bluuebunny/crossref_metadata_2025 huggingface dataset:
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 The paper has not been peer reviewed.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.
Field-Development Expansion By Use of Artificial Islands as Drilling and Production Centers
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 118379, "Field Development Expansion of a Giant Oil Field in Abu Dhabi Using Artificial Islands as Drilling and Production Centers," by A. Modavi, SPE, Zakum Development Company/ExxonMobil, and W.W. Martin, SPE, A.H. Muflehi, J.V. Walters, and G. Ismail, SPE, Zakum Development Company, originally prepared for the 2008 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 3–6 November. The paper has not been peer reviewed.

The current development plan for the subject field is based on drilling from numerous wellhead platform towers (WHPTs). The current production-buildup target would require many more new WHPTs and hundreds of kilometers of new pipelines connecting the new and current towers to the field central processing complex and its satellites. The full-length paper examines an alternative field-development strategy based on a few drilling/production centers (i.e., artificial islands and/or large platforms), instead of numerous new WHPTs.

Introduction

The giant oil field discussed in the full-length paper was discovered in the early 1960s and is offshore Abu Dhabi. This field stretches over some 1200 km2, and is one of the largest oil fields in the world, with a current expected operating life exceeding 100 years. Over the past 30 years, field development has been based on pattern producer and water-injection wells drilled from WHPTs located throughout the field. To date, 80 WHPTs have been installed, each capable of supporting as many as 14 producer/injector wells served by production-gathering satellite platforms connected by subsea trunklines and pipelines. An in-field central complex receives all production for initial processing and transfer.

The field, operated by Zakum Development Company on behalf of its shareholder companies, has a strategic target to increase the production rate from the subject field reservoirs by approximately 40% by 2015, and to maintain the new plateau rate for 25 years. Initially the development plan to achieve these targets was founded on a continuation of the past surface development approach (i.e., to install additional WHPTs). It was estimated that more than 20 WHPTs would be required to cover the new production-/injection-well requirements, together with several hundred kilometers of flowlines. Major facilities upgrades on existing satellites and on the central processing platform also would be necessary. Inherent in these development plans was the added requirement to increase the jackup-rig fleet to achieve the necessary production-buildup rate.
Characterization of Hydraulically Induced Fracture Network in a Tight Gas Formation Using Treatment and Microseismic Data
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125237, "Characterization of Hydraulically Induced Fracture Network Using Treatment and Microseismic Data in a Tight Gas Formation: A Geomechanical Approach," by Wenyue Xu, Joël Le Calvez, and Marc Thiercelin, Schlumberger, prepared for the 2009 SPE Tight Gas Completions Conference, San Antonio, Texas, 15-17 June. The paper has not been peer reviewed.

Large amounts of gas are produced from unconventional tight-gas-sand reservoirs (e.g., Cotton Valley, Lobo, Taylor Sand, and Wilcox formations) and gas-bearing shale formations (e.g., Barnett, Fayetteville, Marcellus, and Woodford). These plays are driven partly by technology and partly by economics. Modern well-log-evaluation techniques and completion methods are required to yield economical wells. In some cases, microseismic-monitoring campaigns are performed in these low-permeability environments to improve the understanding of the induced-fracture network and to go beyond the simple assumption of a symmetric biwing-fracture system.

Introduction

Use of traditional models, assuming single- or biwing-type induced fractures, has produced successful hydraulic fracturing in conventional reservoirs. However, these models cannot represent the complex nature of induced fractures in unconventional reservoirs with pre-existing fractures. The otherwise straightforward propagation of a simple wing-like hydraulic fracture tends to interact with nearby pre-existing natural fractures. There are indications of microseismic activity being related to stress effects and to actual fluid movement. In some cases, a volumetric hydraulic-fracturing process is indicated. Recent efforts have been made to map the pattern of induced-fracture networks on the basis of observed microseismic-event distribution. These interpretations were not constrained closely by accounting for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures.

Fracture-Network Model

To characterize the induced-fracture network better, a semianalytical pseudo-3D geomechanical model was developed on the basis of the conservation of injected-fluid mass and mechanical interactions between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically equivalent description of the process of hydraulic-fracture propagation and the characteristics of the induced fractures.
Implementation of a Drilling-and-Completions Advanced Collaborative Environment - Taking Advantage of Change
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 123801, "The Implementation of a Drilling-and- Completions Advanced Collaborative Environment - Taking Advantage of Change," by S.J. Sawaryn, SPE, S. Goodwin, A. Deady, SPE, C. Critchley, and B. Swanson, SPE, BP plc, prepared for the 2009 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 8–11 September. The paper has not been peer reviewed.

