bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Software for Opex Estimation: Cost Driver Estimation (Code) Tool With Montecarlo Risk Analysis Simulation
Authors: Boccardi A.. , Giubileo A.. , Cadegiani C.. 
Published: July 2010

Abstract
CODE tool is a software built by Eni used to calculate both on and off-shore production plants OPEX estimation during the project development and operations phases. The tool from a database used as reference baseline, through specific algorithm give as output the estimation of the all life cost structured coherent with the Activity Based Costing Methodology.
The application is divided into:a database for the technical data and the unit costs subdivided by countries;an environment for plant construction;an environment for the definition of the country coefficients and the project parameters;a section dedicated to the visualization and analysis of the results.
The user defines, through a series of interface dedicated, all the parameters and the configuration of the project, including the type of process, production forecast, fluids, plants, contract strategy, transportation costs and logistics strategy.
The software could be interfaced with other applications for the dynamic management of the operating costs in the production phase, supplying, on the predictive base, the initial input of the data and utilizing the successive data processed as feedback for baseline updating.
At the end, in order to evaluate the uncertainties and to monitor the more sensitive parameters the obtained results have been modeled through a Montecarlo risk analysis simulation.
An Integration Approach for Evaluating Well Deliverability in Ultra Deep Sands
Authors: Xiao Guo , Jingjing Ma , Yiwei Chen , Weixin Liu 
Published: July 2010

Abstract
Deep and ultra deep low-permeability reservoirs are widely distributed in the South China Sea, such as HuiZhou 19–1, 26–3, 9–2 oil field and PanYu 34 gas field. These ultra deep reservoirs generally performed as deep burial depth, low porosity, low permeability, which lead to difficulty in evaluating well deliverability. DST is a fast and valid well test method for deep sands. The DST showed that layer M-31 of well HuiZhou 19–1 had a relatively higher productivity. However, the layer M-32 with the same perforated thickness only produced about 1.6 m3 each day. While the layer M-32 and M-31 has a vertical distance of about 25m and similar porosity and permeability. In order to evaluate well deliverability of layer M-32 and M-31, effect of mineral components and pore structure on DST was analyzed. 13 groups of start-up pressure and 13 groups of stress-sensitive experiments were also carried out. This work indicated kaolin clay in the soil minerals of layer M-32 damaged the formation and had an important impact on well deliverability from DST. In addition, layer M-32 offered an relatively high start-up pressure gradient, which reached the magnetite of 10–1 to 10–2. When effective stress was more than 15 MPa, the porous media would begin to deform seriously. The integrated approach indicated optimized production of the layer M-31 and layer M-32 of well are 2413.1 m3/d and 86.39 m3/d respectively. Numerical simulation also showed that enlarging producing pressure drop, hydraulic fracturing and horizontal wells can further improve well deliverability of deep and ultra deep low-permeability reservoirs. The study also suggested effect of kaolin clay and start-up pressure gradient on DST should be considered correctly.
Optimization of Carbon Dioxide Sequestration and Enhanced Oil Recovery in Oil Reservoir
Authors: Jahangiri Hamid Reza , Zhang Dongxiao 
Published: July 2010

Abstract
Carbon dioxide (CO2) storage into depleted or partially depleted oil reservoirs is an immediate option for reducing CO2 emissions into the atmosphere. This process, if implemented in depleted oil reservoirs, combines environmental benefits of reducing CO2 emissions and economical benefits of maximizing oil recovery. CO2 Enhanced Oil Recovery (EOR) processes, to date, have attempted to minimize the amount of CO2 needed to recover each barrel of oil. For a sequestration process, however, the aim is to maximize the amount of CO2 stored. If CO2 emissions are regulated, CO2-EOR process may therefore be able to earn sequestration credits in addition to oil revenues.
This paper discusses the effects of several injection strategies and injection timing on optimization of oil recovery and CO2 storage capacity for a synthetic, three dimensional, heterogeneous reservoir models. A simulation study was completed using a 3-D compositional simulator &#x93;ECLIPSE 300&#x94; in order to optimize oil recovery and CO2 storage. The study proceeded through the following steps: 1) comparison of different injection schemes; 2) testing the effect of injection rate on the CO2 storage capacity. The results show that innovative reservoir engineering techniques are required for cooptimizing CO2 storage and oil recovery.
Feasibility Investigation of CO2 Miscible Flooding in South Slattery Minnelusa Reservoir, Wyoming
Authors: Gao P. , Towler B. , Jiang H. 
Published: July 2010

