bluuebunny/crossref_metadata_2025_split huggingface dataset:
Project Profitability and the Economics of Sustainable Development
Authors: Agbon I. S. 
Published: December 2007

AbstractIn the past economic models captured economic externalities such as sustainable economic development as additional investments that increased project operational costs. There is a need to internalize investment in sustainable economic development in project profitability models. This paper develops a model that captures economic returns from oil and gas investments from the different perspectives of the four major stakeholders in oil and gas operations. These four major stakeholders are the oil companies, the shareholders, the society and the host communities. The cost of sustainable economic development has different impacts on the financial conditions of each of the stakeholders. Each stakeholder therefore has its unique economic perspective defined by its minimum rate of return and its view of project profitability.The perspective of the oil companies use the cost of borrowing capital as its absolute minimum rate of return while that of the shareholder uses the bank saving rate of return. The absolute minimum rate of return for the society captures the replacement of oil and gas as wasting assets, while that for the host communities encompass the replacement of the income generating capacity lost due to environmental pollution as well as the cost of maintaining the economic regenerative capacity of the environment. The project must be profitable from the unique point of view of each of the major stakeholders for sustainable economic development to occur. Project profitability from the perspective of the host community is the sustainable economic development test.The paper concludes that oil and gas ventures can be screened with the four perspectives profitability model to ensure that they will enhance sustainable economic development understood from the perspective of each of the major stakeholders. Screened investment opportunities that are profitable from the four perspectives can then be ranked on the basis of profitability from the perspective of the oil companies.
Produced Water: Environmental Issues/ Technological Solution of the Nigeria Depletion Era
Authors: Ukpohor T. O. 
Published: December 2007

ABSTRACT
Environmental literatures have been greatly concerned with possible detrimental effect of continued produced water discharged in offshore and onshore areas. While it remains a major policy for the operating companies in Oil production to be environmental friendly in achieving their goal of maximum petroleum exploitation, certain natural phenomenon tends to pull a negative effect on the production of Produced water as an inevitable associate of crude oil.
As the Depletion of crude oil reservoirs in Nigeria becomes more evident by nature of maturing field, the production of Produced water, which varies directly as Depletion will be increasing at almost a geometric rate that effective treatment of this effluent may elude the various Operating companies. With a case study of field F in the Niger Delta, this paper technically reviewed the environmental issues of the pollution effect of Produced Water, inductively analyzed the Depletion Rate of the case study and recommended technological solution to this problem.
Illustratively, a schematic flow diagram relating the technological solution was made, delineating the various option of Produced water Disposal Systems that are within expectable standards, conforming to flora and fauna safety.
e_Business and Asset Teams: A Perspective
Authors: Woolley Thomas C. , Wittstrom Martin D. , Wright Brian J. 
Published: December 2007

Abstract
E-Business initiatives are common today in medium and large size oil companies, and new ones continue to develop as companies identify and review opportunities to use Internet technology to improve their operations and productivity. Opportunities for sustained efficiency gains through the use of electronic commerce and communication solutions offer benefits for all portions of the petroleum value chain. The technical and business problems are often similar and therefore offer leveraging opportunities to port technology and solutions across different sectors of the value chain. The impact on petroleum industry professionals continues to increase as capabilities in the different business sectors continue to grow. Asset Teams, whether they are in the upstream, midstream, or downstream sectors are likely to be active participants in one or more type of business space: Business-to-Consumer (B2C) commerce (e.g. purchasing of data, materials and services); Business-to-Government (B2G) activities (e.g. permitting and acquisition of lease information from government agencies), and Business-to-Business (B2B) commerce (e.g. direct linking of suppliers and business partners to receive products and services to directly link work processes such as AFE approvals).
This paper will discuss some experiences and observations of asset teams relating to e-Business solutions. Examples of these would include improvements in teamwork, productivity, joint venture communication, management information reporting, property acquisition and divestment, and virtual workgroups. Barriers to success, lessons learned and future development predictions will be described.
Methane Hydrates: Major Energy Source for the Future or Wishful Thinking?
Authors: Thomas C. P. 
Published: December 2007

