bluuebunny/crossref_metadata_2025_split huggingface dataset:
Achieving Global Acceptance of and Compliance With a Universal Set of Petroleum Resources and Reserves Definitions - Are We There Yet?
Authors: Harrell D. Ronald 
Published: February 2015

Management
SPE has long been a leader together with several other cooperative industry organizations in establishing petroleum reserves definitions. This began in 1962 with the appointment of the first SPE Oil and Gas Reserves Committee (OGRC) and continues through the most recent SPE programs and processes created to inform and educate the industry and the public about the applicability and significance of the Petroleum Resources Management System (PRMS) approved by the SPE Board of Directors in March 2007. This article is a condensation of SPE 114162 and the reader is directed to the full paper for more details about the PRMS, the sponsoring societies, and the historical sequence of events leading to the current state of PRMS adoption and acceptance. The creation of the PRMS was, in every measure, a global effort as the mandate for the OGRC and its observers was strengthened by having representation from 10 countries: Australia, Canada, Hungary, Italy, Norway, Saudi Arabia, South Africa, the UK, the US, and Venezuela. Employers of the OGRC members and those of its six observers included privately owned, state-owned, independent, and integrated producers, plus large and small consulting firms, one government agency, and an international accounting board.
The more challenging part of this process clearly lies ahead as the sponsoring organizations work together to "sell" these definitions and principles to upstream petroleum industry management, the financial community, the accounting world, governments, certain mining interests, and regulators.
Has the SPE OGRC reached a sufficiently high level of consensus in crafting the PRMS for it to warrant recognition and acceptance by the companies, agencies, organizations, and individuals who will ultimately make these decisions? This article attempts to address this very important question.
Who Are the Players?
The petroleum value chain begins with exploration and production companies—large and small, public and private—who incur the financial risks and manage other uncertainties endemic to their businesses. Adoption of the PRMS by all or most producing companies will clearly not eliminate the risky nature of the industry but a common understood nomenclature removes a part of the uncertainty and helps eliminate many of the avoidable problems associated with inconsistent, and sometimes conflicting, terminology. How many oil and gas producers are there? Even though most of the world's petroleum reserves and resources are controlled by fewer than 50 or so companies, there are more than 900 companies who registered securities for sale in 2006 through stock exchanges in the US, the UK, and Canada. This number excludes several hundred more tiny-to-large privately owned companies that do not fall under the jurisdiction of any securities reporting agency.
Roncador Field Development: Reservoir Aspects and Well-Development Strategy
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19296, "Roncador Field Development: Reservoir Aspects and Well-Development Strategy," by L. Cysne and M.K. Mihaguti, Petrobras, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Roncador, a giant field in the deepwater Campos basin, was discovered in 1996. Field development involves an 111-km2 area and water depths from 1500 to 1900 m, with significant oil in place, different types of oil, and variations in geological characteristics. The development strategy comprises four modules. The first module, Module-1A, will produce reservoirs in the hanging wall of a large normal-fault structure. Modules-2, -3, and -4, will produce reservoirs in the footwall block. This paper presents key aspects of the reservoirs, drainage modeling and design, and the strategy for project implementation to overcome major reservoir uncertainties, such as fluid type, connectivity, and net-pay thickness.

Introduction
The Roncador deepwater oil field is approximately 125 km from the coast of São Tomé Cape, Rio de Janeiro State, Brazil (Fig. 1). Reservoir depths range from 2900 to 3600 m below sea level. Roncador reservoirs are high-quality Cretaceous-age siliciclastic reservoirs with average porosity of 25% and average absolute permeability of 800 md. The field is divided into two large blocks separated by a major normal fault (Fig. 2), with oil gravity varying from 18 to 22°API in the footwall block and 28 to 30°API in hanging-wall block. The field resource volume is approximately 7.5 billion bbl. Estimated total recovery is 3.7 billion bbl of oil equivalent, with proven reserves of 3.0 billion bbl of oil equivalent.
Module-1 started production in May 2000 through semisubmersible platform P-36. Unfortunately, in March 2001, P-36 sank. Module-1 was renamed Module-1A and was divided in two phases. Phase-1 production started at the end of 2002 with floating production, storage, and offloading (FPSO) vessel Brasil. Phase 2 of Module-1A (P-52) and Module-2 (P-54), both with 180,000 BOPD capacity, started production at the end of 2007. Peak production of approximately 450,000 BOPD will occur by 2013, when all Modules (-1A, -2, -3, and -4) will be on production.
The newest drilling and completion technologies were used to achieve the project goals: field development by constructing good-quality wells with low price in the short term. Technologies and other well-construction strategies that contributed to success in the Roncador development are detailed in the full-length paper.
Offshore Atlantic Canada - Regional Overview
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19273, "The Offshore Petroleum Industry in Atlantic Canada - A Regional Overview," by R.P. Barnes, Canadian Association of Petroleum Producers, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
An overview is presented of current and planned offshore exploration, development, and production activity off the east coast of Canada. Petroleum-related research is taking place and is being applied to offshore development and production.

