bluuebunny/crossref_metadata_2025_split huggingface dataset:
Execution of Brownfield Projects
Authors: Al-Khaledi Sadoun , Waheed Farrukh 
Published: February 2011

Abstract
While the Greenfield projects are considered much easier to execute, both execution and commissioning of Brownfield projects constitutes a major challenge to the oil and gas industry. Still the oil industry due to various financial and operational constraints is continuously pursuing the constructing and commissioning of more and more Brownfield projects. The challenges of executing Brownfield projects are not only confined to the planning, construction activities as far as the Contractors are concerned but it presents a significant challenge to the asset owners for accommodating various construction activities within an operational facility that can have significant integrity issues. Project completion schedule, production downtime and facilities outage also presents a challenge to both the construction contractor and the asset.
This paper will present a case study on one of the major Brownfield project that was recently constructed and commissioned in Kuwait Oil Company (KOC). Although the project significantly enhanced the Company production capacities and capability, however lot of efforts and dedication was required for successful completion of the project. The extend of the construction activity can be comprehended by the fact that all 14 Oil/Gas Gathering centers in greater Burgan fields were upgraded with the addition of new production facilities like gas compressors, oil/gas separators with water treatment units, crude dehydration and desalting facilities and re-location of all critical hydrocarbon piping from underground piping to above ground.
Controls on Mannville Coalbed Methane Production in Fort Assiniboine, Alberta
Authors: Bearinger D. , Majcher M. 
Published: February 2011

Abstract
Fort Assiniboine is a commercial Coalbed Methane field in central Alberta, Canada with over 200 multilateral horizontal wells in the Upper Cretaceous Mannville coal. The Mannville coal seams in this area are under-saturated. Therefore the reservoir's ability to dewater the coal through the fracture fabric to establish a gas phase is key to improving permeability to gas within the fracture system and thus achieving economic gas production rates. There is a wide range of production rates seen across the field. The multiple variables that affect gas production can be divided into a two main categories, wellbore parameters and reservoir parameters. Some of these variables were sufficiently straightforward to establish while other variables, such as permeability, are not as easily ascertained in a fractured coal system having multiphase flow. Field wide data was collected from core, wells, geological and geophysical mapping and production data. The information was compiled and analyzed in order to determine the major controls on gas production rates.
Integrated Monitoring Radon and NORM Scale: HSE Well Surveillance Case Study
Authors: Nengkoda Ardian , Hajri Mohd , Kindy Azzan , Bulushi Abdulwahab , Yazeedi Zeyana , Velagapudi Ravi Kiran , Nicol Barry 
Published: February 2011

Abstract
Processes of oil production, gathering, transportation are some times accompanied by scaling of radioactive materials (NORM). As an integrated approach to identify the Radon and NORM scale as flow assurance issue, a campaign of Radon monitoring, Barium and Strontium ion analysis from produced water potential lead to NORM scale have been conducted starting from well testing and in both onplot-offplot of the oil gathering station. Chemical composition of NORM scales strongly depend on chemical composition of produced waters. Presence of considerable amount of radioactive materials on technological equipment during production and treatment of oil, and gas may lead to personnel irradiation exceeding allowable levels and creates potential hazard to environmental pollution. The role of radon and its decay products in pollution of environment and internal personnel irradiation was not practically studied. Liberation of radon with decay products from scales and their entry into atmosphere may lead to radioactive pollution of environment, which increases the risk of internal personnel irradiation. This technical paper explained how to monitor effectively potential NORM and the intensity of radon accumulation in X field Petroleum Development Oman. During well testing or intervention, the equipment of wells radiobarite precipitates on impellers of electric centrifugal pumps, tubing inside surface in the form of white films with yellowish tint. Thickness of scales on tubing surface achieves 3 mm. In long-run operation radiobarite in electric centrifugal pump is able to clogging up. As a result of this well surveillance, Radon, Barium and Strontium analysis from produced water are really helpful in predicting NORM potential.
HySWEET® Process: An Improvement in Energy Efficiency
Authors: Shah Virenkumar , Cadours Renaud , Weiss Claire , Benquet Christophe 
Published: February 2011

