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Search Petrowiki: Stress corrosion cracking
...Also referred to as Stress Corrosion, this occurs in metal that is subject to both ...stress and a corrosive environment. May start at a "...stress riser" like a wrench mark or packer slip mark...
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...Cracking of a metal under the combined action of tensile ...stress and ...corrosion in the presence of water and hydrogen sulfide (a form of hydrogen ...
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...Corrosion problems in production ...Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oi...l and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Age and presence of corrosive materials such as carbon dioxi...
Corrosion of metal in the presence of water is a common problem across many industries. The fact that most oil and gas production includes co-produced water makes corrosion a pervasive issue across the industry. Corrosion control in oil and gas production is reviewed in depth in Treseder and Tuttle,[1] Brondel, et al.,[2] and NACE,[3] from which some of the following material is abstracted. Iron is inherently (thermodynamically) sufficiently active to react spontaneously with water (corrosion), generating soluble iron ions and hydrogen gas. The utility of iron alloys depends on minimizing the corrosion rate. Corrosion of steel is an "electrochemical process," involving the transfer of electrons from iron atoms in the metal to hydrogen ions or oxygen in water. This separation of the overall corrosion process into two reactions is not an electrochemical nuance; these processes generally do take place at separate locations on the same piece of metal. This separation requires the presence of a medium to complete the electrical circuit between anode (site of iron dissolution) and cathode (site for corrodant reduction). Electrons travel in the metal phase, but the ions involved in the corrosion process cannot. Ions require the presence of water; hence, corrosion requires the presence of water. This overall process is shown schematically inFigure 1.[3]
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...Cracking of a metal under combined action of tensile ...stress and ...corrosion in the presence of chlorides and an electrolyte (NACE). Starts at a pit, scratch or notch. Crack pr...
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...ced in casing by drilling, production, and workovers, and these loads might cause buckling (bending stress) loads in uncemented intervals. In shallow normal-pressured wells, temperature will typically have ...ing burst, collapse and axial ratings accordingly. Sour gas well design Sour gas (H2S) may cause stress corrosion cracking on casing and lead to catastrophic failure of the casing string. So sour gas is a major considerati...ing the appropriate material for the production casing and tubing. The factors influencing sulphide stress cracking failure include the H2S concentration, pressure, temperature and the fluid pH environment, and in s...
To evaluate a given casing design, a set of loads is necessary. Casing loads result from running the casing, cementing the casing, subsequent drilling operations, production and well workover operations. Temperature changes and resulting thermal expansion loads are induced in casing by drilling, production, and workovers, and these loads might cause buckling (bending stress) loads in uncemented intervals. In shallow normal-pressured wells, temperature will typically have a secondary effect on tubular design. In other situations, loads induced by temperature can be the governing criteria in the design.
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...lations. Tubing with the use of a packer allows isolation of the casing from well fluids and deters corrosion damage of the casing. Multicompletions require tubing to permit individual zone production and oper...I specifications but are used in the petroleum-producing industry for: * Resistance to weight-loss corrosion * Higher strengths * Less susceptibility to sulfide ...stress corrosion cracking (SSC) * Wear resistance ...
Tubing is the normal flow conduit used to transport produced fluids to the surface or fluids to the formation. Its use in wells is normally considered a good operating practice. This page introduces tubing uses and types. The use of tubing permits better well control because circulating fluids can kill the well; thus, workovers are simplified and their results enhanced. Flow efficiency typically is improved with the use of tubing.
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...H2S. These have been difficult to produce in the past because of the tendency for sour gas to cause corrosion and sulphide ...stress corrosion cracking, particularly in pipelines. With the advent of ...corrosion resistant materials and advanced manufacturing techniques for steel pipelines the production of the...
Natural gas that contains more than 4 ppmv of hydrogen sulphide (H2S) is commonly referred to as "sour". This is because the odour of hydrogen sulphide gas in air at very low concentrations is similar to that of rotten eggs. Significant quantities of natural gas resources around the world are known to contain H2S. These have been difficult to produce in the past because of the tendency for sour gas to cause corrosion and sulphide stress corrosion cracking, particularly in pipelines. With the advent of corrosion resistant materials and advanced manufacturing techniques for steel pipelines the production of these sour gas reserves is now becoming possible. Downstream refineries have been handling sour gas as a by-product from the processing of sour crude oil for many decades ..... H2S is highly toxic and can cause serious injury and death at relatively low concentrations. The characteristic odour can be detected by human beings at very low concentrations. However, at higher concentrations the odour can no longer be detected by human beings and the inability of human beings to detect its presence is a major risk factor. The toxic effects of H2S are summarised in the table below.
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...oduction have a major effect on the IFT of the produced water and the hydrocarbons. Indeed, certain corrosion inhibitors added to the three-phase production stream can lower the produced water IFT enough ( 1 t...ul for water identification or correlation purposes, but it does indicate possible scale-forming or corrosion tendencies of a particular water. The pH also may indicate the presence of drilling-mud filtrate or...t is so poisonous. H2S also causes rapid, nearly instantaneous, failure of steel because of sulfide stress-corrosion cracking, unless the steel has been specified for "sour service." Besides the presence of sulfate ions, diss...