Introduction
Atlantic Canada is the eastern region of Canada that comprises four provinces: New Brunswick, Prince Edward Island, Nova Scotia, and Newfoundland and Labrador. Current activity offshore Nova Scotia and Newfoundland and Labrador, is shown in Fig. 1. Four offshore fields are in production, and agreements with governments are being finalized for development of a fifth field. The area is a high-cost, high-risk environment with challenges presented by harsh weather conditions, remote drilling locations, and limited infrastructure. Much of the region is relatively unexplored and considered frontier area. Research, development, and new technologies have been key in advancing the industry.
The Newfoundland and Labrador offshore area has three fields in production: Hibernia, Terra Nova, and White Rose. Resource estimates on the Hibernia and White Rose fields have been revised as a result of positive drilling results in nearby satellite fields, and plans are under way to develop the additional resources.
Offshore Nova Scotia was the site of Canada's first offshore oil field, Cohasset Panuke. Production began in 1992, and the field ceased production in 1999. There is one offshore natural-gas field in production offshore Nova Scotia—the Sable Offshore Energy Project. Development of a second gas field, Deep Panuke, was sanctioned in October 2007 and is expected to reach production in 2010. Only a small amount of offshore petroleum-exploration activity has taken place offshore Prince Edward Island, with no significant discoveries.

Offshore Production

Nova Scotia.
The Sable Offshore Energy Project is 250 km from Halifax, Nova Scotia, and began production on 31 December 1999. The project delivered more than 500 MMcf/D of natural gas in the early years of production, decreasing to 375 MMcf/D in 2006. A compression platform was built in 2006–07 that returned production to 400 to 500 MMcf/D in 2007. Production is expected to continue at this level throughout 2008 and then begin to decline. Production is from five separate fields. The most recent public declaration of project reserves, January 2004, estimated the recoverable gas at 1.4 Tcf.
Technology Focus: Knowledge Management and Training (November 2008)
Authors: Ellul Ivor 
Published: February 2015

Technology Focus
We have evolved from attempting to forge a definition for knowledge management (not a trivial undertaking) to active deployment across the upstream exploration and production (E&P) industry—remarkable progress. A common thread prevails among the papers reviewed for this year's knowledge-management feature that relates to concepts and technologies that are being implemented in the field, thus leading to lessons learned and best practices captured—two pivotal elements in knowledge management. A few recurring themes abound that are worth summarizing. These areReal-Time Operations in Drilling. The success of a well is directly proportional to the ability to rapidly analyze drill cuttings, bit dynamics, and other measurements and responses while drilling. This domain is, therefore, an early adopter for information capture, analysis, and conversion into knowledge and eventually into decision making.Wellsite Information Transfer Standard Markup Language (WITSML). In tandem with (or, realistically, as a result of) the flow of data between the well-site and the office, WITSML has emerged as a popular data standard, with the deployment of WITSML servers and clients becoming increasingly common.Collaboration. Everyone understands the benefits of collaboration. Remote collaboration, however, whether on an asset basis or an asset-group (hub) basis, is still evolving.Common Language. Efficient use of data requires providing appropriate access for the right people at the right time. The increasing deployment of knowledge bases is commonplace. However, for this to become an industrywide common practice and for knowledge bases to become standardized, we all need to speak a common language.Data Validation and Reconciliation. This topic is a direct response to the question "Can we trust all the data that are being collected?" Solutions that validate and reconcile data are required to facilitate the direct use of data transferred to complex applications such as reservoir simulators.Communication. One cannot forget the basic need for communication (and person-to-person interaction) to drive decision making, whether by land line, cellular network, radio, or video. Currently, there is no closed-loop control that will deliver complete E&P life-cycle automation.
It seems that important milestones are being met in realizing the data information knowledge workflow with ensuing knowledge capture. Companies are realizing the benefits of such an investment.
Knowledge Management and Training additional reading available at the SPE eLibrary: www.spe.org
SPE 112016 • "WITSML—Changing the Face of Real Time" by N.R. Deeks, Schlumberger, et al.
SPE 112253 • "Real-Time Access to Expertise: Improving Decision Making and Collaboration Through Unified Communications" by Michael Munro, Cisco Systems
SPE 110388 • "A Standard Real-Time Information Architecture for Drilling and Completions" by J.G. Pickering, BP plc, et al.
Transforming Production Data Into Knowledge
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112517, "Transforming E&P Data Into Knowledge: Applications of an Integration Strategy," by Jean-Paul Couput, Alain Louis, SPE, and Jacques Danquigny, SPE, Total S.A., originally prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.
Data validation and reconciliation (DVR) applied to flow-measurement systems improves the reliability and accuracy of production estimates. The potential of DVR to analyze, quantify, and interpret large amounts of data and provide more information from existing sensors is of particular value when key measurement devices fail or are not available.