Abstract
Removing mercaptans from sour natural gas has always been considered as a challenge. This is becoming an even more important issue with the global trend towards more stringent commercial gas specifications. Amines have been extensively used because of their ability to meet the most severe H2S and CO2 specifications and their very high acid gas selectivity over hydrocarbons, but present very limited mercaptans removal performances. An additional treatment step is required to achieve the total sulfur specification in the exported gas. Hybrid solvents are more efficient in removing mercaptans, but may have the disadvantage of poor acid gas selectivity over hydrocarbons, resulting in hydrocarbon losses with the separated acid gas.
Total, taking advantage of its extensive know-how and experience in gas sweetening with amine mixtures, has developed a new hybrid solvent formulation allowing simultaneous absorption of acid gases and of mercaptans, with limited co-absorption of hydrocarbons. The HySWEET® process using the new hybrid solvent is in operation at the Lacq plant in France since 2008. More than half of the gas production is now treated with this new hybrid solvent, allowing to achieve not only higher global mercaptan removal but also to reduce the overall energy consumption compared to the use of the HiLoadDEA process.
This paper emphasis on the energy gain that can be achieved by using the HySWEET® process compared to the conventional HiLoadDEA process. A pilot plant study was carried out to compare the regeneration heat duty requirement of the new HySWEET® process with that of the HiLoadDEA process. This study has actually demonstrated that under similar conditions the HySWEET® solvent requires up to 15 % lower reboiler heat duty compared to the conventional amine solvent. These results have been confirmed during industrial operation of the HySWEET® process at the Lacq plant.
This paper also reminds the results of the techno-economic study carried out to evaluate the potential gain achievable by the implementation of the new hybrid solvent. The study lead to identify the application cases for which the new hybrid solvent will allow an economic and complete mercaptan removal without any additional treatment, and a perspective of reduction of the additional treatments for the other cases.
A Case Study of Seismic Anisotropy Analysis on Multi-Azimuth OBC Seismic Data in an Offshore Carbonate Oil Field, U.A.E.
Authors: Ikawa Hidemasa , Mercado Gary 
Published: February 2011

Abstract
Fractures can be observed in micro or macro scale at outcrops and many oil/gas reservoirs can be fractured as well. A good understanding of the fracture network is hence critical for reservoir development since it could have significant impact on fluid flow. Full azimuth 3D seismic data provides a means of detecting and characterizing fractures before drilling. Seismic anisotropy investigation for fracture detection has been carried out in a carbonate oil field located in offshore United Arab Emirates (U.A.E). Target reservoirs are lower cretaceous carbonates mainly consisting of limestone with alternating porous and dense intervals which become dolomitic with depth.
A large 3D-2C OBC seismic data sets was acquired over this giant oil field with orthogonal patch geometry covering all azimuths in 2001. The seismic data was reprocessed in 2006 to improve mainly pre-stack data quality and maintain azimuthal integrity. Velocity and amplitude analysis by ellipse fitting for the azimuthal anisotropy intensity and the direction have been conducted on seismic super CMP gathers, PreStack Migrated (PrSTM) partial stacked data and azimuthally picked velocities. A multi-line walkaway and walk-around VSP survey from a single point of well control was also used to analyze and to verify 3D seismic results.
The VSP amplitude and AVOAz results around the well show harmonic amplitude variation with offset and azimuth. However, amplitude analysis on partial stack data shows relatively high seismic anisotropy intensity especially in noisy data areas and the direction is not consistent with the other results. The azimuth direction of partial stacked amplitude is close to the receiver line orientation and thus appears susceptible to acquisition geometry and processing applications. On the other hand, all velocity analysis results show a NE-SW high velocity anisotropy trend. This is consistent with the regional ZAGROS stress field which also has a NE-SW as SHmax, consistent with FMI and core interpreted open fracture data. Six core and FMI data sets were used in this study to verify the results. The velocity analysis result is consistent with the core & FMI data at 5 of the 6 well locations in terms of the azimuthal direction. These results of this study highlight the importance of reviewing multi-sources of information when available, evaluating pros and cons of the datasets with specific attention paid to data volume, noise sensitivity and resolution.
Uncertainty Management in a Major CO2 EOR Project
Authors: O’Dell P. M. , Lindsey Kirby C. 
Published: February 2011

Abstract
Occidental is the operator of a large turbidite sandstone reservoir in California that has progressed through primary depletion, limited gasflooding, and extensive waterflooding. A fraction of the reservoir is shut-in at this time due to uneconomic water cut. Oxy is currently evaluating a miscible CO2 injection project in this light oil reservoir.
Although a CO2 injection project has the potential to significantly increase oil reserves and extend productive field life, the project includes significant technical and economic challenges. This paper describes the evaluation of subsurface uncertainties, including the use of a two stage design of experiments approach to choose optimal operator choices, regardless of subsurface uncertainties, and preparation of probabilistic production forecasts for project valuation. The steps in generating a robust model, discretization study, tornado analysis, uncertainty analysis, and generating forecast type curves are described.
Operator choices and subsurface uncertainties each have significant impact on oil recovery, CO2 utilization, and project valuation. Though fundamentally different, both must be included in any uncertainty analysis. The authors believe the two step approach is a novel technique to evaluate operational trade-offs and find optimal solutions.
Asphaltene Studies in On-shore Abu Dhabi Oil Fields, PART II: Investigation and Mitigation of Asphaltene Deposition - A Case Study
Authors: Abdallah Dalia , Al-Basry Ali , Zwolle Simon , Grutters Mark , Huo Zhongxin , Stankiewicz Artur 
Published: February 2011

