A method for correcting log-derived temperatures in deep wells (3500–6500 m) has been developed by comparing log temperatures from the Gulf of Campeche (Mexican Gulf of Mexico) with DST temperatures in the same wells. The equations developed in this study are modified slightly from those of Waples & Mahadir Ramly (2001) , which were calibrated using data from depths <3500 m in Malaysia. The correction depends strongly on time since end of mud circulation ( TSC ) and, to a much lesser degree, on depth. In this study the true subsurface temperature (Celsius) is given by \batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} T_{true}=T_{surf}+f{\cdot}\left(T_{meas}{-}T_{surf}\right){-}0.001391\left(Z{-}4498\right)\end{document} where f =1.32866 −0.005289 TSC , T surf is the seafloor or land-surface temperature (°C), T meas is the measured log temperature (°C), TSC is in hours and Z is depth below seafloor in metres. If TSC is unknown, it can be estimated from the trend of TSC with depth. An estimate of the uncertainty in the corrected temperature is obtained from the equation: \batchmode \documentclass[fleqn,10pt,legalpaper]{article} \usepackage{amssymb} \usepackage{amsfonts} \usepackage{amsmath} \pagestyle{empty} \begin{document} {\sigma}=0.10842^{{-}0.029TSC}\end{document} where σ is the standard deviation of the correction factor f . The uncertainty in the correction factor f can be expressed as ±2 σ .

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A risk model was developed to identify the probability that unacceptable downhole corrosion will occur as the Arun field is depleted. Using life-expectancy estimates for the carbon steel (CS) tubing strings from this model, optimized mitigation strategies could be developed to provide cost-effective alternatives for corrosion management.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe ability to optimize the use of carbon steel in corrosive service presents many economic advantages, including minimizing the use of expensive corrosion resistant alloys, reducing well count by enabling optimized large bore completions, and eliminating additional offshore pipelines and facilities. An integrated approach to corrosion modeling and testing is employed by ExxonMobil to reliably extend the application of carbon steel.The integrated approach to predicting corrosion has five primary elements:1. Rigorously establish the environmental conditions by conducting thermodynamic and compositional hydraulic analyses, and characterize how these conditions are expected to change over time. 2. Identify the local environmental conditions and the types of corrosion that are expected to occur (e.g., weight loss, pitting, environmental cracking), including sensitivity and upset cases. 3. Conduct realistic corrosion tests under the identified field conditions by simulating brine chemistry, dissolved acid gas concentrations, hydrocarbon effects, fluid shear stresses, and flow regime in appropriate laboratory equipment. Specialized laboratory test apparati, such as a large-diameter sour, multiphase flow loop and large-volume highpressure high temperature autoclave test cells, have been designed and constructed to ensure proper reproduction of field conditions. 4. Mathematically extrapolate the results of the laboratory tests to the field, enabling calculation of expected tubular life. 5. Conduct life cycle cost analysis. This paper will describe how this integrated approach to predicting corrosion is used to evaluate the use of carbon steel in oil and gas production environments. Special emphasis will be placed on the prediction of pitting corrosion in H 2 Scontaining environments.

An important element that is often overlooked during chemical qualification and application is the compatibility between oilfield chemicals (OFCs), which can critically impact the ability of the chemicals to meet their desired function in the field. In the area of corrosion control, one important example of this is the interference of oilfield chemicals on corrosion inhibitor effectiveness. In this study, we aimed to identify the primary sources of inhibition failure during the simultaneous use of a corrosion inhibitor with scale inhibitor, drag reducing agent, and biocides under particular field conditions. Results show that one type of biocide completely rendered the corrosion inhibitor ineffective, while other OFCs had no significant impact on corrosion inhibition. The findings in this study highlight the necessity for chemical compatilibty checks during corrosion inhibitor qualification, or when there is a change in other OFC formulation/application, to ensure proper corrosion protection is maintained. Additional work is ongoing to improve the fundamental understanding of chemical compatibility.