bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydraulic Intelligent Well Systems in Subsea Applications: Options for Dealing with Limited Control Line Penetrations
Authors: Tirado Ricardo 
Published: October 2009

AbstractThroughout the past decade, the reservoir management and interventionless flow control benefits of Intelligent Well Systems have made them a perfect fit for deepwater developments. Approximately 90% of current deepwater wells are subsea, and the number of subsea wells is expected to continue to grow. To enable subsea operators to reap the rewards of intelligent well technology, the industry (operators and service companies) is working to interface downhole intelligent well equipment with subsea trees and controls. Currently, the hydraulic penetration requirements of intelligent wells and the limited number of hydraulic penetrations in many existing subsea trees prohibit some subsea operators from using intelligent well technology. Manufacturing lead times for subsea trees and control systems are usually quite long. Rather than interrupt rig and operation schedules for an extended period while waiting for new equipment with more penetrations, operators often choose not to run intelligent well systems, and sacrifice the resulting benefits.This paper will address various technologies and methodologies that are currently available to enable operators to benefit from intelligent well technology in subsea wells with limited number of penetrations. The case histories covered will illustrate how it is possible to reduce the number of hydraulic control lines required to remotely operate downhole flow-control valves without sacrificing overall system reliability.
Wellbore Tortuosity, Torsion, Drilling Indices, and Energy: What do They have to do with Well Path Design?
Authors: Samuel Robello , Liu Xiushan 
Published: October 2009

Abstract
Borehole quality is generally related to the "smoothness" of the wellbore which manifests in a number of ways, all tied to the efficiency of the drilling process and drilling and well completion cost. Presently, several parameters, such as wellbore tortuosity, curvature, torsion, and various drilling indices, are used to quantify the well path or to estimate the difficulty of drilling a smooth well. Furthermore, there is no clear criterion for defining the quality of the wellbore. Drilling indices describe the quality of the hole more subjectively, rather than quantify the hole qualitatively. In some cases, they are used solely as a measure of how difficult it is to drill the well, rather than how smoothly it was drilled.
Another important parameter that is neglected in the calculations is wellbore torsion. Wellbore torsion depicts the rotating rate of the binormal vector with respect to curved length, or the measure of the rate at which the osculating plane changes its direction. It ensures a smooth well path and reduces the drag and torque in extended reach and ultra-extended reach wells. Because there is no industry standard for quantifying these parameters, a great deal of confusion exists between them, and they are used interchangeably and loosely without any proper substantiation and understanding. This paper provides the details of these parameters, as well as a clear definition and context in which they can be used. The simple guidelines are presented with several example calculations. This paper also provides methods for evaluating these parameters applied on a smooth well path in relative and absolute terms. An additional mathematical criterion based on non-linear curve modeling of a thin elastic beam known as the minimum energy for measuring the borehole quality is presented in this paper.
Depletion-induced Stress Changes in a HPHT Reservoir: Calibration and Verification of a Full-field Geomechanical Model
Authors: Hettema M. H. H. , Bostrøm B. , Pedersen E. S. 
Published: October 2009

Abstract
The Kvitebjørn field is a high pressure and high temperature gas-condensate field offshore Norway seated at a depth of 4000 meters. The field is produced by pressure depletion and therefore many geomechanical risks are at hand. In order to be able to forecast the geomechanical risks a full three-dimensional finite element model of the Kvitebjørn field has been built. We use four types of field measurements for initialisation, calibration and verification of the model:
Surface subsidence measurements at the platform location In-situ compaction measurements from radio-active marker loggin Material properties from core and log measurements Stress measurements from extended leak-off tests
Repeated compaction logging and global positioning measurements are used to calibrate the deformations at the surface and the reservoir level. The geomechanical model is populated by material properties based on core and log measurements. Four extended leak-off tests have been performed at different stages of reservoir depletion. The main application of the model is to determine and predict the depletion-induced stress changes for the entire Kvitebjørn field, to assess geomechanical risks related to infill drilling and collapse of production wells. It is concluded that the calibration and verification of the geomechanical model giving confidence in the prediction of the depletion-induced stress changes and the related geomechanical consequences.
How to Prevent Loss of Zonal Isolation Through a Comprehensive Analysis of Micro-Annulus Formation
Authors: Bois A. -P. , Garnier A. , Rodot F. , Saint-Marc J. , Aimard N. 
Published: October 2009

