bluuebunny/crossref_metadata_2025 huggingface dataset:
Anti-gbm Rapidly Progressive Glomerulonephritis (Syndroma Goodpasture): A Case Report
Authors: Figurek Andreja , Vlatkovic Vlastimir , Vojvodic Dragan , Grujicic Milorad
Published: January 2016

Goodpasture syndrome is a severe illness caused by the formation of antibodies to the glomerular basement membrane and alveolus with consequential damage to renal and pulmonary function. With current therapy, long-term survival is more than 50%. Before, the mortality was higher than 90%.

In our patient, the disease began as dysuria, continued as anaemic syndrome, and ended with the development of end-stage renal failure.

Immunosuppressive therapy with pulse doses of methylprednisolone and cyclophosphamide has put the disease into remission, but the permanent impairment of renal function remained.

Early diagnosis of Goodpasture syndrome helps preserve renal function and improves patients’ survival. In patients who achieve remission, a kidney transplant can be considered. Currently, our patient is awaiting transplantation
The Effects of Acute Vibroacoustic Microvibrations on the Rat Heart Rate, Rhythm and Structure / Efekti Akutne Primene Vibroakustičkih Mikrovibracija Na Frekvenciju, Ritam I Strukturu Srca Pacova
Authors: Kornjaca Dusko , Jakovljevic Vladimir , Zivkovic Stefan , Djuric Marko , Puskas Nela , Djuric Dragan
Published: January 2016

The body surface of homeothermic organisms produces constant microvibrations. In the past, many studies were conducted on this topic, and the amplitude of the microvibrations was described as a sensitive marker of muscle tension and body activity. Subsequent studies indicated that the frequency of the microvibrations is an important variable affecting the body. The aim of this research was to examine the effects of the vibroacoustic microvibrations on the rate, rhythm and structure of the rat heart during physiological conditions. Microvibrations of specific frequency and amplitude were induced by a Vitafon-T, four different modes were used, and the effects of the microvibrations on ECG characteristics and the wall structure of the rat heart were examined. After the application of microvibrations (lasting 10-60 min), no statistically significant changes occurred in the heart rate, but the amplitudes significantly increased after 10, 20 and 30 minutes, and increased even more after 60 minutes. No changes in the heart wall structure were found. Acute in vivo application of vibroacoustic microvibrations in the rats did not produce significant effects on the heart rate and rhythm; however, it increased the amplitude of the R wave by 25-32% in the second standard ECG lead but did not lead to structural changes in the rat heart wall.
Accommodating a Viewpoint
Authors: Abbott J. Haxby
Published: February 2016

In this month's issue, we debut a new feature: Viewpoint. Viewpoint articles are scholarly papers containing opinion or perspectives relevant to musculoskeletal and sports physical therapy. They are editorial-/perspective-/professional commentary-type articles, authored by experts in their topic field, and intended to put research into context for readers by delivering clinically meaningful synopsis, debate, and discussion.

J Orthop Sports Phys Ther 2016;46(2):37. doi:10.2519/jospt.2016.0102
Time Series Modeling for U.S. Natural Gas Forecasting
Authors: Al-Fattah Saud Mohammed
Published: February 2016

Faced with diminishing supplies of domestic crude oil and increased demand for energy, the US has come to rely on imported crude and domestic supplies of natural gas. During the last decade US natural gas production has risen about 10%, but it still fails to meet demand. This failure has resulted in significant increases in natural gas prices. We believe that developing a reliable method to forecast US natural gas production rates and reserves will benefit gas producers, consumers and policy makers.

This paper presents one methodology for developing forecasting models for predicting U.S. natural gas production, proved reserves, and annual depletion to year 2025 using a stochastic (time series) modeling approach. The methodology is not mechanistic. A mechanistic model would examine individual geologic settings, exploration success, the physics of gas production and the rate of exploitation for provinces, basins, and reservoirs. However, to do so would result in an extraordinarily massive model that would be difficult, if not impossible, to develop and use. Instead we used a simpler approach which takes advantage of established trends in easily obtained published data.

