bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Match and Associated Forecast Uncertainty Analysis - Practical Approaches Using Cluster Computing
Authors: Landa Jorge Luis , Kalia R.K. , Nakano A. , Nomura K. , Vashishta P. 
Published: February 2016

Abstract
This paper presents practical approaches to deal with the complex problem of the uncertainty assessment in the performance forecast using reservoir simulation models with extensive production history. The complexity and difficulty of this type of problem arises mainly from the necessity of finding a large number of simulation models that are consistent not only with the geological data but also with the observed production history. In simpler terms this means finding an appropriate number of multiple solutions to the history match problem that can be used to estimate uncertainty in the forecasts. The rigorous solution to this kind of problem involves the application of methods based on Monte Carlo simulation; but they are not routinely applied because of the computational cost associated to the necessary large number of simulations for real field problems.
Advances in computing technology in recent years, especially in the areas of CPU speed and of high performance computing affordability with medium to large CPU clusters, indicate that now is, probably the appropriate time to explore and revisit the practical aspects of performing a more comprehensive history match and forecast uncertainty analysis with Monte Carlo simulation methods.
The approaches presented in this work take advantage of the availability of a medium size 256 CPU Linux cluster that allowed the coupling of distributed high performance computing with efficient sampling techniques to solve the history match and the associated forecast uncertainty problem under a probabilistic inverse problem framework, and to present the results of both history match and forecast in the form of probability density functions (PDF). Prior probabilistic model information is incorporated in the process.
The tests performed with data from a real field indicated that our approaches provide one practical way to address, more comprehensively than current existing approaches, the non-uniqueness issue of the history matching problem and the associated uncertainties in performance forecasts in real fields. Since the results are accomplished in a very short time, significant changes in reservoir management paradigms may result.
History and Prospect of Natural Gas Development in China
Authors: Wang Fengjiang , Zhang Guang Jie , Zhang Ying , Cong Lianzhu 
Published: February 2016

Abstract
Along with the discovery of gas fields and the increase of gas reserve, China's natural gas industry has been entering a new period of rapid growth. The gas yield has witnessed a steady increase in the last decade. It could be expected that great progress will be made in both exploration and development.
In this paper, the history of natural gas industry was reviewed, and the achievements were summarized for every stage of development. The prospect forecast was proposed in gas exploration and development. The reserve increase and gas yield trend was suggested, indicating the rapid growth trend will sustain, and natural gas will play an even more important role in the energy mixture in China.

Historical review of gas exploration and development
Exploration. Gas exploration has seen 5 stages of development (Figure 1).
Stage 1 (Before 1956): There was no new gas fields found and gas reserve remained a low level (around 0.2 bcm).
Stage 2 (1956 – 1976): In this period, gas reserve saw a relatively low increase, and most reserve was obtained in Sichuan basin. To the statistics, the quantity of reserve increase was 121 bcm, of which over 70 percent was that of Sichuan basin.
Stage 3 (1977 – 1989): In this phase, besides a number of small-scaled gas reservoirs were found in Sichuan basin, a series of breakthrough was achieved in such basins as Tarim, Ordos, Qaidam, Ying-Qiong, East sea, etc.. Many gas-bearing structures were identified through exploration well-drilling. In particular, field Ya 13-1 in Ying-Qiong basin was the largest gas field in China at that time, and it was the first high productivity and high reserve abundance offshore gas field in China.
Stage 4 (1990–1999): A series of important breakthroughs in gas exploration were achieved and the natural gas reserves saw a rapid growth. With the stable progress of natural gas exploration and development in Sichuan Basin, three new natural gas areas, Tarim basin, Ordos basin and Tsaidam basin, came into being. In this period, gas reserve of 950 bcm was proved. A number of large fields found or proved in this period (such as Dukouhe, Wubaiti, Shapingchang in Sichan basin, Jingbian, Yulin in Ordos basin, Kela 2, Yaha, Yingmaili in Tarim basin) became major gas producers and supply sources.
Resistivity Anisotropy as a Decision-Making Tool: A Case Study From Egypt
Authors: Aldred R.D. , Nour M. , Reda M. , Nelson R. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
When BP drilled the offshore Nile Delta well, Ruby-2, they encountered a sequence of thinly laminated shaly sands. Neither LWD nor conventional wireline resistivity logs gave clear indication of hydrocarbon presence, and only a small crossover on the neutron and density logs showed the possibility of the presence of gas. Fortunately, BP also ran a multi-component induction device, allowing the measurement of vertical resistivity in addition to the conventional horizontal measurement. The electrical anisotropy measured by this tool gave a clear indication of the presence of hydrocarbons in the laminated formation and made the decision to test the interval a foregone conclusion.
Following the successful test, the data recorded also allowed the petrophysicists to evaluate the formation with greatly reduced uncertainty, and made it possible to distinguish between productive laminated intervals and non-productive zones where formerly laminated sequences have been disturbed by bioturbation and slumping.
This paper reviews the technology behind the tool and the tensorpetrophysical model used in the interpretation and uses examples from the Egypt well to illustrate the various benefits of using these techniques. The paper also shows confirmation of the techniques by comparison with core and imagedata.
Integrated Reservoir Management Approach: From Time-Lapse Acquisition to Reservoir Model Update at the Norne Field
Authors: El Ouair Youness , Lygren Magne , Osdal Bard , Husby Oddvar , Springer Martin 
Published: February 2016