AbstractMicro-annuli at the well cement sheath's interfaces may result in loss of zonal isolation, which is the source of many problems, such as sustainable casing pressures, cross flows between reservoirs or any undesirable flow behind casing. They are commonly explained by cement volume variations during hydration (chemical shrinkage/expansion) or by contraction of the casing due to a decrease in mud density/temperature as these could create a gap if cement cannot follow induced deformations. However, these modes are not sufficient to predict all possible types of micro-annuli encountered in oil and gas wells, meaning that other modes have been missed.This paper presents a comprehensive mechanistic analysis of micro-annulus formation to highlight the forgotten modes, to explain them, to detail under which conditions they can appear, and to present counter measures to prevent them. It is based on both theoretical and experimental evidences and takes into account most features that characterize cement after it has been placed, including cement volume variations during hydration, cement heat production during hydration, mud density and temperature variations, cement thermo-poro-elasto-plastic behavior during and after hydration, formation thermo-poro-elasto-plastic behavior, and formation initial state of stress.
Model-Based Optimisation of a Gas Production System—The BP Trinidad Field Optimiser
Authors: Ramdial A. M. , Hudson N. H. , Pike R. G. , Rodriguez J. C. , Stratman M. S. , Sama S. S. 
Published: October 2009

Abstract
Oil and gas production facilities are being pushed to their limits to achieve maximum throughput in a period of global economic uncertainty. Cost pressures continue and balancing costs, throughput and maintaining safety remain the unending challenges. This paper and presentation will address a real example of a gas company that has leveraged real-time data with engineering models to manage a complex production system.
It will address these business challenges: How to turn real-time data into actionable information (historized process settings, well test data, etc).How to encourage cross discipline communication by integrating sub-sea, offshore, and onshore facilities.Understanding the impact of field and process constraints together in production potentials and capacity utilization, e.g.:Available separation and transportation capacity.Pipeline back-pressure effects.Wells operational limitations.Onshore treatment constraints (condensate RVP and water contents, capacity of installed stabilization units, etc).Meeting contractual obligations in the most profitable way (e.g. produce the nominated gas quantities in a way that maximizes the condensates revenue stream).Reacting to system upsets and planned equipment outages.In depth understanding of the potential of new field developments and of the required changes in the operating philosophies to maximize the value of the investments.
The Asset system has been tested in a number of real production situations where it has helped to: Pinpoint process behaviors that can be turned into an opportunity for economic improvement,Identify process bottlenecks under various different production scenarios,Co-relate offshore and onshore process constraints to find true overall optimums, andIdentify potential oil production increases
Corporate Venture Capital as a Conduit for Early Adoption of Emerging Technology: A Decade of Experience
Authors: Unneland Trond , Hanten John 
Published: October 2009

Abstract
A continuous challenge in the petroleum industry is to identify and rapidly implement new technologies into field operations to increase production, improve employee productivity and lower costs. Utilizing new world class technology is critical as the industry moves towards more complex environments. To support this, a Chevron corporate strategy is to leverage technology to deliver superior performance and growth. A range of tools are available to achieve this, such as internal R&D, joint ventures and collaboration with academia & service companies. A less traditional method in the petroleum industry is to use corporate venture capital (VC) as a tool to gain access to world class technology. This paper covers a decade of Chevron venture capital experience, including justification for corporate VC investments, how success is measured, financial and strategic yield, investment criteria, governance, partnerships, track record and portfolio highlights. In the paper, several technology transfer success stories are given including the financial and operational value they created for the Chevron business units. The investments cover such diverse technology areas as artificial lift, seismic monitoring, deep water technology, wind power, and high end computing for reservoir simulation.
Modeling Multiphase Wax Deposition in Submarine Pipelines After Shut-In
Authors: Villazon G. Michel , Civan F. 
Published: October 2009

Abstract
Rigorous modeling of wax deposition in submarine oil pipelines undergoing a cooling process after shut-in is developed. Relevant mechanisms of wax deposition are described by accurate approaches. Fraction of wax precipitated under various conditions is estimated by an improved correlation and validated using experimental data. It is proven that consideration of a moving boundary between waxy gel and liquid oil is unnecessary and consideration of wax/oil mixtures as a continuously varying multiphase system is more effective.
Combining Drilling and Evaluation Technology in Remote Operations Increases Reliability
Authors: Thorsen Arve K. , Vargervik Elin , Nygaard Vebjorn 
Published: October 2009