Abstract
Methane hydrates are methane bearing, ice-like materials that occur in abundance in permafrost areas such as on the North Slope of Alaska and Canada and as well as in offshore continental margin environments throughout the world including the Gulf of Mexico and the East and West Coasts of the United States. Methane hydrate accumulations in the United States are currently estimated to be about 200,000 Tcf, which is enormous when compared to the conventional recoverable resource estimate of 2300 Tcf. On a worldwide basis, the estimate is 700,000 Tcf or about two times the total carbon in coal, oil and conventional gas in the world. The enormous size of this resource, if producible to any degree, has significant implications for U.S. and worldwide clean energy supplies and global environmental issues.
Historically the petroleum industry's interests in methane hydrates have primarily been related to safety issues such as wellbore stability while drilling, seafloor stability, platform subsidence, and pipeline plugging. Many questions remain to be answered to determine if any of this potential energy resource is technically and economically viable to produce. Major technical hurdles include: 1) methods to find, characterize, and evaluate the resource; 2) technology to safely and economically produce natural gas from methane hydrate deposits; and 3) safety and seafloor stability issues related to drilling through gas hydrate accumulations to produce conventional oil and gas. The petroleum engineering profession currently deals with gas hydrates in drilling and production operations and will be key to solving the technical and economic problems that must be overcome for methane hydrates to be part of the future energy mix in the world.
Novel Low Dosage Hydrate Inhibitors for Deepwater Operations
Authors: Fu B. , Neff S. , Mat hur A. , Bakeev K. 
Published: December 2007

Abstract
Novel low dosage hydrate inhibitors (LDHI) have been developed for applications in oil and gas fields. The new-generation inhibitors work as kinetic inhibitors that prevent hydrate formation encountered frequently in deepwater operations. These chemicals effectively inhibit hydrate formation regardless of the water cut in the system. They also exhibit a low toxicity that leads to very favorable environmental ratings. Valuable experience has been learned from recent laboratory studies as well as field trials with respect to the application limits and implementation techniques for these new products. The key to the overall success is a full integration of a good front-end design, a comprehensive deployment plan and an effective monitoring program. An overview of the chemistry of these new inhibitors along with their performance under simulated deepwater conditions is briefly discussed. In addition, the effect of LDHI on hydrate formation and the effect of pressure on LDHI performance are addressed.
Development of a Foam Monitor for High Pressure Separators
Authors: Poindexter M. K. , Marsh S. C. , Fransen G. 
Published: December 2007

Abstract
Many deepwater platforms installed in the Gulf of Mexico produce large amounts of both gas and oil. Due to the limited space aboard these vessels, some separation equipment may become undersized particularly when record setting production rates are attempted. Additionally, there is increased activity in adding new subsea production to platforms that are within specified production limits. When the increased throughput arrives, separation equipment can be overloaded. In other instances, the addition of a new well (or wells) to existing production can greatly change the foaming characteristics of the overall composite. If the change is towards more severe foaming, an immediate problem can arise.
The high pressure separator (HPS) is where gas/oil separation begins. It is imperative that efficient separation occurs in the HPS, otherwise performance in downstream vessels will likewise diminish. With enough foaming, the platform can be forced to take an unwanted, and sometimes unexpected, shutdown.
Foaming can often be viewed as a two-fold problem. While foam (or liquid carry-over) takes place through the overhead outlet of the HPS, there is generally simultaneous gas carry-under through the bottom outlet of the separator. This "double problem" can often be observed by watching process gauges (e.g. pressure, flow rate, and level monitors). While these monitors are often useful for detecting foam, they are located either after the HPS or often do not respond quickly to an impending foam situation. To develop an immediate response to separator foaming, a probe was developed to monitor the conditions directly within the HPS. Lab development and field evaluation of a probe capable of handling the high pressure and flow rates of a HPS will be reviewed. Examples of using the probe to assist in selection and optimization of antifoams will also be presented.
New Coreflood Interpretation Method for Relative Permeabilities Based on Direct Processing of In-Situ Saturation Data
Authors: Goodfield M. , Goodyear S. G. , Townsley P. H. 
Published: December 2007

Abstract
Generation of good quality relative permeability data depends on carefully designed core flooding programmes, combined with appropriate interpretation of the laboratory data. Where capillary pressure is important simulation based methods are needed. However, experience shows that the conventional fixed capillary pressure outlet boundary condition may fail to capture the development of the in-situ saturation profiles satisfactorily.
This paper describes a new interpretation approach that fully utilises in-situ saturation data and reduces the sensitivity to boundary condition assumptions. The method extends previously published techniques for interpreting gravity drainage floods by including viscous and capillary forces. Relative permeabilities are calculated directly from in-situ saturation and pressure drop data, without the need to use simulation methods, by applying the Darcy flow equations for the mobile phases at each position and time in the core. Darcy's equations are recast to give separate pressure and fractional flow equations. The fractional flow equation is solved locally, independently of any boundary condition assumptions, and the pressure equation (written in a global integral form) is solved for the mobility. The algorithm is applicable to a wide range of water-oil displacements or gasoil displacements with an immobile initial water saturation, including multi-rate and constant pressure drop unsteady-state floods, steady-state and gravity drainage floods.
The algorithm is applied to synthetic saturation and pressure drop data sets generated using a conventional simulator for a selection of water/oil and gas/oil core floods. The underlying relative permeabilties are correctly constructed, including a significant fraction of the oil relative permeability tail. A range of smoothing methods have been developed to allow the basic algorithm to be successfully applied to datasets in which noise has been added to the basic saturation and pressure profiles generated by simulation.
Physical Effects of WAG Fluids on Carbonate Core Plugs
Authors: Svec R. K. , Grigg R. B. 
Published: December 2007