Various time series models were tested and validated using data that are not used in the mathematical development of the models. Having adequately validated these time series models using historical data we believe that they can be used to make at least short time forecasts. Comparison of results of this study with other published forecast is also presented. Our forecasts show that U.S. gas production rate will maintain a production plateau of 18.7 Tcf/yr from 2005 to 2008 after which gas production will increase gradually from 19.0 Tcf/yr in 2010 to reach 22.5 Tcf/yr in 2025. We predict that U.S. gas production will have an average annual rate of increase of 0.5% from 2005 to 2015 after which the average annual rate of change of production will increase to 1.2% for the period of 2015 to 2025. Our forecasts also show that U.S. gas depletion rate will increase from 10.6%/yr in 2005 to 13.4%/yr in 2025. While the reserves discovery rate increases, U.S. gas proved reserves are predicted to increase from 197 Tcf in 2005 to 215 Tcf in 2010. Afterwards, the gas proved reserves will increase at an annual rate of 1.3% and are expected to reach 263 Tcf in 2025.
Structural Styles and Tectonic Evolution of Onshore and Offshore Abu Dhabi, UAE
Authors: Johnson Christopher , Hauge Tom , Al-Menhali Saeed , Bin Sumaidaa Saleh , Sabin Brian , West Brian
Published: February 2016

Brittle deformation of carbonate reservoirs was characterized by applying advanced visualization and interpretation techniques to 18 recent 3-D seismic surveys in Abu Dhabi. The excellent data quality afforded a unique opportunity to integrate the broad range of observed structural styles and detailed structural geometries into a unified tectonic model. This resulted in a better and more thorough definition of the structure and hydrocarbon distribution of Abu Dhabi in the context of the entire Arabian Platform.

The observed structures resulted from gentle basement inversion, salt-tectonics, and detached thrusting. The N- and NE-trending anticlines that form the giant onshore fields grew during Late Cretaceous, basement-involved foreland inversion. Systematic sets of remarkably linear, small-offset conjugate fault zones, oriented approximately N75W and N45W, cross the antliclines at high angles to the axial traces. The consistent orientations and shear sense of the fault zones suggests they result from regional WNW-ESE compression, which also drove late Cretaceous inversion and fold growth. Development of the salt-related anticlines was influenced by the same late Cretaceous compression, as well as multiple episodes of salt movement. Both sets of anticlines share the regional fault trends, but the salt-related fault zones have more variable orientations and timing. Mechanical stratigraphy clearly influences fault zone spacing, offset, and segmentation, both laterally and vertically. Interpretations of the fault zones as single fault planes underestimate their geometric complexity. The key to unravelling and communicating the geometric complexity is making use of a combination of data optimization and advanced 3-D visualization and interpretation techniques. Quantification of the orientations, segmentation, offset magnitudes, and spacing of the fault zones provides a foundation for defining their implications for fluid flow within the reservoirs.
Information Content in Forward 4D-Seismic Modelling and Elastic Inversion
Authors: Skorstad Arne , Kolbjornsen Odd , Drottning Asmund , Gjoystdal Havar , Huseby Olaf Kristoffer
Published: February 2016

Elastic seismic inversion is a tool frequently used in analysis of seismic data. Elastic inversion relies on a simplified seismic model, and generally produces 3D cubes for Vp, Vs and density. By applying rock physics theory such volumes may be interpreted in terms of lithology and fluid properties. Understanding the robustness of forward and inverse techniques is important when deciding how much information seismic data really carry.

This paper discusses the observed deviation between a reference and simulated reservoir, and its dependency on the seismic parameters and the reservoir characterization parameters. The ability to utilize the results from a 4D seismic survey in reservoir characterization will depend on several aspects. To investigate this, a loop that performs independent forward seismic modeling and elastic inversion at two time stages has been established.

The multi-disciplinary workflow has several independent steps:Generation of a synthetic reference reservoir, by realistic geostatistical modeling.Flow simulation of the reference reservoir to predict reservoir conditions at survey acquisition times.Establishing a relationship between petrophysical and fluid properties and seismic parameters by a rock physics model.Generation of seismic AVA responses corresponding to reservoir conditions at base and monitor survey times.Elastic seismic inversion of both AVA response sets.Simulation of lithology and fluid parameters conditioned on seismic inversion.Comparison of static reservoir parameters of reference and simulated realization.Comparison of seismic responses at initial and monitor survey times.

