bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploring for Fractures in Tight Gas Reservoirs, North Oman
Authors: Millson John A. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
As gas operator on behalf of the Oman Government PDO has been active in a mature basin for ca 18 years. The traditional focus for gas exploration in the north has been on deep Haima reservoirs. These have been successfully targeted in a proven Haima silicilastic "play fairway" where all the classic play elements have been are recognised and areally defined in a target window of ca 4 - 5km. The approach has led to the discovery and development of a number of significant deep gas/condensate fields including: Barik, Saih Rawl, Saih Nihayda and Kauther. Periodic attempts (ca 5 year cycle) to move out of the fairway area based on a challenge of prior geological models, developed with new insights, have often led to disappointing results. Outside the mature fairway all the play elements (reservoir, charge, structure, seal) are still present but an additional overriding "reservoir recovery" play risk becomes significant. Reservoir recovery captures (at a play level) subtleties in reservoir composition/facies, burial history and charge timing that have a significant overprint on the overall play risk. To manage the "operational" factors impacting reservoir recovery in the exploration arena ongoing work pursues optimising drilling, completion and testing procedures. The presence of an open fracture network in a recent discovery has triggered a possible geological "game changer" with the potential to significantly reduce recovery effectiveness risk and unlock significant additional gas volumes across a large area. With the aid of a number of key indicators (rock mechanical properties, recent flexure, fault orientation and late charge) a working model for the deliberate pursuit of fracture systems in an exploration setting (a "fracture play") is being developed. This workflow in conjunction with optimised operations may allow a redefinition of recovery effectiveness risk.
Data Acquisition and Interpretation Challenges in Deep Gas Exploration Wells
Authors: de Koningh Hans , Walton William , Millson John A. , Skaloud Dieter , Harthy Mohamed Salim 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
Exploring for gas and gas condensate reservoirs in Oman has in recent years been focussing on deep reservoirs in the Haima Group. Formation evaluation is becoming increasingly challenging with increasing depth. Abnormal pressure regimes and high temperatures go hand in hand with severe borehole breakouts. These factors result in a difficult logging environment making it hard to acquire a good quality data set for formation evaluation leading to efficient completion decisions. Reservoir compaction and cementation increase with depth and typically the reservoirs that are targeted are characterised by low porosity and low permeability. The calculation of water saturation at low porosity is very sensitive to errors. One porosity unit error in this environment will result in a 30 % – 40 % error in the calculated water saturation. In addition, the porosity system in the Haima Group changes with depth. Micro porosity becomes the dominant porosity system at larger depths and this has significant consequences for formation evaluation. In particular with reductions in the resistivity index, the electrical behaviour changes and residual gas saturation increases. Production testing in PDO's exploration setting invariably involves running a liner, completion and some form of fracture stimulation. Therefore, production testing is expensive and time consuming, putting more emphasis on an appropriate "test or abandon" decision. A good understanding of the range of uncertainty on all available data types and their associated interpretation are essential ingredients for the completion decision. A number of examples from recent exploration wells are shown were production test results are compared with pre-test well interpretations with the aim of capturing the lessons learned and highlighting the progress made in recent years in PDO as well as demonstrating the remaining uncertainties.
Redevelopment Of The Abandoned Dutch Onshore Schoonebeek Oilfield With Gravity Assisted Steam Flooding
Authors: Jelgersma Frank 
Published: February 2016

Abstract
The 1 billion stock tank bbls Schoonebeek oilfield produced 250 million bbls medium gravity waxy oil in the period 1943–1996 from a 20 meter thick sandstone reservoir using nearly 600 vertical wells. In part of the field primary recovery was characterised by early water breakthrough caused by a strong aquifer. In another part of the field limited aquifer support in combination with low GOR led to rapid pressure decline and a subsequent requirement for voidage replacement. Small-scale EOR projects were carried out from 1960 to 1996: hot water flooding; wellbore heating; in-situ combustion; high and low pressure steam drives and soaks. In 1996 exploitation was no longer economic, after which all wells were abandoned and most surface infrastructure was removed.
Today, redevelopment of the part of the field that has limited aquifer support is attractive again by use of up-to-date subsurface and surface technologies.
Detailed reservoir modelling identified steam flooding with a closely spaced pattern of 44 horizontal oil producers and 25 horizontal steam injectors in the bottom part of the reservoir as optimal. This process is called "Gravity Assisted Steam Flooding".
To maximise efficiency, a gas fired Combined Heat-Power plant will generate steam and deliver surplus electricity to the national power grid. Wastewater from a nearby sewage plant will be used to produce boiler feed water. Produced water will be disposed of in depleted gas fields in the area via existing gas evacuation pipelines that are converted to water disposal service. Produced oil will be delivered to a refinery in the region by tying into existing third party infrastructure.
The project will deliver more than 100 million bbls of oil and 120 MW of electrical power. Pending Final Investment Decision planned for end 2007, construction will start in 2008 with the project coming on-stream in 2010.

