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Corrosion oilfield

Sulfide Stress Cracking Resistant Metallic Materialfor OilField Equipment, NACE Standard MR-01-75, 1980 rev.. Technical Practices Committee, National Association of Corrosion Engineers, Houston, Tex., 1980. [Pg.156]

In oilfield situations we are generally faced with corrosion attacks in aqueous environments. Basically all attacks in aqueous solutions are electrochemical in nature. This means that besides the chemical reaction there will also be a flow of electrons, resulting in a flow of current. The current flows from a higher potential to a lower one. Hence, there are two reactions taking place simultaneously in the system. One reaction occurs as the electrons are discharged from the surface, called the anode. The released electrons are consumed in the other... [Pg.1259]

The vast majority of corrosion design issues faced in marine and offshore engineering involve water in one form or another. In that regard, the two principal media involved are seawater and formation waters (oilfield brines). Seawater, of course, surrounds offshore installations though may also be used as the medium in reservoir injection and other critical offshore process... [Pg.62]

Thomason, W. H., Corrosion Monitoring with Hydrogen Probes In The Oilfield , Materials Performance, 23, 5. 24-29, May (1984)... [Pg.1151]

Corrosion Control Engineering Joint Venture, Task Group EI/1, Review of Current Practices for Monitoring Bacteria Growth in Oilfield Systems, ICorr Document 001/87 (1987). [Pg.1151]

Anonymous. Microbiologically influenced corrosion and biofouling in oilfield equipment. Nace TPC Publication TPC 3, 1990. [Pg.349]

M. J. Bronaley, S. H. Gaffney, and G. E. Jackson. Oilfield emulsion control, techniques and chemicals used to separate oil and water. In Proceedings Volume, volume 3. Inst Corrosion UK (Corrosion 91) Conf (Manchester, England, 10/22-10/24), 1991. [Pg.363]

J. Cossar and J. Carlile. A new method for oilfield corrosion inhibitor measurement. In Proceedings Volume. Annu NACE Corrosion Conf (Corrosion 93) (New Orleans, LA, 3/7-3/12), 1993. [Pg.374]

F. B. Growcock. Surfactants can affect corrosion inhibition of oilfield steel. In Proceedings Volume. SPE Oilfield Chem Int Symp (San Antonio, TX, 2/4-2Z6), 1987. [Pg.398]

R. M. Matherly, J. Jiao, J. S. Ryman, and D. J. Blumer. Determination of imidazoline and amido-amine type corrosion inhibitors in both crude oil and produced brine from oilfield production. In Proceedings Volume. 50th Annu NACE Int Corrosion Conf (Corrosion 95) (Orlando, FL, 3/26-3/31), 1995. [Pg.429]

J. A. Newton. Applications of spectroscopic quality control techniques for oilfield chemicals. NACE Corrosion 88 (St Louis, MO, 3/21-3/25), 1988. [Pg.440]

H. A. Videla, P. S. Guiamet, O. R. Pardini, E. Echarte, D. Trujillo, and M. M. S. Freitas. Monitoring biofilms and MIC (microbially induced corrosion) in an oilfield water injection system. In Proceedings Volume. Annu NACE Corrosion Conf (Corrosion 91) (Cincinnati, OH, 3/11-3/15), 1991. [Pg.473]

Oilfields in the North Sea provide some of the harshest environments for polymers, coupled with a requirement for reliability. Many environmental tests have therefore been performed to demonstrate the fitness-for-purpose of the materials and the products before they are put into service. Of recent examples [33-35], a complete test rig has been set up to test 250-300 mm diameter pipes, made of steel with a polypropylene jacket for thermal insulation and corrosion protection, with a design temperature of 140 °C, internal pressures of up to 50 MPa (500 bar) and a water depth of 350 m (external pressure 3.5 MPa or 35 bar). In the test rig the oil filled pipes are maintained at 140 °C in constantly renewed sea water at a pressure of 30 bar. Tests last for 3 years and after 2 years there have been no significant changes in melt flow index or mechanical properties. A separate programme was established for the selection of materials for the internal sheath of pipelines, whose purpose is to contain the oil and protect the main steel armour windings. Environmental ageing was performed first (immersion in oil, sea water and acid) and followed by mechanical tests as well as specialised tests (rapid gas decompression, methane permeability) related to the application. Creep was measured separately. [Pg.167]