Abstract
It is a given that carbonate mineral dissolution and deposition occur in a formation in geologic time and are expected to some degree in carbon dioxide (CO2) floods. Water-alternating-gas (WAG) core flood experiments conducted on limestone and dolomite core plugs confirm that these processes can occur over relatively short time periods (hours to days) and in close proximity to each other.
Effect of GOR, Temperature, and Initial Water Saturation on Solution-Gas Drive in Heavy-OIl Reservoirs
Authors: Tang G. , Firoozabadi A. 
Published: December 2007

Abstract
We have carried out an extensive set of tests on solution-gas drive for a heavy oil to study the effects of initial water saturation, temperature, and gas-oil-ratio (GOR). The viscosity and the API gravity of the stock tank oil from Hamaca field (in Venezulela) used in our tests are 560,000 cp (at 24°C) and 8.7, respectively. The solution-gas drive tests were conducted using live oils with GOR of 6.5, 9.0, and 12.2 (vol/vol at standard conditions). In two tests, initial water saturations of 4.0 and 5.2% were established. Five tests were conducted at a temperature of 35°C; one test was conducted at 46°C. The duration for each test was around three months. Based on the results from all the tests the following conclusions can be drawn. Initial water saturation reduces gas-bubble density. The recovery efficiency decreases due to increase in gas mobility with increase in initial water saturation. As the temperature increases from 35 to 46°C, the gas relative permeability increases one order of magnitude; as a result there is reduction in recovery efficiency. The temperature effect on recovery is in agreement with our previous work with temperature increase from 24 to 35°C. Increase in solution GOR has a significant effect on gas-bubble nucleation; there is a systematic increase of the critical gas saturation with GOR increase. For all the tests conducted, the oil recovery by solution gas drive at test termination was about 16 percent and higher.
Experimental and Theoretical Assessment of Using Propane to Remediate Liquid Buildup in Condensate Reservoirs
Authors: Jamaluddin A. K. M. , Ye S. , Thomas J. , D'Cruz D. , Nighswander J. 
Published: December 2007

AbstractThis paper presents the results of an assessment of condensate phase behavior issues in the near-wellbore region. Constant composition expansion (CCE) studies were conducted to measure the retrograde liquid deposit data for a real reservoir fluid. Subsequently, the effect of adding light hydrocarbon gases on the vaporization of condensed liquid was studied. An equation of state (EOS) model was developed based on the measured data and was used to evaluate the experimentally observed phase behavior characteristics of the condensate fluid. Results indicate that although carbon dioxide can influence the liquid extraction properties of the condensate wellstream to some extent, the use of propane allows the system conditions to be supercritical conditions for most typical reservoir fluids at reservoir temperature and pressure. This allows for an enhanced liquid extraction capability, which subsequently improves wellbore extraction.
An Integrated Electric Flow-control System Installed in the F-22 Wytch Farm Well
Authors: Tourillon V. , Randall E. R. , Kennedy B. 
Published: December 2007

Abstract
The increased complexity of hydraulic and complex electrohydraulic flow-control systems, especially with multizone completions, substantially increases deployment risk. Until now it has not been possible to provide an infinitely variable flow-control system for multiple zones using only a single conduit from surface.
The BP Wytch Farm F-22 well has an all-electric tubing-retrievable flow-control device installed as the primary active downhole component in the intelligent completion system. This device integrates an electromechanical adjustable choke, multiple quartz pressure and/or temperature sensors, and a mass-flow sensor, all powered from the surface through one permanent downhole cable. Multiple flow-control devices can be run on the same cable to provide zonal control and monitoring. Each device is independently addressable, allowing the operator to adjust any zone in the well on command and react to potential reservoir uncertainties in real time. The presence of an electric pump cable near the permanent downhole cable at the Wytch Farm installation has demonstrated that the communication system working on a twisted pair cable is immune to noise.
The fully electrical system can establish a secure link between multiple downhole sensing and flow-control components, the surface acquisition system, and remote control locations where reservoir engineers and production specialists can monitor and control well operations. Infinitely variable flow control coupled with real-time monitoring and data transmission will facilitate and accelerate the development of subsea, deepwater, and other hostile location wells by eliminating the need for surface or close infrastructure.
Kinetic of Hydrates Formation: Influence of Crude Oils
Authors: Sinquin A. , Bredzinsky X. , Beunat V. 
Published: December 2007