By working on a realistic synthetic reservoir, full knowledge of the reservoir characteristics is achieved. This makes the evaluation of the questions regarding the fundamental dependency between the seismic and petrophysical domains stronger. The theoretical limitations of the information content of the seismic data, including 4D, are investigated since the synthetic reservoir is an ideal case with accuracy never achieved in the applied situation.

The production deviation between the reference and predicted reservoir was significantly decreased by using 4D seismic data in addition to the 3D inverted elastic parameters.
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

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

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.

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

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

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

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

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

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.

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

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.
New Completion Design Facilitates Well and Reservoir Surveillance in Beam Pumped Wells in South Oman
Authors: Sadek Ehab , Sikaiti Salim , Abu-ElKhair Al Monaim , Chakravarthi Ravula , Mahrooqi Majid , Zett Arian
Published: February 2016

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

Most oilfields in South Oman comprise mature, heavy oil reservoirs with sub-hydrostatic pressures. Wells need be put on artificial lift since the beginning and different artificial lift methods have been deployed. Rod driven beam pump is one of the common artificial lift methods used and currently more than 1000 beam pumped wells are in operation contributing to about 30% of production from south Oman fields. These oilfields, in general, are geologically very complex and extremely heterogeneous due to the presence of large number of faults and fractures. Water flooding is being used in many of the reservoirs to enhance recovery and increase the economic life of the various reservoirs. Success of water flood calls for increased level of well and reservoir surveillance - more so in an adverse mobility ratio scenario in presence of faults and fractures. The most common surveillance program calls for identifying the source of premature water breakthrough in producers. Conventional beam pump completions do not facilitate effective surveillance, as production logging cannot be carried out.

This paper presents the implementation of a new completion design in rod pump wells which facilitates recording of surveillance data like production logs, flowing pressure survey etc. in rod pump wells by deploying dual well-heads. The well design facilitates deployment of two strings - the conventional string which houses the pump and is used for normal production; and a second string to be exclusively used for surveillance and well intervention. Successful implementation of the new completion design has facilitated recording of production logs in beam pump wells. Well intervention job using a coiled tubing or slick-line can also be carried out using the surveillance string. This can obviate the need of an expensive conventional hoist for intervention jobs like sand clean-out, stimulation, perforations and water shutoff.
An Overview of Reservoir Quality in Producing Cretaceous Strata of the Middle East
Authors: Ehrenberg S.N. , Aqrawi A.A.M. , Nadeau P.H.
Published: February 2016

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

A compilation of average porosity and permeability data for Cretaceous petroleum reservoirs of the Middle East reveals important differences between the two main tectonic provinces present in this region. The Arabian Platform tectonic province is characterized by strong inverse correlation of average porosity with present depth in both carbonates and sandstones, whereas the Zagros Fold Belt, containing almost exclusively carbonate reservoirs, has distinctly lower porosity overall and no porosity-depth correlation. These contrasts are interpreted as reflecting the fact that Arabian Platform strata are mostly at or near their maximum burial depth, whereas Zagros strata have experienced widely varying uplift and erosion following maximum burial in mid- Tertiary time. The carbonate reservoirs show no correlation between average porosity and permeability, probably because of wide differences in dominant pore types. Average permeabilities tend to be much higher for sandstones than for carbonates, despite similar porosity for given depth.