Standard Material Requirements Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment Corrosion Engineers Reference Handbook... [Pg.72]

NACE MR0175-2003 - Metals for Sulphide Stress Cracking and Stress Corrosion Cracking resistance in Sour Oilfield Environments (published by NACE), a standard which is now already withdrawn. [Pg.81]

Water Purification Desalinization Chemicals Oilfield Chemicals Corrosion Inhibitors Biocides... [Pg.190]

NAiCE Standard MR0175, Sulfide Stress Corrosion Cracking Resistant Metallic Material for Oilfield Equipment," MACE, Houston, TX. latest revisron. [Pg.151]

Several investigators have demonstrated that there is no direct correlation between numbers of SRB and the likelihood that corrosion has occurred or will occur. Jack and coworkers [41] prepared a review of 30 months of electrochemical measurements, weight-loss data, water chemistry and microbiological data for an oilfield waterflood operation in which produced brine was injected to displace oil from the reservoir. They concluded that SRB numbers could be used as an index of biocide performance in these field systems. No other correlations between corrosion measurements and microbial numbers were found. [Pg.670]

A consequence of the use of advanced technology in oil production from a reservoir results in increase in the corrosivity of the oil production environment. The extent of corrosion increases because (i) oil, water, and gas are present in the field. Seawater or fresh water is injected downhole to drive oil out of formation. As time passes, the amount of water to the amount of oil increases and the degree of internal corrosion increases. Water injection from seawater or fresh water sources causes souring of oilfields with H2S and increases in corrosion rate. These water sources require biocide injection and deaeration to avoid the introduction of new corrosion pathways into the existing system. Tertiary recovery techniques involve miscible and immiscible gas floods that may contain as much as 100% CO2. This leads to high corrosivity of the fluids. [Pg.290]

Because of the high cost of failure and inability to rehabilitate facilities in deep water, offshore production in deep water requires the use of high alloy steels and more exotic corrosion control measures. A similar need for advanced corrosion control measures is encountered when dealing with high-pressure and high-temperature offshore oil and gas fields where conventional corrosion mitigation is not applicable. Typical costs for various expenses for one large oilfield area are listed in Table 4.41. [Pg.290]

S. Maxwell, C. Devine, F. Rooney, I. Spark. Monitoring and control of bacterial biofihns in oilfield water handling systems. Paper No. 04752, Corrosion 2004, NACE International, Honston, TX, 2004. [Pg.119]

P. Smith, S. Roy, D. Swailes, S. Maxwell, D. Page, J. Lawson. A predictive model for MIC (microbial induced corrosion) in sub-sea production pipelines Part 1—Abiotic corrosion model. SPE 114135, 2008 SPE International Oilfield Corrosion Conference, Aberdeen, UK, May 27, 2008. [Pg.128]

Use of corrosion resistant alloys in oilfield environments. NACE Technical Report IF192 (1993 Revision). [Pg.211]


See other pages where Corrosion oilfield is mentioned: [Pg.64]    [Pg.422]    [Pg.422]    [Pg.1297]    [Pg.75]    [Pg.80]    [Pg.1142]    [Pg.236]    [Pg.390]    [Pg.225]    [Pg.439]    [Pg.306]    [Pg.190]    [Pg.367]    [Pg.64]    [Pg.1565]    [Pg.64]    [Pg.169]    [Pg.463]    [Pg.666]    [Pg.170]    [Pg.289]    [Pg.394]    [Pg.3]   
See also in sourсe #XX -- [ Pg.290 ]




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