Abstract
A study using experiment and full-field reservoir modeling investigated and optimized the design of a CO2 miscible flooding project for the Minnelusa reservoir of the South Slattery field. The study began with extensive data gathering in the field and building a full-field three-dimensional geologic model. A fullfield simulation model with relatively coarse gridding was subsequently built and used to history match the depletion and waterflood. This history matching model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. The estimation of minimum miscibility pressure was conducted with the slimtube method. A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood. Continuous CO2 miscible injection and alternating were simulated. CO2 WAG injections were simulated mainly to observe the improvement of low sweep efficiency caused by override and unfavorable mobility ratio. Main considered sensitivities included the WAG ratio and slug size. The integrated recovery efficiency comparison of CMI and WAG was used to demonstrate the mobility control of the WAG process.
Effect of Interstitial Water Saturation and Air Flux on Combustion Kinetics of High Pressure Air Injection HPAI
Authors: Barzin Y. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Tabasinejad F. 
Published: July 2010

Abstract
High Pressure Air Injection (HPAI) in deep light oil reservoirs has received notable attention in the last three decades after its successful field application in 1979. Kinetics of the oxidation reactions associated with HPAI are important for understanding the mechanism which control the overall performance of air injection processes; however, they are not yet fully defined. This paper describes the results of an experimental study conducted to characterize some main parameters which impact the reaction kinetics of light oil oxidation/combustion in HPAI.
Vaporization of oil has been recognized as important mechanism controlling the nature of the residual oil that is the source of the fuel for light oil combustion; however, the parameters controlling vapor phase oxidation/combustion have not been included in the studies of oxidation kinetics. Interstitial water saturation plays an important role on phase behavior and heat transfer and consequently the reaction kinetics. However, there is no reported data in literature investigating this factor.
This study aims to shed light on these unknown aspects of light oil air injection (HPAI). Several oxygen and nitrogen injection experiments have been performed on a recombined light oil and also a pure oil component sample in a 45 cm long, high pressure ramped temperature oxidation (HPRTO) reactor. Experiments were run in the presence and absence of interstitial water at two different levels of air and nitrogen injection flux. This paper concentrates on selected tests which highlight the effects of interstitial water, injection flux, and oil type on oxidation/combustion behavior of light oils under HPAI.
An endothermic evaporation front was observed to precede the thermal front in low flux air injection tests. Interstitial water saturation had a major contribution to endothermic heat of vaporization and the tests with no recombined water barely developed a distillation wave. Observations in this study highlight the significant impact of phase behavior on oxidation/combustion behavior of light oils in HPAI.
Evaluation of a Deposit at the PBU L-106 Site, North Slope, Alaska, for a Potential Long-Term Test of Gas Production From Hydrates
Authors: Moridis G. J. , Reagan M. T. , Boyle K. , Zhang K. 
Published: July 2010

Abstract
As part of the effort to investigate the technical feasibility of gas production from hydrate deposits, a long-term field test (lasting 18–24 months) is under consideration in a project led by the U.S. Department of Energy. We evaluate a candidate deposit involving the C-Unit at the PBU-L106 site in North Slope, Alaska. This deposit is stratigraphically bounded by impermeable shale top and bottom boundaries (Class 3), and is characterized by high intrinsic permeabilities, high porosity, high hydrate saturation, and a hydrostatic pressure distribution. The C-unit deposit is composed of two hydrate-bearing strata separated by a 30-ft-thick shale interlayer, and its temperatrure across its boundaries ranges between 5 and 6.5 °C.
We investigate by means of numerical simulation involving very fine grids the production potential of these two deposits using both vertical and horizontal wells. We also explore the sensitivity of production to key parameters such as the hydrate saturation, the formation permeability, and the permeability of the bounding shale layers. Finally, we compare the production performance of the C-Unit at the PBU-L106 site to that of the D-Unit accumulation at the Mount Elbert site, a thinner, single-layer Class 3 deposit on the North Slope of Alaska that is shallower, less-pressurized and colder (2.3 − 2.6 °C). The results indicate that production from horizontal wells may be orders of magnitude larger than that from vertical ones. Additionally, production increases with the formation permeability, and with a decreasing permeability of the boundaries. The effect of the hydrate saturation on production is complex and depends on the time frame of production. Because of higher production, the PBU-L106 deposit appears to have an advantage as a candidate for the long-term test.
A Novel Electrokinetics Method of Oilfield Scale Control In-situ
Authors: Haroun M. , Ghosh B. , Chilingar George V. , Wittle K. , Pamukcu S. , Badawi M. Al 
Published: July 2010