Existence of the Arabian Platform porosity-depth correlation, despite wide diversity of depositional settings and early diagenetic porosity modifications among the individual component reservoirs, reflects the overriding importance of burial diagenesis in controlling the porosity differentiation of reservoir rock bodies. Although porosity commonly shows enormous small-scale (bed-to-bed) heterogeneity, the average pre-burial porosity of larger stratigraphic intervals tends to be very high in both carbonates and sandstones. Burial diagenesis progressively destroys this porosity by chemical compaction and associated (stylolite-sourced) cementation, such that all portions of the affected rock body move toward the zero limit as depth increases. Average reservoir porosity therefore tends to correlate inversely with depth, regardless of the complexities of depositional facies and early diagenesis.
Formation Testing Strategy Based on Quick-Look Data Evaluation From a Fractured Basement Reservoir: A Case Study From Kharir Field Yemen
Authors: De Urreiztieta Marc , Troussaut Xavier , Baradi Ali , Nagaraj Guru , Tresse Philippe , Meunier Jean-Pierre , Paillat Jerome , Kloos Jannes
Published: February 2016

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

In Kharir Field (Yemen, Block 10), major hydrocarbon accumulation is hosted in fractured basement. Along drilled basement sections, only restricted intervals account for flow. Accurate identification of open flowing fractures (amid numerous planar features) is crucial to characterize and monitor non-conventional basement reservoir. At well Kharir-XX, relevant logs were acquired in single run (Resistive-Acoustic Borehole Image, Fullwave Cross-dipole Acoustic, Induction and Spectral GR). Logging program was designed to provide maximal time for flowing intervals identification before decision to perform Formation Tester Run. Acoustic image and Cross-dipole full wave data acquired RIH were sent from wellsite, QCed and processed. Interpretation focused on Acoustic Travel Time Image which is a key parameter for flowing fracture recognition. Wellsite Monopole VDL images were used for evaluation of Stoneley Wave Reflectors. High-definition Array Induction Log and Micro-resistivity Borehole Imager data were logged whilst POOH and sent at regular intervals for evaluation. From above logs, fractures that appeared large, continuous and visible on the Acoustic Travel Time (potentially open at borehole wall); with a conductive appearance on micro-resistivity images were located and oriented. These fractures were then ranked taking into account their good match with while-drilling gas shows and increased rate of penetration. From tens of candidate intervals only twelve were selected for testing. Interval Formation Tester was deployed using Dual Inflatable Packer System (1m packer spacing). Borehole images were used to accurately position packers to avoid risking damage or no/lost seal. Formation Tester was run under Aphron mud system (reversible cake). Special clean fluid carriers inflated packers, thus avoiding risk of plugging fluid lines inside the tool with congealing mud. At well Kharir-XX, 80% of selected sampling stations gave reliable formation pressures, pressure transients, fluid gradients, mobilities and representative formation fluid samples.
World's First Expandable Monobore Well System: Development, Implementation and Significnace
Authors: Jabs Matthew
Published: February 2016

The introduction of expandable metal technology to the oil and gas industry in recent years has allowed a change in the traditional well construction design. The advent of this technology is allowing operators to drill wellbores that do not subscribe to the traditional telescoping reduction in casing sizes as well depth increases. In September 2006 the industry achieved a milestone in its quest to achieve an expandable monobore well. The milestone was the world's first true monobore expandable liner extension system. The successful installation of the expandable liner system was the end result of a collaborative development project between Baker Oil Tools and a major oil company that has been ongoing since spring 2004.

This paper will cover the background, development, and overview of the first commercial monobore expandable liner system.

Introduction

At the turn of the millennium the exploration and production industry sought to prove the feasibility of monobore expandable liner extension systems as an advantageous alternative to conventional casing designs in order to address the technical needs of the increasingly challenging drilling environments.

The ability to drill wellbores that do not subscribe to the traditional telescoping reduction in casing sizes as the well depth increases will allow extended reach wells to be drilled without sacrificing casing size results in advantages over the traditional telescoping construction methods.

The goal of an expandable monobore liner extension is to enable the operator to drill deeper exploration and production wells with larger hole sizes at the reservoir. In addition expandable monobore wells provide the operator the ability to isolate zones that contain reactive shale's, sub-salt environments, low fracture gradient formation or other drilling situations without having to reduce the casing and subsequent enter into the production reservoir with reduced size production hole sections which may adversely affect well production.

(Fig. 1 & 2)

System Development Background

Expandable Material and Expansion Methods

The use of expandable metal technology to construct a monobore well requires the selecting of the correct material and method of expansion to achieve desired expansion percentages and final performance properties. The performance properties are not only measured in empirical numbers such as burst/collapse/tensile rating but also in ability to provide a suitable solution to an application. Both of these factors must be developed and analyzed in unison in order for a system to perform as expected.

