bluuebunny/crossref_metadata_2025_split huggingface dataset:
Options, Methods, and Costs for Offsite Commercial Disposal of Oil and Gas Exploration and Production Wastes
Authors: Puder M. G. , Veil J. A. 
Published: July 2008

Summary
In the United States, most exploration and production (E&P) wastes generated at onshore oil and gas wells—contaminated soils, naturally occurring radioactive material (NORM), oil-based muds and cuttings, produced water, tank bottoms, and water-based muds and cuttings—are disposed of or otherwise managed at the well site. Some of these E&P wastes, however, are not suitable for onsite management, and some well locations in sensitive environments cannot be used for onsite management. In these situations, operators must find offsite waste-disposal solutions. Responding to this need, offsite commercial disposal facilities are businesses that charge a fee for accepting and managing E&P wastes generated by others.
Funded by the U.S. Department of Energy (USDOE), the authors of this paper assembled a unique set of data covering options, methods, and costs for offsite disposal of E&P wastes in the United States (Puder and Veil 2006a). Data were collected for more than 200 disposal facilities. This paper describes the project and the findings, which were published in September 2006.
Operating Experience With the Split MR Machinery Configuration of the C3MR LNG Process
Authors: Brimm A. , Ghosh S. , Hawrysz D. J. 
Published: July 2008

Summary
Efficiency and economics have motivated RasGas Trains 3 through 5 to implement a novel compressor-driver arrangement comprising both propane and mixed-refrigerant (MR) compressors on a single shaft. One Frame 7E gas turbine drives the low-pressure (LP) and medium-pressure (MP) MR compressors, while a second Frame 7E drives the propane and high-pressure (HP) MR machines. With minor control system adjustments after startup, the refrigerant compressors in RasGas Train 3 are operating reliably.
Flexible Treatment Program for Controlling H2S in FPSO Produced-Water Tanks
Authors: Burger E. D. , Andrade C. A. , Rebelo M. , Ribeiro R. 
Published: July 2008

Summary
Tanks used to store produced water on floating production, storage, and offloading units (FPSOs) are extremely susceptible to generation of high hydrogen sulfide (H2S) levels because of the activity of sulfate-reducing bacteria (SRB). The FPSOs operated by Petrobras in the Campos basin, offshore Brazil, all contain slop-water tanks, while some also have upstream oil/waterseparation tankage. Slop water, including produced water, ballast water from oil cargo ships, and deck water, contains SRB and their nutrients required for generating H2S. Additionally, solids accumulations at the tank bottoms provide an excellent environment for microbial growth.
A 2002 field trial on an FPSO confirmed the viability of combined batch treatments using anthraquinone (AQ) and a THPS blend and their effectiveness in controlling H2S biogeneration better than previous treatment programs. AQ, a nontoxic SRB inhibitor, and tetrakishydroxymethyl phosphonium sulfate proprietary blend (THPS), an oilfield biocide, act synergistically to provide effective control of H2S biogeneration in this environment. The combined-chemical treatment strategy has now been implemented successfully on six Petrobras FPSOs. Flexibility has been important in developing the treatment programs because operating parameters are different for each FPSO and change with increased water-production rates. Options include the ability to inject the chemicals continuously or batchwise at different locations and to alter the volumes and ratios of chemicals for optimizing control over H2S and corrosion.
This paper describes the individual FPSO water-flow and water-storage systems and discusses the customized chemical treatment programs. Included are field H2S data showing the evolution of the programs as they are being continually adjusted to optimize control of H2S generation and cost-effectiveness. Also included are results of laboratory microbial studies showing the synergy of anthraquinone and THPS and of corrosion studies that have impacted the direction of usage of these chemicals.
With more than 100 FPSOs operating worldwide, the treatment program described can significantly affect the safety and environmental aspects of processing water containing SRB.
Reducing Incidents in Marine Personnel Transfer
Authors: Strong Philip A. 
Published: July 2008