Introduction
The Schoonebeek oilfield is located onshore in the northeast of the Netherlands (figure 1). It is part of a complexly faulted anticline that straddles the Dutch-German border. The German oilfields Emlichheim1, Rühlertwist and Rühlermoor are part of the same structure.
Figure 1. Location map of the Schoonebeek oilfield
The main productive formation is the lower cretaceous Bentheim sandstone (KNNSP). This is an unconsolidated, clean, well-sorted strand plain deposit. Table 1 gives an overview of the reservoir parameters and the medium gravity oil properties in the Schoonebeek oilfield.
Fast Maturation in a Mature Basin; An Example From a Stringer Discovery
Authors: Al-Rawahi Zuwena , Faulkner Andrew , Matvienko Alexander , Al-Mayahi Najma Mohamed , Boersma Diederik Michiel 
Published: February 2016

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

Abstract
Pre-Cambrian carbonate reservoirs occur at depths between 3–6 km in the subsurface of South Oman. These reservoirs are typically over-pressured, encased in and sealed effectively by thick Ara evaporites and contain sour oil. They have been a focus for exploration since the late 1950s. The discovery in 1976 of commercial oil in these "stringers" opened up the Ara play and PDO has since then been actively exploring for these deep oil reservoirs in the South Oman Salt Basin.
Compared to the more conventional reservoirs in Oman, the Ara stringers are complex and pose challenges both in the sub-surface and to surface facilities design, which typically results in a long lag time between discovery and well hook-up. Following the discovery of the Budour NE field in 2005, we challenged to dramatically reduce the time to develop these reservoirs. Thirty five years on, with surface facilities in place and with several producing fields nearby, it was possible to accelerate the appraisal of the discovery and achieve early oil production.
This was achieved through the formation of an integrated exploration and development team that could capitalise on existing infrastructure and local expertise, and was able to deal effectively with appraisal uncertainties. The team worked on the definition, quantification and planning of the field development. This resulted in additional volumes, an acceleration of appraisal drilling, and the early hook-up of the discovery for extended flow testing in 2007, i.e. 18 months after discovery. The latter is a record within PDO for a deep oil discovery. This hydrocarbon maturation exercise will deliver fast reserves, early initial production and an accelerated full field development.
Improvement Of Human Factors In Control Centre Design - Experiences Using ISO 11064 In The Norwegian Petroleum Industry And Suggestions For Improvements
Authors: Aas Andreas Lumbe , Johnsen Stig Ole 
Published: February 2016

Abstract
Managing Human Factors (HF) in the design of control centres (CC) has become increasingly important in large-scale petroleum projects, because of the impact it has on safety and efficient operations. Integrated Operations (IO) and the "e-field of the future" introduce new ways of working, allowing for virtual teams but raise new risk management issues. In 2006, 22 persons, representing different sectors and actors in the industry were asked about their experiences with ISO 11064. ISO 11064 is the standard "Ergonomic design of control centres" and provides guidance on how to handle HF during design of CC.
This paper presents the present status; summarizing experiences made when applying ISO 11064 in Norwegian petroleum projects and suggest areas of improvements. The purpose of the study has been to assess and improve the standard's usefulness for the purpose of reducing the risks introduced by bad design, and to create new guidelines where such are found necessary.
Results indicate that ISO 11064 contributes positively to structuring and legitimating the HF work. The interdisciplinary approach has proved to be an effective HF risk management tool. Applying the standard gives safer operations; this will reduce risk and allow for increased operative efficiency. However, the study also indicates possibilities of improvement of ISO 11064 in areas such as scope of the standard, organizational issues, work procedures, competence in design and operations, exception handling in a virtual organization, communication to the engineering team and documentation of design results. Thus, additional guidelines and techniques are necessary when designing and managing HF in modern CC.
Several improvements to ISO 11064 are suggested. In particular, a goal-based approach can ensure the standard's future applicability, while accommodating technological changes. A survey is planned to follow up on the results to elaborate the findings in the study.