Abstract
As in many other fields in Statoil, Time-lapse (or 4D) seismic data is one of the important tools used for monitoring the Norne field. However, in order to reduce uncertainties, an integrated multidiscipline approach involving geophysics, reservoir engineering, geology and petrophysics has been successfully applied. As a result, a better history matched reservoir model was obtained by improving the consistency between the reservoir simulator results and the observed 4D seismic data. This led to an increased understanding of the reservoir drainage and hence contributed to the process of identifying and prioritizing infill-drilling targets at Norne.

Introduction
Time-lapse seismic data is used in the reservoir management of about 70% of the offshore fields operated by Statoil. Interpreted and inverted 4D seismic data has given valuable information used to locate remaining hydrocarbons in the reservoirs. Thus, we have been able to save wells, optimize the positions of infill wells and to generally increase the understanding of our reservoirs.
However, there is a need to extract more quantitative predictions from the 4D seismic data. This can be achieved by increasing the integration of geophysical data with data from well logs, well production and injection data and general geological knowledge. One particular approach for data integration is by using all available and relevant data in conditioning the dynamic reservoir model. In other words, to use 4D seismic data jointly with well data in the history matching process of the reservoir simulator.
In this paper an integrated approach applied on the Norne field is presented where several disciplines as 4D Q marine seismic acquisition and processing, 4D seismic Bayesian inversion and computer-assisted seismic history matching are combined together. One of the new aspects of this method is the quantification and the propagation through the whole chain of the uncertainties inherent to seismic and well data.
The final objective is to update the reservoir model and so, obtain a better estimate of the remaining producable volumes that is crucial in reducing decision risks related to the well drilling process.
South Diana, Gulf of Mexico, U.S.A.: A Case Study in Reservoir Management of a Compacting Gas Reservoir
Authors: Guenther Kurt Thomas , Perkins D. Sam , Dale Bruce A. , Pakal Rahul , Wylie Phillip L. 
Published: February 2016

Abstract
South Diana is a single-well gas condensate field in the deepwater Gulf of Mexico (GOM). The reservoir consists of turbidite unconsolidated sands separated by thin shales. Geomechanical characterization of South Diana core revealed high rock compressibility and potential for compaction- induced permeability reduction. This paper discusses various modeling studies conducted prior to field startup to assess the impact of rock compaction on well integrity and producibility. Geomechanical models, reservoir simulation studies, and core measurements were used to develop physics-based integrated well performance technical limits. These technical limits have been used to successfully manage rock compaction related risks to well integrity and producibility. Reservoir surveillance data and comparison with model predictions are discussed. Reservoir management issues and insights gained from field data for this compacting deepwater reservoir are also discussed.