Summary
Millions of crew transfers take place each year, and whether they are by boat or helicopter, this remains one of the most high-risk activities in offshore operations. Although the safety of crane transfers compares favorably with other methods of crew supply, incidents and associated litigations are not infrequent.
Why does such an apparently simple operation go wrong? One reason is a lack of recognition of the true risks. Operators go to great lengths to improve the safety of helicopter operations, while marine transfers rarely get a second thought. The underlying objective, however, remains the same: to move personnel to and from their place of work in a safe, cost-effective, and reliable manner.
This paper looks at the real risks, the root causes, of recorded incidents and outlines how transfers can be made safer. Risk can be managed in two ways:
Engineered protection. A modern car provides a secure environment that can protect passengers from impacts. A transfer device can do the same and guard against the inevitable human factors that contribute to the majority of incidents. Improved operational control. Procedures, pre-lift planning, communications, and training can all play a significant role in reducing risk.
The paper also describes how analysis of past incidents led to the development of improved equipment and operating practices. Considerable focus was given to human factors to prevent minor misjudgments, for example by a crane operator or a vessel skipper, leading to serious incidents.
After 10 years working with enhanced systems and after millions of safe transfers, the author explains why serious transfer incidents are not an inevitable feature of offshore life. Modest investments and changes in operational practices have provided many operators with a dual benefit of safer operations and reduced downtime.
Finally, the author takes a look at the future of offshore crew supply, providing details of a groundbreaking new project that will utilize a state-of-the-art high-speed catamaran and newly developed transfer system. This will be the first time that a vessel and transfer system have been custom-built to provide swift, comfortable, and safe transfers to offshore installations. The system, developed for the new Crewzer Class of vessel, is due to be commissioned in the Gulf of Mexico in late 2007.
Pipe/Soil Interaction Behavior During Lateral Buckling
Authors: Bruton D. , White D. , Cheuk C. , Bolton M. , Carr M. 
Published: July 2008

This paper addresses lateral pipe/soil interaction behavior at the large displacements that occur with lateral buckling of a pipeline. Force-displacement-response models were developed by the Safe-buck joint-industry project (JIP) to replace the use of simple friction-coefficient approximations. Such simplistic models are unrealistic for modeling large lateral displacements or the building of soil berms that occurs with cyclic lateral loading.
The models are based on large- and small-scale tests carried out by the Safebuck JIP on deepwater soils from the Gulf of Mexico and west Africa, as well as on kaolin clay. To this database was added project-specific test data donated by JIP participants.
Four stages of pipe/soil interaction are considered:
Embedment of the pipe at installation. Breakout during buckle formation on the basis of different levels of initial pipe embedment. Large-amplitude lateral displacement as the buckle forms. Cyclic lateral displacement influenced by the building of soil berms.
While breakout loads have been the subject of much research and published papers on pipeline stability, there is little guidance on modeling lateral resistance at the large displacements experienced in lateral buckling. There is also little guidance on modeling subsequent large-amplitude cyclic behavior, which occurs with each shutdown and restart of the pipeline.
New equations were proposed where appropriate, and recommended models for each part of the characteristic response were developed. These models provide a valuable basis for lateral-buckling design guidance. They currently are being applied by JIP participants on a number of projects in which pipelines are being designed for lateral buckling.

Background of the Safebuck JIP
The aim of the Safebuck JIP (Bruton et al. 2005) is to raise confidence in the lateral-buckling-design approach and to improve understanding of the related phenomenon of pipeline walking. Experimental work is being undertaken at the Welding Inst. on low-cycle fatigue-materials performance and at Cambridge U. on axial- and lateral-pipe/soil interaction.
The JIP has been very well supported by the offshore industry. BP, ConocoPhillips, ExxonMobil, Petrobras, and Shell, as well as the U.S. Government through the Minerals Management Services, participated in Phase I, with installation contractors and suppliers represented by Allseas, JFE-Metal One, Technip, and Tenaris. Additional participants including Acergy, Chevron, Statoil, and Saipem have joined Phase II, which will run through 2005 and 2006.
Mercury Monitoring and Removal at Gas-Processing Facilities: Case Study of Salam Gas Plant
Authors: El Ela M. Abu , Mahgoub I. S. , Nabawi M. H. , Azim M. Abdel 
Published: July 2008

Summary
Presence of mercury in natural gas can cause catastrophic failures of aluminum heat exchangers in gas-processing plants. In addition, the release of mercury can have serious health and environmental consequences. Recently, a number of methods for detecting mercury content in natural gas have been developed, and several techniques to remove mercury from the gas stream have been investigated.
Khalda Petroleum Company, an international joint venture company in Egypt, has recently found mercury as a naturally occurring component of hydrocarbons in the Egyptian Western Desert. Since then, Khalda Petroleum Company has concentrated on measuring and removing the mercury from its produced gas. A mercury removal unit was installed at the Salam gas-processing plant. The mercury contents of the gas at the inlet and outlet of the Salam mercury removal unit have been continuously monitored.
This paper gives a short overview of the biochemical effects of mercury, the corrosion mechanism of mercury and aluminum, analysis techniques for mercury in natural gas, and mercury removal techniques from natural gas. It also covers process design, field-analysis procedures, and the performance of Salam mercury removal unit.
Offshore LNG Technology: A Comparative Study of Conventional and Futuristic Salt-Cavern-Based LNG Receiving Terminals
Authors: Rai Sanchit 
Published: July 2008