Advanced collaborative environments (ACEs) were planned as an integral part of the operator's new Aberdeen office. The move, in early 2008, coincided with a major business reorganization that prompted a critical reassessment of their scope and functionality. The selected approach is well suited to operations in a mature area. During the pilot project, three ACE implementation types were tested. By June 2008, seven rigs were being supported simultaneously, including monitoring the progress of a wired-pipe trial in Trinidad.

Introduction

The operator's North Sea activities involve both planning and day-to-day management of platform, mobile-rig, and land-rig operations. The assets on which the rigs operate are in various stages of maturity, with older assets characterized by aging infrastructure and infill-well drilling to reservoirs that are progressively smaller. For these assets, any new drilling activity must fit into the ongoing maintenance schedules, and managing the personnel on board (POB) is critically important. Moving traditional rigsite activities onshore and use of collaborative environments played an important role in the success on the Andrew platform.

Drilling and completion activities are more data oriented than ever before, and the same information and understanding is needed at both ends of a conversation. Through collaboration, the life of older assets can be extended, and events can be used to learn and to influence development and operations on younger assets. ACEs, therefore, have a critical role.

Project Mercury

Project Mercury was established to manage all aspects of the operator's new building, including design and implementation of the operations and drilling ACEs. The Andrew onshore operations center (OOC) had demonstrated the value of collaborative environments for POB management, but had not attempted to address the additional needs and issues that might arise with the use of OOCs to improve drilling performance. An earlier comparison of OOC concepts in the North Sea categorized them according to the degree of technical and sociotechnical content involved in the change and the degree of integration across projects or disciplines. Given the wide range of choices, the Project Mercury team elected to pilot various configurations before selecting one for implementation in the new building.
The Judgment-Elicitation Process for Multicriteria Decision Making
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 12502, "Judgment Elicitation Process for Multi-Criteria Decision-Making in Oil and Gas Industry," by Lev Virine, SPE, Schlumberger, originally prepared for the 2008 International Petroleum Technology Conference, Kuala Lumpur, 3–5 December. The paper has not been peer reviewed.

Decision making related to oil and gas exploration and production relies on objective data analysis as well as on the subjective judgment of experts. Expert judgment often is considered to be less accurate than objective data analysis. By improving the judgment-elicitation process particularly in the case of multicriteria decision making, it is possible to improve the quality of critical decisions. Proper use of judgment-elicitation techniques together with objective data analysis will lead to significantly better decisions related to oil and gas exploration and production.

Introduction

Uncertainty assessment in the petroleum industry can be performed on the basis of objective information, such as using analogs or actual production data, as well as by interviewing experts. Traditionally, expert judgment has been considered to be less accurate than objective data analysis because of inherited biases. However, recent research shows that subjective expert judgment can be accurate as long as it is elicited properly. In other words, the experts need to be asked the proper questions in a proper order. The judgment-elicitation process should be designed properly for the particular problem.

There are two types of biases: cognitive and motivational. Cognitive biases show up in the way we process information. In other words, they are distortions in the way reality is perceived. There are many forms of cognitive bias, but they can be separated into a few groups:Behavioral biases influence how beliefs are formed. An example is the illusion of controlling something that we cannot influence. Another example is our tendency to seek information even when it cannot affect the project.Perceptual biases can skew the ways we see reality and analyze information. An example of one of the more common perceptual biases is overconfidence. Many project failures originate in our tendency to be more certain than we should be that a certain outcome will be achieved.Probability and belief biases are related to how we judge the likelihood that something will happen. This set of biases can especially affect cost and price estimates.Social biases are related to how our socialization affects our judgment. It is impossible to find anyone who manages an oil and gas exploration and production project in complete isolation.Memory biases influence how we remember and recall certain information and can affect judgment elicitation. An example is hindsight bias ("I knew it all along").
Engineers Australia A National Forum
Authors: JPT staff _
Published: February 2015

Editor's note: SPE seeks to develop strong relationships with other oil and gas societies worldwide. Many of these societies partner with SPE and other organizations on conferences, workshops, and other programs, at both the local and international levels. This series offers an overview of some of these societies. This fourth installment in the series spotlights Engineers Australia, more formally known as the Institution of Engineers Australia.

Engineers Australia is the national forum for the advancement of engineering and the professional development of its more than 85,000 members. It is the largest and most diverse professional body for engineers in Australia and embraces numerous engineering disciplines.