Introduction
As offshore developments trend toward fewer wells with high per-well production volumes and rates, new technologies are required to ensure long-term mechanical integrity and optimum producibility of wells. An example of one such development is the South Diana single-well satellite gas field in deepwater GOM. The field was developed through an 8-mile subsea well tie back to existing infrastructure in the Diana Basin (4400-ft water depth). The reservoir consists of several high quality distal turbidite unconsolidated sands separated by thin shales. At the time of field development, key geologic uncertainties included connectivity across the reservoir area and sand thickness away from existing well control. Natural depletion with moderate water-drive is the expected depletion mechanism. Cores and fluid samples were obtained from the discovery well and a sidetrack well.
Geomechanical characterization of South Diana core revealed high rock compressibility with depletion and potential for compaction-induced permeability reduction. Pressure transient analysis from offset ExxonMobil operated reservoirs (Diana, Hoover, Marshall, Madison) within the Diana basin has confirmed reservoir-wide compaction. These analyses have shown reductions of up to 80% of the original flow capacity (Kh) for several wells. The quantitative impact of compaction could not be predicted directly from laboratory measurements on cores for a number of reasons including differences in stress paths between experimental and actual reservoir depletion. Similar compaction induced reduction of Kh has been documented by other GOM operators.
Permanent Seismic Monitoring of the Valhall Field, Norway
Authors: Barkved Olav Inge , Kjelstadli Roar Morten , Kristiansen Tron Golder , Buer Kjell , Kommedal Jan H. 
Published: February 2016

Summary
The Valhall field started production in 1982 and is expected to produce for another 25 years. Recently three new platforms were installed at the field to facilitate a water injection program and infill drilling.
The central area of the reservoir is difficult to image using conventional marine streamer data due to gas charges in the reservoir. The imaging challenges have been addressed by using seafloor recording of converted shear waves. In other parts of the field the seismic quality is very good and a conventional 4D seismic surveys acquired in 2002 provided impressive production induced 4D seismic images.
A permanent seismic array was installed across the field during the summer of 2003. The system allows for cost effective acquisition of frequent seismic surveys. The primary objective is to use the resulting 4D images to improve recovery and to provide technical assurance.
The permanent seismic recording system was selected based on its ability to acquire shear wave and expected improvement in repeatability to allow for monitoring of production and injection of low volumes.
In the period from September 2003 until April 2005, five time-lapse surveys have been acquired. High quality and repeatable data has allowed for identifying relevant 4D effects taken place over only a few months.
In this presentation we will discuss the Valhall permanent seismic system, present some results and discuss how these data are used to improve the value of the field.

The Valhall field
The Valhall field is located 290 km southwest of Stavanger, Norway, in 70 m water depth, figure 1. The reservoir is over-pressured Upper Cretaceous chalk. The field was discovered in May 1975 and production from the field started in 1982. After 23 years the field is still producing at plateau and is expected to produce economically for 23 more years, [1]. To date, around 500 million barrels of oil, out of the estimated 2, 7billion barrels in place, have been produced.
Building a Premier Technical Workforce
Authors: Fischer Timothy Paul , Donald Best , Burgis Wendy , Tittle Lisa , Zimmerman Linda J. 
Published: February 2016

Abstract
Building a premier technical workforce for the upstream petroleum industry requires knowledge of worldwide business needs, corporate commitment, and guiding principles. Centralized processes for skill development ensure the quality, effectiveness, and efficiency of training globally. State-of-the-art tools for skill assessment, course development and delivery, and mentoring accelerate the development of targeted technical skills.

Introduction
A long-term, corporate commitment to technical excellence is the foundation for building a premier technical workforce for the upstream petroleum industry. This process requires the collaboration of various operating, technical, and support (i.e., training and human resources) functions of an organization. These groups collaborate in hiring and planning, executing, and stewarding skill development. They also collaborate to adapt methods of skill development for a culturally diverse and geographically dispersed workforce.
This paper focuses on principles, processes, and tools that optimize technical training for a global, upstream workforce (Figure 1). Overarching principles that guide training programs set the stage for a discussion of processes for skill development. These processes are presented in the order of their use from hiring through training. Selected tools are then discussed in the context of the associated processes. We also show how technical-training tools can enhance other types of skill development, such as mentoring.
Foundation for Skill Development. Consistent corporate funding for high-quality technical training is required to sustain a commitment to technical excellence over time. Employee access to technical training at all career stages improves productivity as technology develops.
Business systems that predict skill needs in operating organizations guide the development of training programs. Databases of employees' skills are essential for outlining individual training plans. These systems and tools identify existing, optimal skill sets that match individual capabilities and employee interests with company needs (Figure 2). Training is most effective when existing skills sets of individual preference (Figure 2, dots) are extended toward new skill sets that match employee interest with company need (Figure 2, diagonal pattern).
New 3D Seismic Interpretation Methods To Characterize Fractured Gas Reservoirs
Authors: Reeves James J. 
Published: February 2016