Summary
Tight oil supplies, escalating oil prices, and towering energy demands have led to the revival of natural gas. It is now deemed to be the potential fuel of the near future. The trend now is toward supplying every cubic foot of inland and offshore natural gas to energy-hungry consumers. Liquefied natural gas (LNG) is recognized as the best form of gas transfer from remote inland and offshore fields to consumers around the world.
The natural gas is liquefied and shipped to distant receiving terminals. The main technical features of a conventional terminal facility include LNG carrier mooring systems, unloading facilities, cryogenic LNG storage tanks, LNG regasification systems, and gas send-out systems. The United States has five such conventional terminals and is the world's largest gas market, with gas demands expected to double by 2020. This demand is leading to the expansion and refurbishment of these conventional LNG receiving terminals, with the construction of several more in various phases of planning and development. In 2005, the US Department of Energy (DOE), along with 30 energy industry players, successfully completed a research study on the concept of an offshore facility to moor LNG carriers and unload and store LNG. This concept includes storing gas in salt caverns. This technology is claimed to be highly cost-effective and process-efficient, with better delivery capacity and security than other options. This idea is being implemented through the construction of such a modern LNG receiving terminal in offshore Louisiana.
Apart from the United States, LNG also offers great promise to such countries as Brazil, China, the United Kingdom, Mexico, Germany, and France. These countries are also contemplating LNG facilities development and upgrading.
This paper aims to present a qualitative comparison between conventional and futuristic salt-cavern-based LNG receiving terminals. The comparison is based on the use of technology for these terminals. This approach will be ultimately useful in understanding the technology implementation required for the development and modernization of LNG receiving facilities in such countries.
Economic Modeling of an Oil and Gas Project Involving Carbon Capture and Storage: Snøhvit LNG Field (Barents Sea, Norway)
Authors: Negrescu Matei 
Published: July 2008

Summary
The Snøhvit Liquefied Natural Gas (LNG) project developed by StatoilHydro and partners in Norway is used as an example to describe how the carbon capture and storage (CCS) component of an oil and gas project can be isolated, modeled, and analyzed from an economic point of view. The Snøhvit development, which started production in late 2007, involved a CCS component from day one. Approximately 700,000 tons of CO2 captured from the liquefaction plant will be reinjected every year in an underground formation offshore. Furthermore, there are interesting alternatives for CO2 capture from the on-site power plant and for the use of CO2 for enhanced oil recovery (EOR) in a nearby oilfield, leading to several future development scenarios for CCS at Snøhvit.
Different development scenarios for CCS are analyzed to select the best development option. The economic modeling framework will also be used to assess the impact of the uncertainties on the project economics.
The analysis identifies that a key driver for the profitability of the project is the legislative setting for CCS. The involvement of the government is very important for the viability of the project, which needs a strong incentive, such as the current CO2 tax scheme or an emission trading scheme with strict allocation of emission targets. Under such conditions, a CCS project such as Snøhvit becomes a win-win situation: economically profitable for the operator and environmentally friendly.
From a broader perspective, addressing the economic and legislative uncertainty currently surrounding CCS projects for the oil and gas industry is crucial because this represents the main limiting factor for the further development of such projects. It is therefore essential that economic modeling tools such as the framework described in the present work become industry standards to ensure that projects which could be profitable for both the operator and the environment are not abandoned by pure lack of analysis ability.
Oil Fallout in the Vicinity of an Onshore Blowout: Observations on a Field Case
Authors: Oudeman P. 
Published: July 2008

Summary
Oil deposition in the area surrounding a blowout is one of the most visible consequences of the loss of control over well flow. Less visible, but equally serious, are the short- to medium-term effects of oil coverage on the environment. Apart from the direct damage, studies indicate effects (e.g., reduced tree growth) that persist many years following the incident.
Hence, oil fallout, in the case of loss of well control, is a factor to be taken into account in decisions on well locations, emergency procedures, contingency planning, etc. This requires an estimate of the area around the well likely to be affected by oil fallout, given the geomorphology of the terrain, prevailing winds, and expected outflow conditions. Models to obtain such an estimate have been proposed, but application of these models (e.g., for environmental impact assessment) has been limited. In part, this limitation can be attributed to a lack of validation of the models because this requires a combination of well-effluent data, outflow conditions, meteorological data, a detailed terrain description, and fallout maps.
For the field case discussed in this paper, all the data necessary for validation were assembled from various sources ranging from the well operator and environmental agencies to meteorological and cartographic institutes. The relation between the observed pattern of oil deposition around the well and factors such as outflow conditions and wind speed and direction is analyzed with a simple model. This relationship demonstrates that the main factors determining the area affected by deposition of oil are the outflow conditions and the wind direction.
To verify this result, a comparison with historical observations on oil fallout around gushers has been made. Although more sketchy, the same patterns emerge from this comparison, which strongly suggests that the methods developed to explain the fallout pattern of the field case discussed can be used over a wide range of conditions to predict the area affected by a blowout. This prediction can serve several purposes, such as site selection, definition of emergency procedures, environmental impact assessment, and contingency planning. Finally, it is noted that this method also applies in less dramatic situations (e.g., predicting droplet deposition around vent stacks).
Optimizer's Curse: Removing the Effect of This Bias in Portfolio Planning
Authors: Schuyler John , Nieman Timothy 
Published: July 2008