The not-for-profit organization was founded in the late 19th century as the need grew for a single body to represent the engineering profession, and its first council meeting was held in 1919. Today, the organization publishes books and journals, hosts numerous conferences and workshops, and actively seeks to make its position known on policy issues and government initiatives through policy statements, government submissions, and outreach to the media. It considers it a core activity to make its position known on public issues to raise the profile of engineers and to ensure that the views of practicing engineers are considered in government debate.

A National Congress, made up of 50 members, elects members to and monitors the Council of Engineers Australia. The council is the governing body consisting of nine members, and its role is comparable to that of a company board. The current national president is Peter Godfrey, a civil engineer with extensive management experience, and the chief executive of Engineers Australia is Peter Taylor. The organization has overseas chapters in Malaysia, Singapore, and the UK, and an "interest group" in the US.
Acceptable Returns: Technology Developers' Dilemma
Authors: Jacobs Steve
Published: February 2015

Guest editorial - No abstract available.
Q&A with Peter Bernard
Authors: Bernard Peter , Donnelly John
Published: February 2015

Q&A - No abstract available.
Techbits (November 2004)
Authors: JPT staff _
Published: February 2015

Techbits - No abstract available.
Dialog (November 2004)
Authors: Beeler Sam , Nooteboom Uri , Horvat Damir
Published: February 2015

Dialog - Discussion/Reply. No abstract available.
Spotlight on R&D: Meeting the R&D Needs for a Global HSE Challenge
Authors: Candler John , Norman Monica
Published: February 2015

Spotlight on R&D series - This is the sixth of a series of articles on the state of research and development (R&D) in the major upstream technological disciplines. The Spotlight on R&D Series, comprising articles published in JPT during 2004 and 2005, is available as a collection on OnePetro (SPE-101432-JPT).
Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90552, "Gravel Packing Deepwater Long Horizontal Wells Under Low Fracture Gradient," by Zhongming Chen, SPE, Rudolf J. Novotny, SPE, Rodrigo Farias, SPE, and Alfredo Mendez, SPE, BJ Services, and Carlos A. Pedroso and Lucia Helena C. Fernandes, SPE, Petrobras, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Productivity of Selectively Perforated Horizontal Wells
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 90580, "Productivity of Selectively Perforated Horizontal Wells," by Turhan Yildiz, SPE, Colorado School of Mines, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Overview: Drilling and Completion Fluids (November 2004)
Authors: Carter Tom
Published: February 2015

Overview - No abstract available.
Barite-Sag Management
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 87136, "Barite-Sag Management: Challenges, Strategies, Opportunities," by Paul D. Scott, SPE, Marathon Oil Co., and Mario Zamora, SPE, and Catalin Aldea, SPE, M-I LLC, prepared for the 2004 IADC/SPE Drilling Conference, Dallas, 2-4 March.
Environmental Aspects of the Use and Disposal of Nonaqueous Drilling Fluids
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 86696, "Environmental Aspects of the Use and Disposal of Nonaqueous Drilling Fluids Associated With Offshore Oil and Gas Operations," by H.R. Melton, SPE, J.P. Smith, SPE, and H.L. Mairs, ExxonMobil; R.F. Bernier, Chevron- Texaco; E. Garland, SPE, Total; A.H. Glickman, SPE, ChevronTexaco; F.V. Jones, SPE, Marathon; J.P. Ray, SPE, Shell Global Solutions; D. Thomas, SPE, Amerada Hess; and J.A. Campbell, SPE, OGP, prepared for the 2004 SPE International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Calgary, 29-31 March.
Modeling the Knowledge-Value Chain
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 87027, "A Study on the Modelling of Knowledge-Value Chain," by Yeong-Long Chen, Tzer-Chyun Yang, and Zsay-Shing Lin, SPE, National Cheng Kung U., prepared for the 2004 SPE Asia Pacific Conference on Integrated Modelling for Asset Management, Kuala Lumpur, 29-30 March.
Q&A with Abdul-Jaleel Al-Khalifa
Authors: Al-Khalifa Abdul-Jaleel , Donnelly John
Published: February 2015

Abdul-Jaleel Al-Khalifa is 2007 SPE President-Elect and Manager of Reservoir Description and Simulation in Saudi Aramco’s headquarters in Dhahran, Saudi Arabia. He is also serving as Program Chairperson of SPE’s first International Petroleum Technology Conference, to be held 21–23 November in Doha, Qatar.