Abstract
Reservoir fractures are predicted using multiple azimuth seismic lineament mapping in the Lower Dakota reservoir section. A seismic lineament is defined as a linear dislocation seen in a time slice or horizon slice through the seismic volume. For lineament mapping, each lineament must be recognizable in more than one seismic attribute volume. Seismic attributes investigated include: coherency, amplitude, frequency, phase, and acoustic impedance. We interpret that areas having high seismic lineament density with multi-directional lineaments are associated with high fracture density in the reservoir.
Lead areas defined by regions of "swarming" multi-directional lineaments are further screened by additional geologic attributes. These attributes include reservoir isopach thickness, indicating thicker reservoir section; seismic horizon slices, imaging potentially productive reservoir stratigraphy; and a collocated cokriged clay volume map for the Lower Dakota computed from near trace seismic amplitude (an AVO attribute) and a comprehensive petrophysical analysis of the well data to determine discrete values of clay volume at each well. We interpret that clean/low clay reservoir rock is brittle and likely to be highly fractured when seismic lineaments are present.
A gas sensitive AVO seismic attribute, near trace stacked phase minus far trace stacked phase, phase gradient (an AVO attribute first developed by GeoSpectrum), is used to further define drill locations having high gas saturation. The importance of this attribute cannot be understated, as reservoir fractures enhance reservoir permeability and volume, they may also penetrate water saturated zones in the Dakota and/or Morrison intervals and be responsible for the reservoir being water saturated and ruined.
Seismic interval velocity anisotropy is used to investigate reservoir potential in tight sands of the Upper Dakota up hole from the main reservoir target. We interpret that large interval velocity anisotropy is associated with fracture related anisotropy in these tight sands.
Results from a four well drilling program to test GeoSpectrum's fractured gas reservoir prospects show that the fracture detection methodology is ready to be applied on a commercial basis.
Improving Produced-Water Quality by Investigating the Farthest Upstream Solution
Authors: Westaby C. , Fransen N. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
Many papers and conferences regarding produced water focus on oil detection, redemption and water chemistry. These discussions typically cover methods of reporting when and why too much oil was discharged from the facility. Many facilities used to reduce oil content in the produced water list their separation efficiency at 96–97%. Very little discussion in these papers and conferences covers the upstream processes which feed the final separators. As many fields and facilities age production rate, oil density and oil/water concentration will change from what the facilities were originally designed for. Often these changes will cause the production separators to perform below their initial design specifications.
Since the final devices in the facility list an efficiency less than 100%,the performance of the initial production separators is just as important as the final vessel. If the initial separation is not performing properly everything down stream from there will not be able to produce expected results. This paper will discuss methods of improving the separators performance by controlling the oil/water interface, optimizing emulsion thickness and vessel modifications. By controlling the interface within the vessels the system will perform better than when the discharge water is monitored for oil content. Once the discharge water has too much oil present the separator, being upstream, cannot have any impact on the down stream water quality.
Pressure Drop for Oil-Gas Two-Phase Flow Through Straight Horizontal Pipe
Authors: Liu Wenhong , Guo Liejin , Zhang Ximin , Lin Kai , Yang Long , Feng Yaorong 
Published: February 2016

Abstract
An experimental investigation on oil-gas two-phase flow through a straight horizontal plexiglas pipe within 40mm inner diameter was conducted. The superficial velocity ranges of oil and air were 0.05–0.612m/s and 0.024–50.64m/s, respectively. The atmospheric temperature condition was maintained throughout the experiments. The frictional pressure drop multiplier of two-phase flow was expressed using the Lockhart-Martinelli parameter correlation in accordance with typical flow pattern, but the modification factor C in the correlations was defined afresh according to flow conditions. New predict correlations for pressure gradient in accordance with typical flow patterns were proposed and the mechanisms of pressure drop production were analyzed for each flow patterns. The proposed models give a good agreement with the experimental data.

Introduction
Production of oil from offshore reservoirs also implies the simultaneous production of natural gas. Today's and tomorrows offshore production includes long horizontal wells and multiphase transport over long distances. Thus, it is important to have some knowledge on the flow characteristics of the two-components, such as flow patterns, pressure drop and holdup, especially at high pressure, for the proper design and operation of pipelines[1~4]. So far there is no specific models or correlations for the pressure gradient prediction of gas-oil flow.
Pressure drop for gas-liquid two-phase flow is very important in engineering application and many research were studied. But most of the correlation for predicting pressure are for low viscous liquid. As the more research on oil-gas-water three-phase, Study of highly viscous liquid are too important, especially for frictional pressure drop.