1. Introduction
"HF (ergonomics) is the scientific discipline concerned with the understanding of interactions among human and other elements of a system, and the profession that applies theory, principles, data and methods to design in order to optimize human well-being and overall system performance"[1]. The main objective of this exploratory study is to map experiences from applying ISO 11064 to CC design in full scale industrial projects, e.g. construction of new offshore installations (oil platforms, FPSOs) and onshore process installations as well as major CC modifications of the same.
Analysis of Multi-Criteria Decision-Making Methodologies for the Petroleum Industry
Authors: Lev Virine , murphy Derek 
Published: February 2016

Abstract
Decision-making within the petroleum industry is a complex process involving extensive analysis of multiple objectives based on a variety of diverse criteria. As part of the decision-making process, companies often convert non-monetary criteria to common monetary equivalents, i.e. assigning costs allocations regarding public response to a proposed project. However, this approach has many limitations related to recognizing the company's true financial performance in comparison to quality, safety, environmental concerns and other factors.
When nominal factors are involved, it may be practical for decision-makers to rely on intuition and experience to guide their decisions. However, when multi-criteria exist, simplistic intuitive process may not be applicable in which case a more detailed and robust process is required.
The process of multicriteria decision-making starts with eliciting judgment concerning corporate decision-making policy, in particular identifying levels of risk tolerance. By interviewing key decision-makers and reviewing historical decision making policy, it is possible to identify and quantify an organizations strategic preferences and overall objectives. Such findings can then be used in the multicriteria decision analysis process to further distinguish a company's priorities and requirements.
This paper examines different multicriteria decision making methodologies including the multi-attribute utility theory (MAUT), the simple multi-attribute rating technique (SMART), and the analytic hierarchy process (AHP). This paper presents an independent review and comparison of each method while highlighting how each method can be applied for evaluating different types of decisions within the petroleum industry. This paper also creates discussion around heuristic, intuitive as well as other mental strategies that exist, placing focus on their individual strengths and weaknesses.

Intuitive and Formalized Approaches for Multicriteria Decision-Making
Multicriteria decision-making is a process that can assist an individual and/or an organization to effectively incorporate and evaluate all known factors and outcomes associated with a required decision. The goal of this process is to provide the decision-maker with sufficient information in order to choose an alternative that results in the most feasible and optimal outcome.
Traditionally, many decisions involving multiple objectives and trade-offs are made intuitively by a decision-maker without sophisticated analysis or examination. This style of decision-making relies primarily on various mental simplification techniques by each individual in determining the specific decision of choice.
In many cases these techniques, or heuristics, lead to high quality decisions, however they are often polluted by individual biases and predictable mental errors. In the case of oil and gas exploration and production, such biases may possibly lead to very damaging mistakes.
The Role of Alternative Formation Evaluation Technologies in Brownfield Revitalization in Colombia
Authors: Guarnizo Eduardo Lozano , Garcia German D. , Losada Hernan , Amaya Mauro , Nunez Gustavo , Restrepo Carmenza , Marquez Leonardo 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
The Casabe field in the middle Magdalena valley of Colombia has been producing since the mid-1940s. With some 18 million bbl remaining recoverable reserves, the field is undergoing its third redevelopment campaign. One of the biggest challenges is reducing uncertainty in the decision making process. Evaluation of the properties of the producing horizons allows the selection of the best intervals for completion and enables reliable reservoir simulations that can be used to select products and solutions to increase production. In the past, many factors led to the suboptimal exploitation of the field. The presence of potassium feldspar and other radioactive materials made gamma ray logs inconclusive for the identification of reservoir rocks. As a consequence, spontaneous potential (SP) was traditionally used as the main indicator of reservoir rocks. The evaluation of saturation has also become a challenge. In new wells, the computation of reliable water saturation is affected by a combination of high clay content and the fact that the field has experienced fresh water injection for more than 20 years. So far, 25 wells have been drilled in different areas of the field to increase production and acquire data for a better characterization of the reservoir. Many of these wells were used to test different new logging technologies, which ranged from the latest generation of resistivity- porosity tools to more sophisticated measurements like magnetic resonance, pulsed neutron, and formation testers. This paper compiles some of the results these different technologies showed in the field. A discussion of the role of such technologies in the decision-making process for completing better wells and in understanding the reservoir architecture and flow behavior is also included.
Integrated Local Reservoir Connectivity Analysis in a Channelised Turbidite Reservoir
Authors: Shams Asghar 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.
A good understanding of reservoir performance for management and production requires information on the pressure and saturation variations together with the major connected paths in the system. However in complex geological settings such as channelised turbidite sands, the pathways for fluid movement and pressure evolution between the individual sand bodies are not obvious and cannot be easily inferred from geological data. The effect of gas/water injection and production is therefore hard to predict with certainty. To address this problem, a method which integrates both time-lapse seismic data and a well interference test is developed to help provide a local update to the reservoir simulation model. The benefit is derived from the overlap between the aerial resolution of the time-lapse seismic with the harder, more localised pressure data from the well test. The seismic contributes to an understanding of the 3D geometry of the connected bodies, and this information is fed into an inversion of the well test data to help reduce the non-uniqueness in the interpretation and improve stability. The technique is successfully applied to a deepwater turbidite reservoir with satisfactory results.
One-Trip Expandable Screen Installation Solves Water and Sand Management and Gas Production Issues in Nile Delta
Authors: Abdel Aal Tharwat , Fattah Mahmoud Abdel , El-Sherif Hossan , Bowen Eddie G. 
Published: February 2016