Understanding the physical properties of the formation water that will be produced along with the oil or gas is important to a proper assessment of reserves volumes, producibility, economics, and surface facilities. As a rule, it is best to have reliable laboratory measurements of the physical properties of oilfield waters. If laboratory measurements are not available, correlations may have to be used. For example, McCain has published some of the most widely used correlations for the physical properties of oilfield waters.[1][2] This page discusses the resistivity, surface (interfacial) tension, viscosity, pH, and redox potential (Eh) of produced water.
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...s Designing the tubing for a well requires consideration of strength, load, performance, stretch, corrosion, coatings and many other factors. This page introduces each of these factors and includes some exam...Example 2 * 7 Example 3 * 8 Example 4 * 9 Stretch in tubing * 10 Example 5 * 11 Buckling * 12 Corrosion considerations * 13 Internal coatings * 14 Nomenclature * 15 References * 16 Noteworthy papers ... pressure wells, especially in sour service when L80, C90, and T95 API grades are used, the general stress level in the tubing should not exceed the minimumyield strength for L80 or the sulfide ...
Designing the tubing for a well requires consideration of strength, load, performance, stretch, corrosion, coatings and many other factors. This page introduces each of these factors and includes some example tubing designs. A design factor is the specific load rating divided by the specific anticipated load. A design factor less than 1.0 does not necessarily mean the product will fail, and neither does a design factor in excess of 1.0 mean that the product will not fail. As a result, design factors are generally selected on the basis of experience. The designer has the responsibility to select the design factors to suit particular needs and to reflect field experience. The condition of the tubing and the severity of a failure should have a significant effect on the design factors used. Design factors greater than 1.0 are recommended.Table 1 contains design factor guidelines. * The internal-yield pressure rating for tubing is based on an American Petroleum Institute (API) variation of Barlow's formula and incorporates a 0.875 factor that compensates for the 12.5% reduction tolerance in wall thickness allowed in manufacturing. In general, these values should not be exceeded in operation. To be on the safe side, a minimum design factor of 1.25 based on the internal-yield pressure rating is suggested; however, some operators use different values. In medium to high pressure wells, especially in sour service when L80, C90, and T95 API grades are used, the general stress level in the tubing should not exceed the minimumyield strength for L80 or the sulfide stress corrosion cracking (SSC) threshold stress (generally 80% of the minimum yield strength) for C90 and T95 grades. The joint or body yield strength for the tension design factor varies widely in practice.
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...d-water issues, including chemistry; hydrodynamics; surface/interfacial science; materials science; corrosion; mechanical, chemical, and petroleum engineering; as well as environmental regulators. Compared wit...within the same wellbore downhole or mixed on the surface. The mixing can lead to scale deposition, corrosion, and other effects. Artificial lift can also alter the stability of the water. In particular, gas l...gh this may not be immediately apparent because only the hydrocarbons produce revenue. Fig. 10.1 โ Corrosion-inhibition cost on a per-barrel-oil basis determines the maximum producible economic water cut (ass...
Early U.S. settlements commonly were located near salt lakes that supplied salt to the population. These salt springs were often contaminated with petroleum, and many of the early efforts to acquire salt by digging wells were rewarded by finding unwanted amounts of oil and gas associated with the saline waters. In the Appalachian Mountains, saline water springs commonly occur along the crests of anticlines.[1] In 1855, it was found that petroleum distillation produced light oil that was, as an illuminant, similar to coal oil and better than whale oil.[2] This knowledge spurred the search for saline waters containing oil. With the methods of the salt producers, Colonel Edward Drake drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859. He struck oil at a depth of 70 ft, and this first oil well produced approximately 35 B/D.[3] Early oil producers did not realize the significance of the oil and saline waters occurring together. In fact, it was not until 1938 that the existence of interstitial water in oil reservoirs was generally recognized.[4] Torrey[5] was convinced by 1928 that dispersed interstitial water existed in oil reservoirs, but his colleagues rejected his belief because most of the producing wells did not produce any water on completion. Occurrences of mixtures of oil and gas with water were recognized by Griswold and Munn,[6] but they believed that there was a definite separation of the oil and water, and that oil, gas, and water mixtures did not occur in the sand before a well tapped a reservoir. It was not until 1928 that the first commercial laboratory for the analysis of rock cores was established, and the first core tested was from the Bradford third sand (Bradford field, McKean County, Pennsylvania). The percent saturation and percent porosity of this core were plotted vs. depth to construct a graphic representation of the oil and water saturation. The soluble mineral salts that were extracted from the core led Torrey to suspect that water was indigenous to the oil-productive sand. Shortly thereafter, a test well was drilled near Custer City, Pennsylvania, that encountered greater than average oil saturation in the lower part of the Bradford sand. This high oil saturation resulted from the action of an unsuspected flood, the existence of which was not known when the location for the test well had been selected. The upper part of the sand was not cored. Toward the end of the cutting of the first core with a cable tool, core barrel oil began to come into the hole so fast that it was not necessary to add water for the cutting of the second section of the sand. Therefore, the lower 3 ft of the Bradford sand was cut with oil in a hole free from water.
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