Introduction
The main objective of the digital-oilfield concept is to maximize production and recovery by integrating all production operations, from the reservoir to export, by use of suitable models and optimization techniques. The combination of both existing and leading-edge technologies ensures that field optimal efficiency is achieved.
Today, most production systems require accurate raw production data. All measured data contain various types of errors (e.g., intrinsic measurement errors, gross errors, and noise). Moreover, when real-time measuring systems, such as multiphase flowmeters (MPFMs), are used, errors may originate from the inaccuracy of the model used to compute the flow rates of the individual phases. Operating decisions based on such data can affect reserves calculations.
The traditional approach to overcome these issues by combining best practices and measurement devices is not sufficient any longer. In the upstream area, new sensor technologies including three-phase metering and virtual metering have emerged. They still remain a challenge, especially in deepwater subsea applications, where equipment repair or replacement involves large costs.
One solution is to combine data from physical sensors with virtual metering and DVR models. This is an innovative approach that has been proved in the downstream area and that effectively helps increase oil production and recovery.

Data-Quality Issues
Building strong and robust field-monitoring systems assumes that the right and correct measurement and data are made available for further processing at the right time. This constitutes a real challenge for existing and future upstream installations, where both instrumentation and associated measurements are deficient and inconsistent. Another issue is the lack of measurement in case of a failure or in the case of measurement systems designed with minimum equipment.
Such questions are not new, but now they are critical and more difficult to address, mainly because requirements are more stringent and measurement accessibility and quality control (QC) are more problematic, especially in deepwater-field developments and in unmanned situations.
Semantic Web Technologies for Smart-Oilfield Applications
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112267, "Semantic Web Technologies for Smart Oil Field Applications," by Ramakrishna Soma, Amol Bakshi, and Viktor Prasanna, University of Southern California, and Will DaSie, SPE, and Birlie Bourgeois, Chevron Corporation, originally prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.
In model-based oilfield operations, engineers rely on simulations to make important operational decisions on a daily basis. Generally, an engineer is an expert in only one aspect of oilfield modeling and trained to use only a few tools. Accessing information captured in models that are not in the area of expertise of the engineer and are created by different processes and people is not easy. The full-length paper examines the application of semantic Web technologies to address the problem of information represented differently across models.

Introduction
The work described in the full-length paper is part of the Integrated Asset Management (IAM) project at the Chevron-funded Center for Interactive Smart Oilfield Technologies at the University of Southern California. The current focus of the IAM project is to enable model-driven reservoir management.
Consider a typical oilfield operation for a greenfield. Because little or no performance-related data for the field exist, the production engineer must rely on simulations for making the initial set of asset-development decisions. Different simulation models of the oil field including Earth, network, reservoir, and integrated-system (coupled)-simulation models are created. These simulation models are built and used at different times and locations, and by team members of different disciplines. A particular member of the team typically is an expert in a particular modeling and simulation technology and is familiar with certain software toolkits in that domain. This means that models, workflows, and results created with other software tools in other domains are not usable and accessible by that expert. As a result, the insights and understanding of a team member in one role are not used fully by someone in another role. These simulation models can be modified constantly as new data are produced in the oil field and interpreted by one or more members of the asset team. In this situation, changes made to the model(s) by one team member should be communicated immediately to other team members who may be using that model as the basis of scenario planning and forecasting, or who may need to modify their own models to match the updates.
Techbits: Reservoir Testing's Benefits Reviewed in Malaysia
Authors: JPT staff _ 
Published: February 2015