Abstract
Asphaltene is the heavy component of a crude oil that constitutes a potential problem because of its tendency to precipitate and deposit causing blockage in tubulars, pipelines and surface facilities leading to decline in oil production. There are a number of wells affected with asphaltene in an onshore field in Abu Dhabi and this is likely to increase in the future with the implementation of Artificial Lift (AL) and HC/CO2 gas injection for EOR.
Mitigation strategies in the field have been concentrating on design of remedial solvent treatments in combination with mechanical methods for removal of deposits. The company’s approach has been shifting in dealing with asphaltenes from reactive to proactive by conducting studies to: understand asphaltene stability in the different fluids, model the behavior across the whole field, look at the effect of HC/CO2 gas injection on asphaltene stability and finally develop optimal preventative techniques to reduce treatment costs.
The study in this onshore field in Abu Dhabi was conducted on oils collected from different zones. The first part of the study involved analysis of different stock tank oil properties, e.g. API, Sulfur content, Nickel content, asphaltene content and viscosity to look for correlations that can help in identifying the problematic areas in the field. The second part of the study involved asphaltene stability screening tests, e.g. SARA screen, to determine whether the fluids from the different zones are stable or unstable with respect to asphaltene. Live-oil depressurization experiments were conducted on selected wells to determine the Asphaltene Onset Pressure (AOP) at different production conditions using solids detection system with Near Infra-Red (NIR) and High Pressure Microscopy (HPM) for visual confirmation of asphaltene particles. The data from the live-oil testing was then used to calibrate Shell’s thermodynamic model which was then used to investigate the effect of changes in process conditions on asphaltene stability phase envelopes. Results of thermodynamic modeling can be applied on the full field which will aid in developing appropriate inhibition and remediation strategies to deal with the asphaltene challenges.
Asphaltene Studies in on-shore Abu Dhabi Oil fields, PART III: Optimization of Field Chemicals for Remediation and Inhibition of Asphaltene Deposition
Authors: Abdallah Dalia , Bazuhair Mohamed , Zwolle Simon , Grutters Mark , Ramanathan Karthik , Artur Stankiewicz 
Published: February 2011

Abstract
The selection of a chemical solution to asphaltene challenges is an integral part of the flow assurance strategy, and has direct impact on both CAPEX and OPEX. The chemical selection process includes a detailed analysis of deposits, measurements of crude oil properties and various stock tank liquid tests, which are essential input into the development of the most appropriate inhibition and/or remediation strategy. The success of the chemical treatment strategy is a collaborative effort between operations and technology experts.
In an onshore field in Abu Dhabi, routine clean-up jobs to date consist of diesel solvent as a carrier mixed with a dispersant chemical in approximately 80:20 proportions. However, the field observations indicate that such an approach provides often limited effect and sometimes can be detrimental for the well due to fluid incompatibilities. Laboratory tests on deposits collected from this field, combined with Shell’s extensive experience in the area of asphaltenes prevention/remediation led firstly to identification of an alternative aromatic-rich solvent. In addition, better performing dispersant chemicals than previously used were identified that could increase the overall efficiency of the cleaning jobs (soaks, washes).
In order to reduce the frequency of clean-up operations for wells with severe asphaltene problems, continuous application of chemicals (inhibitors) has been considered. Asphaltene inhibitors may not completely prevent asphaltene precipitation but may significantly "delay" the process of deposition. Lab inhibitor testing was performed on crude oil samples collected from the Abu Dhabi field and the performance of the chemicals with respect to their concentration was evaluated. The best inhibitor from the lab testing will be applied in a field trial where the dosage is optimized following a proper surveillance plan to monitor the chemical effectiveness.
Complex Laboratory Method of Reservoir Properties Determination for Anisotropic Layers at the Flowing of Abnormal Oils
Authors: Kadet V. , Dmitriev N. , Mamedov M. 
Published: February 2011