Abstract
As deepwater offshore production is widely developing, the problem of flow assurance becomes of major importance. Among the problems that can be encountered, flow lines plugging by hydrates is particularly dread. The kinetic of hydrate's formation is greatly influenced by the nature of the crude oil produced and the management of hydrate's problems could be quite different from one field to another.
We have studied the kinetic of hydrate's formation using four different liquid hydrocarbon phases: a condensate, a paraffinic and two asphaltenic crude oils. The kinetic of hydrate's formation has been studied in a semi-batch stirred reactor. Experiments have been carried out in presence of these liquid hydrocarbon phases, at a constant pressure by decreasing temperature. The induction time, the quantity of hydrates formed and their rate of formation have been determined at different water cuts.
Two types of kinetic behavior have been found: the condensate and the paraffinic crude show very violent and rapid hydrate's formation, while hydrate's formation with the asphaltenic oils is delayed and the crystallization is very smooth.
The influence of the liquid hydrocarbon's composition (paraffin content, WAT, asphaltene's solubility…) has been explored. The effects of the water cut and of liquid hydrocarbon's viscosity have been also studied. Among these, the most relevant parameters having an important effect on the kinetic of hydrate's formation have been pointed out.
This work highlighted the importance of the nature of the liquid hydrocarbon phase on the kinetic of hydrate's formation. Specific studies on the influence of the hydrocarbon phase can give precious information for hydrate's management problems in deepwater offshore development.
A Tale of Two Trees: Flow Assurance Challenges for Wet Tree and Dry Tree Systems in Ultradeepwater
Authors: Golczynski T. S. , Niesen V. G. 
Published: December 2007

Abstract
As oil and gas exploration moves into deeper waters offshore, flow assurance challenges become more prevalent and system design must address these issues from a fresh perspective. In addition to structural and economic issues, the decision to employ either a wet tree (subsea) or dry tree solution needs to especially consider the flow assurance aspects that ultradeepwater production presents. The riser, rather than the flowline, will now dominate the overall hydraulic and thermodynamic performance of the system. An increased liquid column height in the riser, a greater potential energy change, and an enhanced Joule-Thomson effect will all contribute to significant temperature and pressure drops for an ultradeepwater riser, relative to its shallow water counterpart.
Dry trees are traditionally perceived as having less severe flow assurance issues than subsea tiebacks, primarily because of easier access to the tubing string if wax or hydrates are formed. However, aside from significant temperature losses in the riser, dry trees in ultradeepwater are particularly susceptible to hydrate formation upon shutdown. Because of warmer seabed temperatures and lower reservoir pressures, shallow water dry tree risers can provide adequate cooldown times with only minimal insulation. For ultradeepwater developments, the same shallow water dry tree design can fall into the hydrate formation region within two to three hours.
For both the dry tree and wet tree riser systems, it may not be possible to depressurize the system below hydrate formation conditions without gas lift (which may not be available for an emergency shutdown). The focus of this discussion is to evaluate the merits and drawbacks for both wet and dry tree systems from a flow assurance standpoint in ultradeepwater.
A Systematic Approach in Deepwater Flow Assurance Fluid Characterization
Authors: Jamaluddin A. K. M. , Nighswander J. , Joshi N. 
Published: December 2007

Abstract
The potential for hydrocarbon solid formation and deposition adversely affecting flow assurance in deepwater production systems is a key risk factor in assessing deepwater developments. To reduce this risk, a systematic approach to defining and understanding the thermodynamic and hydrodynamic factors impacting flow assurance is required. The development of experimental and simulation techniques to provide this information are a current focus of attention in the reservoir fluid phase behavior community. This paper provides a case study of the various aspects of a state of the art laboratory and simulation assessment for a Gulf of Mexico reservoir crude. The case study illustrates the application of a systematic approach to characterization of the crude and the impact of this knowledge on potential production and flow assurance strategies.