Abstract
Sulfate scaling in the oil well and near wellbore formation is a common phenomena in a waterflood operation where seawater rich in sulfates mixes with formation water rich in Ba, Sr and Ca ions. This gives rise to frequent well intervention for chemical squeeze and well cleaning operation. Apart from production loss, this could lead to a significant addition to production cost in offshore operations. To find a long term solution for this commonly occurring problem, we experimented on a novel idea of using DC current to reduce scaling. The concept of electrokinetic scale remediation in oilfield was conceived during our successful experience with electroremediation of heavy metals in highly-contaminated coastal sediments of Abu Dhabi where di & tri-valent cations were separated from sediments by applying DC current.
In the present study, we focused on barium sulfate, BaSO4 scaling through a series of experiments conducted in a sand-packed glass cell with variable electrode positioning and fluid injection options. DC power was applied at a fixed 2V/cm potential gradient through a constant electrode configuration used in all tests. The injector sites, where 500 ppm Ba and 500 ppm SO4 solutions were injected to the system were used as anode locations, while the production outlet was used as the cathode location. The NaCl concentration of the formation fluid were varied from 0 to 40,000 ppm and the rate of flow was set at 1 ml/min. Results of pressure build up due to the scale deposition were compared with those from the DC electric field system. The results showed that under DC electrical current, scaling rate reduced by up to 60% at the production outlet. Chemical analysis of scale deposits at various points showed high localized concentration distribution throughout but 50% or less deposition near the production well.
Deepwater DST Design, Planning and Operations—Offshore Niger Delta Experience
Authors: Mogbo Obuekwe 
Published: July 2010

Abstract
This paper focuses on the complex design, planning and operational aspects for a case study appraisal deepwater well in the Niger Delta, offshore Nigeria. The objectives of the Drill Stem Test (DST) were to plan and execute safe operations, determine well performance and reservoir properties whilst overcoming the challenges of gas hydrate formation and sand production from an unconsolidated formation.
Exploration activities are high in the emergent West Africa deep offshore region leading to regular execution of DST’s. However the peculiarities of the locality transform the design, planning and operations involved in execution of such deepwater DST’s into complex challenges. The ability to successfully design, plan and engineer the operations of such tests to obtain relevant results becomes crucial because the accurate determination of well performance and evaluation of reservoir properties of the West African complex faulted reservoirs often prove to be game changers in the development decision making process.
The paper begins with a brief discussion of the DST design methodology: simulation of different test scenarios based on prognosed reservoir properties, rate and test sequence definition. The contingent DST design is updated with changes to its data assumptions based on actual well results. Secondly, the planning for the DST project is described including: rig choice, perforation, sand control, downhole completions, tool and equipment choices etc. Furthermore, the operations are described: hydrate inhibition process, equipment layout for DST package, data acquisition and fluid sample acquisition.
This paper contributes a demonstration of how in a studied field case, careful design and innovative planning of the operational aspects of a deepwater DST ensured that targets were delivered so that pressure transient analysis yielded crucial information regarding well productivity, reservoir properties and boundaries.
Fluid Temperature as a Design Parameter in Carbonate Matrix Acidizing
Authors: Kalia Nitika , Glasbergen Gerard 
Published: July 2010

Abstract
One of the methods to stimulate a carbonate formation involves injecting acid into the matrix under fracturing pressure and dissolving near wellbore damage. The reaction of acid with the soluble carbonate matrix results in the formation of dissolution structures that depend on several factors like injection rate, formation mineralogy, reaction chemistry of the acid, temperature conditions, etc. The effect of temperature on carbonate dissolution has been illustrated in the past by conducting laboratory experiments at different temperatures. It has been shown that depending on the reaction kinetics for a given fluid and formation, the effect of temperature on wormhole formation varies. For instance, in hydrochloric (HCl) acid-limestone system, the acid volume required to achieve a given permeability increase or skin decrease has been shown to increase as the temperature is increased. On the contrary, in HCl-dolomite system, the effect of temperature is more complex and depends on the injection rate. A clear understanding of the effect of temperature on different types of formations and injection fluids is still not available.
In this work, a mathematical model is used to investigate the effect of temperature on carbonate matrix acidizing. It is shown that an optimum in temperature occurs in terms of minimum acid volume and optimum injection rate. In particular, fluid temperature has been identified as a design parameter and its importance is illustrated by simulating injection of acid at a temperature different from the formation.
Considerable number of current carbonate reservoirs are high temperature, making it imperative to understand the effect of temperature on acidizing design. The results from this work translate directly into recommendations on using temperature as a design parameter in matrix acidizing for varying formation and fluid conditions.
Oilfield Automation Using Intelligent Well Technology
Authors: Pande Anil , Morrison Mark , Bristow Richard 
Published: July 2010