Before his current assignment with Saudi Aramco, Al-Khalifa was Manager of Characterization–Exploration, and served as Assistant to the Vice President of Petroleum Engineering and Development, and he has held several division head assignments in the Reservoir Management and Simulation departments. In 1998–99, he served as an SPE Distinguished Lecturer on “Reservoir Management of Giant Oil Fields in Saudi Arabia.” In 1999, he received the SPE Middle East Regional Service Award, and in 2001, he was named an SPE Distinguished Member.

Al-Khalifa’s participation in SPE includes serving as a Director-At-Large on the SPE Board of Directors, 2005 Chairperson of the Board Committee on Technical Programs and Meetings, Director of the SPE Saudi Arabia Section during 1993–97, Technical Editor of SPE Formation Evaluation during 1991–92, and Chairperson of the SPE Annual Technical Symposium in Saudi Arabia during 1990–92. He also served as Technical Editor of the Arabian Journal of Science and Engineering during 1993–94.

Al-Khalifa earned BS and MS degrees from King Fahd U. of Petroleum and Minerals, Saudi Arabia, and a PhD degree in petroleum engineering from Stanford U.

As Program Chairperson of the first International Petroleum Technology Conference (IPTC) in Doha, can you offer a preview of some of the highlights of the conference?

This is the first international conference sponsored by the four premier societies: SPE, the American Assn. of Petroleum Geologists (AAPG), the Soc. of Exploration Geophysicists (SEG), and the European Assn. of Geoscientists and Engineers (EAGE). A very intensive program with broad appeal has been carefully designed by a talented team made up of members of the four societies to address the most challenging issues in today’s energy environment.
Cupiagua Uncertainties Offer Insight Into Piedemonte Exploration Prospects in Colombia
Authors: Tipping David E. , Saavedra Nestor Fernando
Published: February 2015

BP Colombia has been producing gas and condensate since 1996 from the heavily fractured Cupiagua reservoir, located in the Piedemonte area of Colombia, 195 km northwest of the capital city of Bogotá (Fig. 1). The field contains an extremely rich gas condensate with a yield of about 280 STB/MMscf. Field data confirm that the natural-fracture network in Cupiagua has a major influence on recovery and well production performance.

Although fractures apparently play a major role in the recovery potential of the field, it is very difficult to predict their behavior. For starters, reservoir data are not good enough to characterize fracture density and orientation in the formation more than 200 m from a well-bore. Hence, a multitude of fracture patterns are possible. Each pattern can lead to a recovery that differs markedly from the others. Secondly, on a practical level, it is not possible to create multiple detailed models representing the range of possible patterns in a realistic time period.

Ecopetrol, the Colombian state oil company, is directing its exploration efforts within the Piedemonte trend where the Cupiagua field is located. This is an area of extensive tectonic activity, so fractures are expected within the hydrocarbon structures. Ecopetrol seeks to benefit from the experience of BP with Cupiagua and is using the field as a benchmark for evaluating the potential of its exploration prospects. Instead of using simple volumetric methods and assumed recovery factors, which are notoriously unreliable under these conditions, Ecopetrol is building on the ideas used by BP to obtain better estimates of its potential in this region.

Cupiagua Field-Development Decisions

To maximize recovery and brake the decline, BP Colombia has implemented a gas-reinjection plan since early in the field life when the pressure was still above dewpoint. Injection above saturation pressure allows maximizing recovery from gas/condensate reservoirs.

However, with a voidage/replacement ratio of roughly 0.8, injection clearly cannot arrest the falling pressure. The average reservoir pressure is about 5,000 psia—significantly below the dewpoint, so condensate accumulation is widespread. Under these conditions, given the richness of the gas, the condensate saturation can exceed 35% of formation pore volume. Although gas injection is less effective below dewpoint, BP has pursued its injection strategy because the gas vaporizes a large fraction of the liquid, increasing recovery, and provides pressure support, boosting well rates.

Reservoir modeling reveals the potential gains achievable with injection. Under natural depletion, a maximum recovery of 18% of initial equivalent oil in place (IEOIP) is achievable. However, with gas injection, the recovery can exceed 60%. Furthermore, the modeling shows that this maximum recovery can be reached with the injection of less than 3 pore volumes of gas. Apparently, gas reinjection is the obvious development strategy.
Success Factors in Troll Geosteering
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17110, “Success Factors in Troll Geosteering,” by S. Leiknes and I. Osvoll, Norsk Hydro ASA, prepared for the 2005 Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.