Expandable Material Selection

Material for use in expandable applications is evaluated and tested in regards to how it performs pre expansion, during the expansion process, and post expansion. The criteria used most commonly to classify and capture these material properties and performances in the three states are: toughness, work hardening, and the Bauschinger Effect.
3D Seismic in the Mature Onshore Dukhan Field: What Is the Value of New Seismic Data?
Authors: Thomson Andrew Brodie , Van Baaren Peter , Al-Ansi Hussain , Smart Andrew
Published: February 2016

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

3D seismic data is recognized as a key tool in successful reservoir management. The existing Dukhan 3D seismic data is more than 15 years old and is of poor quality. 3D seismic technology has advanced significantly in the last 15 years and the technical case for new data appears to be strong. However, in a mature field with more than 700 wells, the potential business impact of new 3D seismic data needs to be carefully evaluated. QP undertook a seismic feasibility study in 2003 and concluded that the technical and business impact of new data needed to be tested before any larger scale full-field re-shoot could be considered. To address this issue, a state-of-the art combined borehole and 50 square km surface seismic pilot 3D survey was acquired over Dukhan field in 2006. The purpose of the pilot survey was to assess the technical benefit of new acquisition and to assess survey design issues. Additionally the pilot 3D seismic survey allowed QP to get a much better assessment of the many logistical issues involved with shooting land 3D within an active producing oil field. This Dukhan pilot 3D seismic survey successfully highlights the dramatic impact of the many advances in seismic technology over the last 15 years The paper discusses the technical needs to be addressed by new seismic data, the acquisition and processing results, compare the new data with the old data and discuss the impact of the pilot data on plans for larger full field re-acquisition.
Big And Clean - A Novel Design For LNG Plants
Authors: Pek Barend Johan Jan , Sander Kaart , Wiveka Elion
Published: February 2016

The fast growing world demand for clean and affordable energy translates into a large demand for LNG production capacity in the next decade. To meet this rapid increase in production capacity, increasingly larger train sizes have become the trend for many years in order to benefit from economies of scale. In addition, large LNG projects reduce the specific engineering contractor efforts.

This paper presents a mega train design for a production of well over 10 Mtpa. The design is based on Shell's Parallel Mixed Refrigerant process. A large part of the expansion in world LNG production is currently taking place in the Middle East. Hence, a typical feed-gas composition from this region has been selected as the basis for integration of gas conditioning (treating), NGL extraction, liquefaction process, and utility facilities. The design will be flexible to meet the typical US low heating value requirement or higher values.

A combination of large mechanical gas turbine drivers and steam turbine drivers provide the refrigeration power demand. A plant-wide integration of heat generation and demand is provided by steam. This includes the waste heat recovery from the gas-turbine drivers, co-firing, the heat demand of the energy intensive treating train and heat production by the sulphur-recovery unit. The full utilisation of waste heat from the gas-turbine exhausts causes a step-change in plant efficiency and can help to reduce the specific CO2 emissions considerably with respect to a conventional LNG plant design, at the same time providing world class LNG train capacities without major step-outs in equipment.

Other challenges addressed in this paper are, maintaining the economy of scale for mega train designs, availability, operability, and start-up considerations for this highly integrated design.

Figure 1. Construction of the Sakhalin LNG plant.

INTRODUCTION

At Shell, we see demand for natural gas growing by some 3% a year over the next 15 years, with demand for liquefied natural gas growing by some 8–10% a year [1]. This is a mere consequence of the fast growing world demand for clean and affordable energy for which LNG is in many cases the preferred route. Already for a few years we have seen a large number of projects underway resulting in a constrained contractor market, a worldwide heavy demand for raw materials as well as issues around logistics of work force and products. These challenges call for large trains, particularly where large resources are involved as in the Middle East, Russia and Australia.

Shell and others have already increased train sizes in recent decades from 1 Mtpa to 8 Mtpa, primarily driven by the desire to reduce capital expenditure. Application of large trains will also help to use the available contractor capability more effectively.