Publications

Abstract not provided.

Two mitigation strategies including the use of corrosion resistant alloys (CRA) for the tubing and the application of a corrosion inhibitor and anti-fouling package in the water were used in the laboratory simulation of corrosion in large oil coolers at US Strategic Petroleum Reserve. A closed-loop, recirculating system was designed and constructed. The corrosion sensors were monitored over time using a commercially available linear polarization resistance (LPR) meter. The ERW steel exhibited significant localized attack along the entire weld root, in addition to pitting along the rest of the surface, as observed on the seamless tubing.

Abstract not provided.

The goal of this study was to first establish the fitness for service of the carbon steel based oil coolers presently located at the Bryan Mound and West Hackberry sites, and second, to compare quantitatively the performance of two proposed corrosion mitigation strategies. To address these goals, a series of flow loops were constructed to simulate the conditions present within the oil coolers allowing the performance of each corrosion mitigation strategy, as well as the baseline performance of the existing systems, to be assessed. As prior experimentation had indicated that the corrosion and fouling was relatively uniform within the oil coolers, the hot and cold side of the system were simulated, representing the extremes of temperature observed within a typical oil cooler. Upon completion of the experiment, the depth of localized attack observed on carbon steel was such that perforation of the tube walls would likely result within a 180 day drawdown procedure at West Hackberry. Furthermore, considering the average rate of wall recession (from LPR measurements), combined with the extensive localized attack (pitting) which occurred in both environments, the tubing wall thickness remaining after 180 days would be less than that required to contain the operating pressures of the oil coolers for both sites. Finally, the inhibitor package, while it did reduce the measured corrosion rate in the case of the West Hackberry solutions, did not provide a sufficient reduction in the observed attack to justify its use.

The intrusion of gas into oils stored within the SPR has been examined. When oil is stored in domal salts, gases intrude into the stored oil from the surrounding salt. Aspects of the mechanism of gas intrusion have been examined. In all cases, this gas intrusion results in increases in the oil vapor pressure. Data that have been gathered from 1993 to August 2002 are presented to show the resultant increases in bubble-point pressure on a cavern-by-cavern as well as on a stream basis. The measurement techniques are presented with particular emphasis on the TVP 95. Data analysis methods are presented to show the methods required to obtain recombined cavern oil compositions. Gas-oil ratios are also computed from the data and are presented on a cavern-by-cavern and stream basis. The observed increases in bubble-point pressure and gas-oil ratio are further statistically analyzed to allow data interpretation. Emissions plume modeling is used to determine adherence to state air regulations. Gas intrusion is observed to be variable among the sites and within each dome. Gas intrusions at Bryan Mound and Big Hill have resulted in the largest increases in bubble-point pressure for the Strategic Petroleum Reserve (SPR). The streams at Bayou Choctaw and West Hackberry show minimal bubble-point pressure increases. Emissions plume modeling, using the state mandated ISCST code, of oil storage tanks showed that virtually no gas may be released when H2S standards are considered. DOE plans to scavenge H{sub 2}S to comply with the very tight standards on this gas. With the assumption of scavenging, benzene releases become the next most controlling factor. Model results show that a GOR of 0.6 SCF/BBL may be emissions that are within standards. Employing the benzene gas release standard will significantly improve oil deliverability. New plume modeling using the computational fluid dynamics code, FLUENT, is addressing limitations of the state mandated ISCST model.

This paper describes three experiments whose purpose is to determine the amount of retained oil on massive salt surfaces and in crushed salt in the presence of water and brine. These experiments have application to the decommissioning process for the Weeks Island mine. In the first experiment, oil-coated salt cores were immersed in either fresh water or in 85% brine. In the case of both fluids, the oil was completely removed from the cores within several hours. In the second experiment, oil-coated salt pieces were suspended in air and the oil was allowed to drain. The weight of retained oil clinging to the salt was determined. This experiment was used to estimate the total amount of oil clinging to the roofs of the mine. The total amount of oil clinging to the roofs of the mine is estimated to be between 240 and 400 m3 (1500 and 2500 BBL). In the third experiment, a pan of oil-soaked crushed salt was immersed in 85% brine, and oil removal from the salt was monitored as a function of time. At the start of the experiment, prior to immersion, 16% of the bulk volume of the crushed salt was determined to be interstitial oil. After the pan of crushed salt was immersed in 85% brine, 80% of the oil, which had been in the interstitial spaces of the crushed salt, immediately floated to the surface of the brine. This oil was not bound and was immediately released. During the next 380 hours, oil continued to separate from the salt and the rate of transfer was governed by a mass-transfer rate limitation.

The conditions and occurrence of gas in crude oil stored in Strategic Petroleum Reserve, SPR, caverns is characterized in this report. Many caverns in the SPR show that gas has intruded into the oil from the surrounding salt dome. Historical evidence and the analyses presented here suggest that gas will continue to intrude into many SPR caverns in the future. In considering why only some caverns contain gas, it is concluded that the naturally occurring spatial variability in salt permeability can explain the range of gas content measured in SPR caverns. Further, it is not possible to make a one-to-one correlation between specific geologic phenomena and the occurrence of gas in salt caverns. However, gas is concluded to be petrogenic in origin. Consequently, attempts have been made to associate the occurrence of gas with salt inhomogeneities including anomalies and other structural features. Two scenarios for actual gas intrusion into caverns were investigated for consistency with existing information. These scenarios are gas release during leaching and gas permeation through salt. Of these mechanisms, the greater consistency comes from the belief that gas permeates to caverns through the salt. A review of historical operating data for five Bryan Mound caverns loosely supports the hypothesis that higher operating pressures reduce gas intrusion into caverns. This conclusion supports a permeability intrusion mechanism. Further, it provides justification for operating the caverns near maximum operating pressure to minimize gas intrusion. Historical gas intrusion rates and estimates of future gas intrusion are given for all caverns.

The prediction of the chemical alteration of cementitious sealing materials and other cementitious components such as liners in the tuffaceous environment of Yucca Mountain is an essential element in understanding the longevity of these materials. This study uses a chemical equilibrium model to obtain information about the chemical reaction of ground water with concretes. Because concretes, cements, and grouts are metastable assemblages, it is expected that these materials will dissolve, cause secondary precipitations and react with the environment. These reactions will alter the porosity and hydraulic conductivity of the concretes. While the importance of these chemical and conductivity changes has not been completely assessed, this study provides insight into the importance of this chemical alteration.

The geochemical modeling codes EQ3NR/EQ6 were used to model the interaction of cementitious materials with ground water from the Yucca Mountain proposed nuclear waste repository site in Nevada. This paper presents a preliminary estimate of the compositional changes caused by these interactions in the ground water and in the cement-based compounds proposed for use as sealing and shaft liner materials at the Yucca Mountain site. The geochemical speciation/solubility/reaction path codes EQ3NR/EQ6 were used to model the interaction of cementitious materials and water. Interaction of water with a cementitious material will result in dissolution of certain cement phases and changes in the water chemistry. These changes in the water chemistry may further lead to the precipitation of minerals either in the concrete or in the surrounding tuff at the Yucca Mountain Site (YMS). As part of a larger scoping study, a range of water, cement, and tuff compositions, temperatures, and reaction path modes were used. This paper presents a subset of that study by considering the interaction of three different cement formulations at 25{degree}C with J-13 water using the ``closed`` reaction path mode. This subset was chosen as a base case to answer important questions in selecting the compositions of cementitious materials for use in the proposed repository. 8 refs., 1 fig., 3 tabs.