Techbits
Recognizing that step changes in oil and gas recovery can only be achieved through analogous step changes in reservoir understanding, a recent SPE Applied Technology Workshop aimed to explore the limits and new promises in reservoir testing. The May 2009 workshop, titled "Reservoir Testing for Maximizing Understanding and Recovery," gathered more than 60 participants from 18 countries to Kota Kinabalu, Sabah, Malaysia to review different reservoir-testing and fluid-sampling technologies aimed at providing more detailed subsurface information which will ultimately lead to improved recovery.
The participants represented both service and operating companies and had an average of 15 years experience, a point which Tuan Haji Akbar Tajudin Abdul Wahab, senior general manager, Petroleum Engineering Department, Petronas Carigali, acknowledged in his keynote address. He said that collectively there were nearly 1,000 years of wisdom in the room.
Wahab used his keynote to challenge the use of the term "well testing," suggesting that it fails to capture the diversity of testing available to the industry today. He proposed that it is time to expand the scope of reservoir testing to cover new technologies, and that new ways of working should be developed to allow an optimal use of new technology with the resources. He also emphasized the need to properly integrate reservoir test results into reservoir models, which can be assisted by proper test planning and design. Not only can the value of the reservoir information be better assessed with proper planning, but it may help avoid unnecessary tests and bring innovation back into reservoir testing.

New Technologies, Improved Reservoir Characterization
In the session titled "Applications of New Technologies," discussion leaders (DLs) reviewed new methods to collect data cost-effectively and ways to maximize the utility of the information collected. The DLs discussed alternative ways of analyzing large data sets from permanent sensors and the long-term reliability of hardware, such as logging-while-drilling tools, in providing fluid samples that could accurately characterize formation properties. The last DL examined smart-well technologies, demonstrating how these could be useful additions to not only production and recovery optimization, but also in providing greater flexibility in testing at all stages of a well's life.
Sakhalin-1: Technology Development for Frontier Arctic Projects
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20208, "Sakhalin-1: Technology Development for Frontier Arctic Projects," by J.M. Hamilton, ExxonMobil Upstream Re - search, and J.E. Jones, ExxonMobil Development Company, originally prepared for the 2009 Offshore Technology Conference, Houston, 4–7 May. The paper has not been peer reviewed.
As the oil and gas industry pushes into frontier Arctic areas, new technologies and design criteria will be required to ensure safety and cost effectiveness of increasingly challenging developments. Sakhalin-1 provides a good example of a development in a frontier subarctic area where location-specific design criteria had to be developed and innovative-technology solutions were required to deal with demanding environmental conditions including sea ice, large breaking waves, and earthquakes.

Introduction
First production from the Exxon Neftegas Limited (ENL) Sakhalin-1 Phase-1 development of Chayvo field began in October 2005, marking the culmination of nearly 10 years of design-criteria and technology development. The development concept consists of an offshore drilling platform, an onshore drilling and treating facility at Chayvo, an oil-export pipeline that runs east/west across the island and Tatar Strait to mainland Russia, and a storage and tanker export terminal at DeKastri. The oil is exported by ice-strengthened tankers south through the Tatar Strait, which is partially covered by up to medium first-year ice (70 to 120 cm) in the winter. The offshore drilling platform, Orlan, is approximately 10 km offshore in approximately 15-m water depth. The platform annually is exposed to approximately 4000 km of drifting first-year pack ice up to 1.5-m (level ice) thickness, which originates in the Sea of Okhotsk north of the island and drifts south along the eastern coast. The controlling ice load features are pressure ridges, with keels extending to depths greater than 30 m (2000-year design value). The design ice load on the 80-m-wide, vertical-sided structure is approximately 385 MN. Design wave loads are generated by late-summer and fall storms that can produce breaking waves at the platform. Global wave loads are on the order of the ice loads, and wave run-up and locally high slamming pressures represent design challenges. Sakhalin Island seismicity is moderate to high, with the active Piltun fault system running north/south on the island as close as 10 km from onshore facilities and 20 km from the offshore platform. The 1995 Neftegorsk earthquake, which registered moment magnitude 7.1, had its epicenter approximately 50 km from the Sakhalin-1 facilities. All facilities must be designed for earthquakes, and the export pipeline, which crosses multiple faults, must be able to withstand several meters of fault displacement.