Abstract
Over the past decade several attempts and methods have been applied to ensure remote operations—from moving operations directly from offshore to onshore to a complete redefinition of work processes and responsibilities. This paper demonstrates how a different work methodology onshore improves the reliability in the total drilling and logging while drilling (LWD) operation, focusing on combining drilling and evaluation work processes and technologies.
This paper presents several cases where combining drilling optimization with LWD formation evaluation greatly enhances the understanding of the subsurface environment. The main goal is to optimize the drilling progress with regards to hole condition and reliability combined with optimum well placement.
The elements involved in this process include:
Use of downhole drilling dynamics measurements and interpretation of these to determine required action to reduce any damage to the downhole sensors and to ensure the energy is used to penetrate new formation. Use of LWD data both for understanding the overall drilling regime and for optimum well placement.
In combination with LWD formation evaluation, any changes in the rock penetrated are instantly taken into the drilling optimization procedure, and parameters are then optimized to maintain maximum progress. In this way, the guesswork about changes in the rock properties is eliminated, and the correct action is implemented instantly.
In addition to the downhole technology, the work flow procedures and distribution of responsibilities throughout the team will be explained. Strong collaboration between the different team members is essential to make this process work.
Holistic Design of Cement Systems to Survive CO2 Environment
Authors: Moroni N. , Santra A. , Ravi K. , Hunter W. 
Published: October 2009

Abstract
Cement systems that can survive in the CO2 environment are needed in various applications. Examples of these applications include: 1) producers: CO2 in the reservoir is produced along with the hydrocarbons, 2) injectors: CO2 is injected for sequestration and/or enhanced oil recovery, and 3) producers and injectors: produced CO2 can subsequently be injected for the purpose of enhanced oil recovery/sequestration.
However, the carbonation of Portland cement is a well-documented, thermodynamically favorable process. When CO2 or carbonic acid comes in contact with Portland cement, it initially reacts with it to form water-insoluble calcium carbonate. Longer term, the presence of water dissolved with CO2 (or carbonic acid), if allowed to contact the cement sheath, can dissolve the calcium carbonate to bi-carbonate, which then could be displaced if a flow channel were to be present or formed during the life of the well. This can threaten long-term effective zonal isolation.
A dual level solution is required to effectively address this challenge. As a first level, the potential for CO2 to enter the cemented annulus and contact the cement sheath is minimized, by placing the cement slurry in the entire annulus, reducing the permeability and endowing the set sheath with the properties necessary to withstand the well events. The second level involves reducing the amount of material in the set cement sheath that is reactive to CO2. This holistic approach has worked well in practice. Both the physical and chemical integrity of the cement sheath is addressed using this approach.
Following the design logic described above, a cement system with improved resistance to CO2 environments was created by 1) designing a reduced-permeability cement sheath to withstand well operations with low cement hydration volume shrinkage and 2) optimizing the cement slurry formulation so that its hydration products have a lower amount of materials that are reactive to CO2. This cement system was then tested in the laboratory under expected in situ conditions and optimized for different well situations before placement in the field.
The cement systems have been successfully placed in anumber of wells and these wells are all operating as required with no loss of zonal isolation reported. The design approach, laboratory test procedure and results from laboratory and field are presented and discussed in this paper.
More Accurate Gas Viscosity Correlation for Use at HPHT Conditions Ensures Better Reserves Estimation
Authors: Davani Ehsan , Ling Kegang , Teodoriu Catalin , McCain William D. , Falcone Gioia 
Published: October 2009

