigated. Mass loss of specimens under given conditions is determined by siderite formation and increasing degradation of siderite layer by impacts of sand and fl uid droplets. Degradation happens by erosionenhanced corrosion. Normalized steel J55 behaves like a ductile material resulting in a maximumdegradation rate under small impact angles outside the focal spot. Compared to J55 the quenched and tempered material C95 shows a generally lower depth of attack with its maximum degradation under large impact angles, indicating a brittle behavior. Cementite of pearlite may act additionally as a cathode and accelerate corrosive attack. KEY WORDS: carbon dioxide corrosion, carbon steel, erosioncorrosion, erosion-enhanced corrosion, fl ow-induced localized corrosion, fl ow loop, jet impingement, multiphase fl ow 0010-9312/08/000035/$5.00+$0.50/0

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The erosion-corrosion behavior of two corrosion-resistant alloys (UNS S42000 and UNS N08028) has been assessed under gaseous-liquid-solid impingement conditions. Erosioncorrosion impingement tests were conducted at three different impact angles and at three different impact velocities up to 60 m/s, and furthermore, pure erosion and pure corrosion impingement tests were run for UNS S42000, and carbon dioxide (CO 2 ) at a pressure of 1,500 kPa was used as the gas phase. The sand content, with grain size below 150 µm, was 2.7 g/L brine. Artificial brine with a sodium chloride (NaCl) content of 2.7% was used as liquid phase. The damaged surfaces of samples exposed to the high-velocity multiphase flow were investigated using scanning electron microscopy (SEM) and an optical device for 3D surface measurements to assess the depth of attack. Electrochemical investigations according to ASTM G61 were performed to determine electrochemical behavior of tested materials including critical pitting potentials (E pit ) and repassivation potentials (E repass ). Furthermore, the surfaces near regions of the samples tested were investigated using applying atomic force microscopy (AFM), magnetic force microscopy (MFM), and nano-indentation measurements. From the analysis, variation of velocity shows the greatest effect on the degradation rate of both materials. In this paper the erosion-corrosion behavior and rates of two stainless steels are presented. The effects of their chemical composition and mechanical properties are discussed.

In petroleum production, the problem of corrosive media attacking metallic structures is almost ubiquitous. Particularly severe environments are encountered in the production and transport of wet natural gas containing corrosive components, such as hydrogen sulphide and carbon dioxide. When exploring new gas fields, it is therefore a prerequisite to take into account the corrosivity of the respective fluids in all stages of the field development, material selection, field layout, and facilities design. In preparation of the subsequent production phase, reliable corrosion monitoring programs have to be selected, established, and implemented as necessary. Furthermore, the financial aspects always play an important role, thus posing a real challenge for the engineer forced to seek a compromise between economics and design.This paper gives a comprehensive overview of these considerations regarding four different OMV gas fields, two in Austria and two in Pakistan, which were successfully developed and brought onstream between 1967 and 2003. These fields not only vary in their geographical position, but also in their gas compositions, production start, and the location of gas dehydration units.One major aspect dealt with in each of these cases was material selection, including metallic as well as nonmetallic and composite materials. Where the initial decision was made in favor of carbon steel, different methods of corrosion protection, the application of corrosion inhibitors, corrosion monitoring, and intelligent pigging are discussed in the paper.A comparison of the various methods of resolution worked out for all four case histories, as well as the experience gained in more than three decades of production and transportation of wet, corrosive natural gas is presented.Furthermore, results of the ongoing corrosion monitoring measurements in operation in the mature gas fields are discussed under the aspect of the remaining facility lifetimes.

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The combination of dissimilar metals can result in corrosion due to galvanic effects. These are caused by differences in their electrode potentials. The spread difference between these potentials is the driving force for galvanic corrosion. Literature data usually refer to either standard conditions or aerated sea water at ambient temperature. However, the actual electrode potentials are influenced by a variety of factors such as temperature, pH, dissolved gases and salts, flow rates, scale formation, etc. For conditions encountered in the oil and gas industry, there are hardly any data about electrode potentials available. The aim of this work is to create a practical galvanic series under typical upstream conditions for standard oil country tubular goods (OCTG) steels, corrosion resistant alloys (CRA) as well as the gasket material graphite. The following materials were selected for the tests, which are considered as representative for downhole and topsides equipment: J55, L80 Type 1, X52, Cr13, 316Ti, 2205, 904L and Graphite. The electrode potentials and polarization resistances of the selected materials were measured in synthetic formation water with dissolved carbon dioxide (CO2) at temperatures between 22 and 130 °C. To account for the influence of bicarbonate and acetic acid these species were added in some of the tests. In order to also identify overpotential effects the electric galvanic currents were determined between coupled dissimilar materials in the described media at different temperatures by electrochemical noise measurements (CoulCount-Method). For comparison, actual corrosion rates of dissimilar material couples were measured gravimetrically. The results exhibit the influences of temperature, bicarbonate and acetic acid on the electrode potential of each material. Galvanic corrosion effects are observed between CRAs and OCTG. The highest galvanic corrosion occurs between graphite and OCTG and is also distinct between graphite and CRAs. Temperature has a strong influence on the galvanic corrosion. At high temperatures, galvanic corrosion effects occur also in couples of different CRAs. The results show a good agreement between the measured electrode potentials, the results of electrochemical noise measurements and the gravimetric corrosion tests. This work provides a practical galvanic series for materials and conditions that are usually encountered in the upstream oil and gas industry. Based on the results of the work presented it is possible to rate the galvanic material behavior under similar conditions. Being one of the first publications in this field of application, it represents a reference for material selection, engineering and failure analysis.