Abstract
With oilfield exploration and production in increasingly hostile and remote locations, the use of intelligent fields is essential for ensuring enhanced recovery, reduction of operating costs and increased profitability. An intelligent field is essentially a partially or fully automated oilfield, with real-time data flowing from the wells in the field, that enables monitoring and control for immediate operational needs and also for longer term optimization requirements. Basic oilfield automation consists of sensors that send data to monitoring systems, which is then used for immediate control of those operations. Further optimization occurs when the same data is sent onwards via communication links to onshore applications and processes, for more advanced management of the oilfield, such as production optimization, reservoir management etc. In essence, intelligent wells allow remote, centralized management and collaboration for the wells, by domain experts who can leverage all of the intelligence available in the operations environment for their decision making. This is the key to achieve the ultimate goal of recovering optimal hydrocarbons at the lowest cost.
Intelligent wells become the new basis for decision making by oilfield engineers, by using the collected data and information, and by monitoring, visualization, decision making and control. The key to success in this area is answered by questions such as: Does your intelligent well system provide the proper information, and not just data that you need to make good decisions in field management? Does your environment have the necessary technology that can, for example, search for and easily find relevant information, detect complex data patterns and problems and leverage it as usable knowledge to empower decision makers?
This paper covers oilfield automation by considering the different technology disciplines as ‘layers’, that are needed for the intelligent fields, such as sensors and controls, connectivity and data transmission, data access and finally making the data work. The discussion is from a production point of view for high value offshore wells, but the principles can just as well be applied to other scenarios.
Friction Pressure Losses of Surfactant-Based Fluids Flowing in Coiled Tubing
Authors: Kamel A. H. , Shah S. N. 
Published: July 2010

Abstract
In spite of surfactant-based (SB) fluids wide use as friction reducer and/or fracturing fluid in the oil and gas industry, the flow data in large pipe sizes as well as coiled tubing are very scarce. Majority of the available flow data are gathered in small size straight tubing. The present study involves experimental investigation on the flow properties of aqueous surfactant-based (SB) fluids in small and large-scale coiled tubing. The unique viscoelastic properties of SB fluid affect their flow behavior in large pipe sizes. This phenomenon is called as "diameter effect" or "scale-up factor".
The properties of widely used Aromox APA-T, a highly-active surfactant used as a gelling agent in aqueous and brine base fluids, are thoroughly investigated. Rheological measurements are conducted using Bohlin rheometer for SB fluid concentration of 1.5, 2, 3, and 4 vol. %. Flow data are gathered using ½, 1½, 2⅜, and 2⅞-in. OD coiled tubing with various curvature ratios.
The results show that SB fluids exhibit non-Newtonian pseudo-plastic behavior. Elastic and viscous properties of SB fluids are very sensitive to surfactant concentration. Friction losses in coiled tubing are significantly higher than those in straight pipes due to secondary flow effect. Increasing curvature ratio yields higher friction pressure losses. Also, small-scale data correlations using only simple power law model fluid rheological parameters lead to erroneous results when scaled-up to a large pipe sizes.
New technique, based on the modified Deborah number, including fluid elasticity and pipe shear effect, has been developed to correlate data from the small laboratory-scale tubing and large field-scale pipes. Correlation to predict Fanning friction factor of SB fluids in coiled tubing as a function of Deborah number and fluid flow behavior index is presented. Correlation is validated by comparing predictions with the experimental data. It is shown that the new correlation accurately predicts friction factor of SB fluids and thus alleviates the scale-up issue.
Experimental Study to Find Optimum Pressure for Separation of Wellhead Fluids
Authors: Fazaelizadeh M.. , Mirhaj S. A. , Bahari-Moghadam M.. , Bahonar M.. , Chen Z.. 
Published: July 2010

Abstract
The oil industry deals with wellhead fluids which are a mixture of hydrocarbons, water and impurities. In a two-phase separator design, the gas and liquid phases of a fluid stream are separated at a specific temperature and pressure. A proper separator design is important, because a separation vessel is normally the initial processing vessel in the surface facilities. Improper design can bottleneck and reduce the capacity of the entire facilities. The optimum separator pressure is defined as the pressure at which the maximum liquid volume is accumulated in the stock tank per volume of the feeded reservoir fluid.
The objective of this study is to find the optimum pressure in a single stage separation for the oil that was sampled from a well head at 300 psia by a "flash equilibrium separator". This type of sampling technique enables to determine gas-oil ratios and shrinkage by a flash liberation or vaporization method. A bottom hole or recombination sample is expanded from above its bobble point pressure into a chamber which is equipped with a back pressure and temperature controller. The volume of gas librated is measured with a gas meter at the atmospheric condition while the liquid volume is measured in the separator chamber. Then the liquid is drained and its gravity is measured.
In this paper, by using the "flash equilibrium separator", "gasometer" and "densimeter" apparatuses, the optimum pressure for an Iranian oil sample is obtained and also the gas-oil ratio, oil formation volume factor and residual oil gravity are depicted all as a function of the separator pressure at the desired temperature.