Summary
Even with unbiased judgments and project calculations, an insidious bias will still be present in an approved projects portfolio. The screening and ranking process used to select projects causes an optimizer's curse (OC) effect (Smith and Winkler 2006). A portfolio's true outcome value will tend to fall below the forecast distribution mean. Stated another way, we should expect to be disappointed in the value of the eventual outcomes. This optimizer's curse effect can be huge: the true portfolio value might be half its forecast value when forecast in the usual way.
This paper describes a correction process based upon Bayesian inversion obtained with Monte Carlo simulation. Estimate/Actual distributions characterize component evaluation errors. The mean and standard deviation of the E/A distribution measures the quality of judgments and estimates. Examples demonstrate the value of better information in project or asset evaluation, portfolio optimization, and competitive bidding.
The premise of our approach to correct for optimizer's curse is straightforward enough, though implementing this method requires judging the population of evaluated projects—or at least assessing the shape of this population's distribution. We offer a process and guidelines for correcting for the optimizer's curse in both project and portfolio value calculations. Correcting estimates for systematic biases restores luster to the recommended expected value-maximizing decision policy. We also tie back to the winner's curse phenomenon (Capen et al. 1971) experienced in competitive bidding and how it affects bid optimization.
Rapid and Low-Cost Methodology to Obtain an Updated Compositional Model of Produced Fluids Using Separator-Discharge Data Analysis
Authors: Morales Fernando L. , Velázquez Juan Cruz , Hernandez Aaron Garrido 
Published: July 2008

Summary
Fluid-characterization data used to build representative reservoir fluid models for reservoir and production engineering are generally scarce and very costly because of the expense of fluid sampling and analysis and operational related problems of well intervention. The problem turns more dramatic when the field to be studied has been producing for some time and its bottomhole pressure has reached the bubblepoint. In those cases, initial reservoir fluid data is more difficult to be used because some portion of the hydrocarbon's heaviest or lightest components, whether oil or gas is produced, may have been left in the reservoir and initial PVT data are no longer valid or very difficult to match to current fluid behavior.
One of the most common practices of obtaining fluid data is by taking well bottomhole samples, or by obtaining surface oil and gas mixture samples, and analyzing them in the lab using recombined methods. Because of the costs involved, including loss of time and production, operating companies do not obtain fluid data with the required frequency. Accordingly, engineers are left with the only option of using nonupdated or insufficient data that will affect the outcome of their simulation studies.
This work describes a rapid and low-cost methodology to obtain an updated compositional model for produced fluids using gas chromatography, oil characterization, and GOR from analysis of the separator fluid discharge. The required samples are easily collected with low cost to the operating company.
Then, a case history is shown wherein compositional fluid models obtained with the proposed method are used in well, surface-network, and process-facility simulation models, with excellent results. A comparison of field data against the simulation model results is also shown.
Offshore Natural Gas Liquefaction Process and Development Issues
Authors: Wood David , Mokhatab Saeid , Economides Michael J. 
Published: July 2008

Summary
Liquefied natural gas (LNG) has yet to be deployed in the development of offshore fields in spite of several detailed studies completed and offshore technology development demonstrating its technical feasibility. The perceived risks associated with deploying unproven technology in a high construction cost and volatrile gas price environment have so far inhibited offshore liquefaction projects. The potential deployment of such technologies is of paramount importance considering the massive volumes of natural gas currently deemed as "stranded" and the exploitation of which is compelling not only because of the inherent economic benefit but also because of the otherwise adverse impact on oil production. It is conceivable that deep water offshore locations may contain quantities of natural gas rivalling those of onshore locations. Such a statement cannot even be confirmed because drilling for offshore natural gas reservoirs, expected to be found considerably deeper than oil reservoirs, has been unattractive exactly because of the absence of coherent exploitation strategies. If anything, the mere presence of large natural gas deposits even in the form of solution gas in oil is now often considered as largely undesirable because of the cost of just handling non-monetized natural gas. This paper discusses potential offshore LNG processes and reviews natural gas liquefaction cycles in the context of compactness, ease of operation, process safety, and efficiency.
Particular attention is paid to the lower-efficiency turboexpander processes for plant capacities up to 3 million tonnes per annum (MTPA, approximately 0.43 Bcf/d). These cycles offer several advantages over the alternative optimized cascade and mixed refrigerant (MR) liquefiers for offshore applications.