Abstract
In January 2006 El-Wastani Petroleum took a step outside the proverbial "box" and made a decision to use expandable technology as a solution for an existing problem. The well, Gelgel #2, located in the Nile Delta Field of South Manzala, was a prolific gas producer whose upper sand body had watered out. Along with the water came the inevitable sand production from this Miocene Age sandstone. The need to shut off the water and provide sand control within a limited work space was the challenge.
This paper will describe how the operator and service company used a one-trip expandable sand screen system to provide a solution for water shut-off and sand retention while allowing continued production of gas.
The paper will review the operator's investigation and decision-making process in selecting an expandable sand screen system for this project, whose objective was to install a 4-3/4-in. screen system to isolate the water section and allow the gas section continued production while providing a means of sand control during the process. Re-entry access through the producing sand was a critical success factor in allowing for future production logging as required.
The authors will discuss the results of the project, which indicated that the application of expandable technology was highly successful. The screen assembly, which included expandable screens and expandable packers, successfully isolated the desired zones. The water was reduced to an acceptable rate and gas rates returned to a respectable rate of 5MMSCFD, the highest gas producer in the South Manzala Field.

Introduction
The South Manzala Field, located in the Nile Delta of Northern Egypt, is a designated gas field development for the independent operator El-Wastani Petroleum Company. There are currently six producing wells in this field. The Gelgel #2 is the most prolific gas producer in the entire field.
Gelgel #2 was placed on line for production in Septemeber 2004. Initial production came from commingling the IIA and IIB reservoir sand bodies. The IIA sand, located at a depth of 905 meters to 912.5 meters, and the IIB sand, located at a depth of 920 meters to 924 meters, initially produced at an average daily rate of 14mmscf/day until July of 2005 (see Figure 1). Very little water was produced during this period. The well flowed on a 0.875in. choke for the first few months and later increased to 1.719in. until it was shut in during July 2005.
Once an indication of sand production became an issue, the decision was made to isolate the lower IIB sand and produce the upper IIA sand body independently. Isolation was accomplished by setting a bridge plug between the two sand reservoirs.
Large carbide dissolution in GCr15 continuously cast billet core
Authors: Li Zhiqiang , Wen Zhi , Su Fuyong , Zhang Ruijie 
Published: February 2016

Abstract
In-situ tracking was used to evaluate the large carbide dissolution process in GCr15 continuously cast billet core. The time needed to dissolve the large carbides at different temperatures was investigated. As expected, the results showed that increased temperature can significantly shorten the complete dissolution time. Based on the spherical model, a new carbide surface area model to describe carbide size is presented in this paper; the parameters needed were evaluated from the experimental data. Appropriate homogenization cycles are also proposed.
Effect of high magnetic field on carbide precipitation in W6Mo5Cr4V3 high-speed steel during low-temperature tempering
Authors: Wu Yan , Li Hui-Hui , Zhang Zhi-Wei , Tong Lu , Zhao Xiang 
Published: February 2016

Abstract
The effect of a high magnetic field on carbide precipitation in W6Mo5Cr4V3 high-speed steel during low-temperature tempering was investigated. The applied high magnetic field promoted the precipitation of M
6C-type carbides at boundaries and in the grain interior, but maximum spheroidization and refinement occurred for those carbides precipitated at boundaries. Compared with M
6C-type carbides, the effect of high magnetic field on the precipitation behavior of MC-type carbides is much weaker. The high magnetic field hindered M
2C-type carbide precipitation by affecting the Gibbs free energy and increased the microhardness of W6Mo5Cr4V3 high-speed steel at low tempering temperature.
Phase-field simulation of liquid phase migration in the WC–Co system during liquid phase sintering
Authors: Cheng Kaiming , Zhang Lijun , Schwarze Christian , Steinbach Ingo , Du Yong 
Published: February 2016

Abstract
Liquid phase sintering is a process for forming high performance, multiple-phase components from powders. The process includes very complex interactions between various mass transportation phenomena, among which the liquid phase migration represents an important one in the aspect of forming a gradient structure in cemented carbide. In the present work, phase-field simulation of the liquid phase migration phenomenon during liquid phase sintering is performed in the WC – Co based cemented carbide. The simulation results are analyzed and compared with the experimentally determined key factors of microstructural evolution, such as contiguity and liquid phase migration rate. The diffusion-controlled solution–precipitation mechanism of the liquid phase migration process in the cemented carbide system is confirmed from the current simulation result, which provides deeper understanding of the microstructural evolution during the liquid phase migration process. These simulations can offer guidance in preventing the liquid phase migration process during liquid phase sintering of cellular cemented carbide.