Abstract
High-pressure and high-temperature (HPHT) gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300°F. Modeling the performance of these unconventional reservoirs requires the understanding of gas behavior at elevated pressure and temperature. An important fluid property is gas viscosity, as it is used to model the gas mobility in the reservoir that can have a significant impact on reserves estimation during field development planning. Accurate measurements of gas viscosity at HPHT conditions are both extremely difficult and expensive. Thus, this fluid property is typically estimated from published correlations that are based on laboratory data. Unfortunately, the correlations available today do not have a sufficiently broad range of applicability in terms of pressure and temperature, and so their accuracy may be doubtful for the prediction of gas viscosity at HPHT conditions.
This paper reviews the databases of hydrocarbon gas viscosity that are available in the public domain, and discusses the validity of published gas viscosity correlations based on their applicability range.
A falling body viscometer was used in this research to measure the HPHT gas viscosity in the laboratory. The instrument was calibrated with nitrogen and then, to represent reservoir gas behavior more faithfully, pure methane was used. The subsequent measured data, recorded over a wide range of pressure and temperature, was then used to evaluate the reliability of the most commonly used correlations in the petroleum industry. The results of the comparison are presented here and suggest that at pressures higher than 8000 psia; the laboratory measurements drift from the National Institute of Standards and Technology (NIST) values by up to 7.48%.
Finally, a sensitivity analysis was performed to assess the effect of gas viscosity estimation errors on the overall gas recovery from a synthetic HPHT reservoir, using numerical reservoir simulations. The result shows that a −10 % error in gas viscosity can produce an 8.22% error in estimated cumulative gas production, and a +10% error in gas viscosity can lead to a 5.5% error in cumulative production.
These preliminary results indicate that the accuracy of gas viscosity estimation can have a significant impact on reserves evaluation.
Selection Criteria for Artificial Lift System Based on the Mechanical Limits: Case Study of Golfo San Jorge Basin
Authors: Hirschfeldt Clemente Marcelo , Ruiz Rodrigo Ariel 
Published: October 2009

Abstract
The Golfo San Jorge basin is the oldest productive basin of Argentina, and is located in south Patagonia. With 12,630 active oil wells, the basin produces 269,937 bpd of oil, and 2.9 MM bdp of water.
The artificial lift systems are distributed as follows: 9,648 Sucker Rod Pumps (SRP), 1,615 Progressing Cavity Pumps (PCP) and 1,336 Electric Submersible Pumps (ESP). There are some important experiences with gas lift, plunger lift and hydraulic jet pump, but are not considered in this study. Close than 90% of the pumps are installed between 3,000 ft to 8,000 ft depth, producing flow rates over 1,500 bpd of fluid
More than 3.1 MMbpd of water are injected in 2,400 wells in water flooding projects, therefore 41% of the oil is produced from this method. Due to the mature state of the basin, every year, new waterflooding projects are implemented for increasing and to hold the oil production of the basin. With every new project, not only increases the gross production per well, but also increases the depth of the new reservoirs.
The combination of these factors resulted in a higher power to be transmitted from the prime mover to the pump, coupled with the increasing down hole temperature.
Another factor, is the restriction provided by the most common casing diameter (5 ½ "), limiting the outside diameter of the pumps, the tubings and sucker rod sizes, and the shaft diameter too in some systems.
In order to overcome these conditions, not only requires new technology in materials and design, but criteria for operation on the surface to achieve it.
This paper presents a theoretical and practical analysis of the mechanical and operational limit of the most used artificial lift systems in Golfo San Jorge Basin such as the PCP, ESP and SRP.
The analysis not only considers the technical aspects of each critical component and new technologies, but also is supported by reservoir information, operational conditions from 11,000 wells and software simulations for each system.
One of the main objectives of this paper is to provide a guide for selecting and designing artificial lift Systems as SRP, PCP and ESP in similar oilfields and conditions.
Adjustments in Teaching Petroleum Engineering Field Operations Lab—An LSU Experience
Authors: Radonjic Mileva , Bourgoyne Darryl , Panchadhara Sneha 
Published: October 2009

Abstract
Educating and preparing engineers for the 21st Century requires adequate changes in the style we teach and demonstrate knowledge, concepts and their application under complex conditions. Energy industry is undergoing fundamental changes globally, which needs to be transferred into the classroom, in order to enable future engineers to be prepared for contemporary issues in all aspects of oil and gas industry, especially exploration and production. One of the areas to be addressed at the LSU Petroleum Engineering is how we teach laboratory classes in order to prepare our students to easily adopt new safety requirements implemented in industry. In addition to technical competency required for high safety standards, it is also critical to develop a certain kind of behavior that will ensure acts of responsible, ethical decision making and leadership in the work place.

Application
Engineering graduates need to be ready to adjust to the workplace not only in terms of technical competency but also more increasingly in their behavior and attitude towards safety, environmental issues and diverse social surrounding during their careers. The field operations laboratory presented an ideal setting to experiment with teaching, demonstrating and grading styles, which resulted in a positive outcome. The changes were in the following areas: An increased number of hands on exercises on safety components that were practiced on the common safety devices donated by Ruelco.com.Undergraduate students were involved in demonstration, creating an open teaching environment.Experimentation with laboratory report writing using a scientific style of laboratory diary which was handwritten.Visits to the industry were incorporated, both, training and a production facility.Finally, written and practical performance was graded.