Abstract
Nowadays, the fields of hard recoverable hydrocarbon reserves are involved more often into reservoir engineering process. The problem of recovery is often connected with non-Newtonian rheology of oil and complicated reservoir structure. Now the problem of viscous-plastic fluid flows in isotropic reservoirs is studied enough. But, as a rule the real reservoirs show anisotropy of reservoir properties. That's why taking into account anisotropy at the developments of viscous-plastic fluid flows offer both practical and scientific interest.
The present paper represents the laboratory method of combined determination of absolute permeability and limiting pressure gradient for anisotropic reservoirs. The method for determination a structure of absolute permeability tensor and tensor of limiting pressure gradient on the core samples is based on combined usage of two methods. The first of them is the measurements of ultrasonic waves' propagation velocities through the core sample in the various directions. And the second is the measurements of elastic static deformations of the core sample in the various directions. The usage of specified methods allows to establish the fact of anisotropy at first and further to determine the anisotropy type. Then the necessary number of core samples is sawed out from the drill core in the requisite directions in compliance with the anisotropy type for carrying out hydrodynamics researches.
The results of the determination of absolute permeability tensor and tensor of limiting pressure gradient for anisotropic reservoirs are represented. The results confirm tensor nature of limiting pressure gradient and allow to get law of viscous- plastic fluid flows in anisotropic porous media. Within the frame of suggested method it's possible to determine tensors of phase permeability and construct non-linear fluid flows laws.
Taking into account the anisotropy of reservoir properties permits to describe fluid flow distribution more adequate which in turn makes it possible to optimize direction of horizontal well drilling, to rationalize field development system (well spacing) and finally to increase oil recovery.
Integration of Horizontal Well Test Results and Log Data with the Purpose of Improving Field Simulation Model
Authors: Neustroev K.A. , Kostyuchenko S.V. 
Published: February 2011

Proposal
This article describes the method of integrated application of horizontal well test result and log data interpretation for refining the simulation model of a specific field. It is stated that the filtration reservoir parameters resultant from the well test interpretation can be more accurate versus the petrophysical model results. Therefore, this method can be useful for underappraised fields and greenfields that do not have robust petrophysical dependencies.
We have formulated and investigated the problem of averaging filtration reservoir parameters in the simulation model to match them with horizontal well test result interpretation. The averaging method has been validated using numerical well test models and subsequent interpretation of synthetic pressure build-up curves. The method of matching simulation model parameters and well test result interpretation can be useful for all fields where horizontal wells are used for development.
The article details the problem of horizontal well test result interpretation at a specific field and describes the uncertainty assessment.
Results of Water-gas Stimulation of the Formation Conducted in OJSK “Ritek”
Authors: Kokorev V. I. , Chubanov O. V. , Akhmadeishin I. A. , Shchekoldin K. A. , Kharlanov S. A. 
Published: February 2011

Abstract
The paper discusses two technologies for implementation of gas methods used in oil field development. - alternating gas-water injection and water-gas stimulation in which combined injection of displacement agents (gas and water) is used.
OJSC “RITEK” is successfully implementing the enhanced oil recovery by means of water-gas injection into the formation.
Water-gas stimulation is stimulation of the oil-bearing formation in which oil is displaced by a maximum possible wide frontal gas fringe followed by water injection. Gas flood ensures high displacement efficiency, while water flood ensures high sweep factor.
Enhancing Efficiency of Steam-Thermal Treatment of Formations With High-Viscosity Oil
Authors: Shandrygin A. , Dinariev O. , Mikhailov D. , Nukhaev M. , Lutfullin A. 
Published: February 2011

Abstract
The studies of the combined method of CHOPS and Cycling Steam Stimulation (CSS) of high viscosity oil reservoirs are described. Technological efficiency of the said stimulation compared with the traditional CSS shown and the main factors that influence the said process determined.
The methods aimed at simulating the non-isothermal multi-phase fluid flow in a formation with wormholes within dual porosity/dual permeability model with parameters expressed as a coordinate function equivalent to the average parameters of the fractal structure described.
Interactive Petrophysical Model of Oilfields with Large Transition Zones Salym Fields Example
Authors: Volokitin Y. , Khabarov A. 
Published: February 2011

Abstract
Many “classical” oilfields in West Siberia represent low- relief structures with long transition zones and presence of moveable water above official oil-water contacts (OWC′s). Development of such “undersaturated” accumulations is complicated by difficulties in prediction of rate potentials for new wells and risks of high initial production watercuts.
Salym Petroleum Development (SPD) company (a 50/50 JV of Shell and Sibir Energy) is successful in developing such fields in the South of West Siberian oil province. This business success is based in part on building an effective and reliable petrophysical model of reservoir rock and fluid distribution.
This was achieved through integration of core, log an production data. At the core of the algorithm is a capillarypressure based model of transition zone interlinked with algorithms of traditional and special log evaluation as well as with models of fluid phase mobilities.