Hydro has produced oil from horizontal wells in the thin oil layer of the Troll West field offshore Norway since 1995. The main challenge is to drain the thin target sands efficiently, within a remain-ing oil column less than 20 m thick covering an area of approximately 500 km2. New horizontal producers are continually being drilled. Vertical geosteering is performed on a centimeter scale, and quick decision making within the well teams is needed to optimize the well paths while drilling.

Introduction

The Troll field is the largest producing oil and gas field on the Norwegian continental shelf. The field is in the northern North Sea on the margin of the Viking graben and is divided by two major north/south trending faults separating the field into three provinces: Troll West oil province, Troll West gas province, and Troll East. Oil has been produced from horizontal wells in the Troll West oil and gas provinces where the initial oil-column thickness was 22 to 27 m and 11 to 13 m, respectively. More than 150 horizontal producers have been drilled in Troll West, and approximately two-thirds of the total oil reserves of 1.4 billion bbl has been produced. The oil column in Troll East is 1 to 4 m thick, and only the huge gas cap has been considered commercial.

New horizontal producers are drilled in the progressively thinning oil layer. As shown in Fig. 1, well planning and drilling are increasingly difficult because of the ever-larger number of existing producers, the consequent decrease in remaining targets, and movement of the fluid contacts resulting from production. Collaboration between geophysicists, geologists, and reservoir and production engineers is crucial to meet this challenging task.

Reservoir Framework

The reservoir consists of stacked, off-lapping, shallow marine sandstones and intervening siltstones mostly in the Upper Jurassic (Oxfordian) Sognefjord formation. Reservoir zones correspond to the finer and coarser portions of the prograding wedges (parasequences) and can be mapped with good confidence over most of the field.

For geomodeling and well-planning purposes, the depositional succession is simplified into clean sand and micaceous sands. The clean sands generally are well sorted, with permeabilities ranging from 1 to 30 darcies, while the micaceous sands are characteristically finer and silty, with permeabilities ranging from 10 to several hundred millidarcies.
Gas-Hydrate Production for Natural-Gas Storage and Transportation
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 93492, “Gas-Hydrate Production Technology for Natural-Gas Storage and Transportation and CO2 Sequestration,” by R. Masoudi, SPE, and B. Tohidi, SPE, Heriot-Watt U., prepared for the 2005 SPE 14th Middle East Oil & Gas Show and Conference, Bahrain, 12–15 March.

Gas hydrates (clathrates) are ice-like crystalline compounds that form under low temperature and elevated pressure conditions. Within the gas-hydrate lattice, water molecules form a network of hydrogen-bonded cage-like structures enclosing the guest molecules that generally comprise low-molecular-diameter gases [e.g., methane, ethane, propane, or carbon dioxide (CO2)]. Although hydrate formation can pose serious flow-assurance problems in the oil and gas industry, gas hydrates present a novel means for gas storage and transportation with potential applications in a wide variety of areas.

Introduction

The need for natural gas at lower costs is the challenge that drives the development of a new process for storing and transporting natural gas in the form of frozen hydrate. An important property of hydrates that makes them attractive for use in gas storage and transportation is their very high gas-to-solid ratio. In addition to the high gas content, gas hydrates are remarkably stable. When the gas hydrate, which is formed at a high pressure and low temperature, is returned to atmospheric pressure, dissociation begins at the surface and an ice film forms over the water that covers the surface and prevents further hydrate dissociation. This “self-preservation” effect causes the gas hydrate to remain stable at atmospheric pressure. These properties make natural-gas-hydrate (NGH) technology very attractive for natural-gas storage and transportation and CO2 sequestration.

Economics

For small- to medium-sized gas fields, hydrate technology is an appropriate alternative to the well-established liquefied-natural-gas (LNG) technology. LNG technology is economically feasible only in large-scale projects. Compared to alternative technologies such as LNG and gas to liquids, NGH technology is relatively simple, low cost, and does not require complex processes or pressure and temperature extremes. Capital cost of NGH technology is approximately 25% lower than the capital cost of LNG technology.

Hydrate Production

There are fundamental interests in continuous production of NGH in a large-scale reactor and effective long-term storage of gas in clathrates. NGH production accounts for more than 60% of the costs of the NGH chain. Development of an efficient technique that is practical and economical for mass production of gas hydrates is vital for realizing NGH technology. There are a number of technical challenges to be addressed in development of a cost-effective NGH production process.
Effect of Formation-Water Salinity on Water-Shutoff Gels
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93005, “Evaluation of the Effect of the Water Formation Salinity on the Performance of Gels for Water Shutoff,” by M.A. Llamedo, SPE, I.J. Fernández, D.L. Pérez, O. Rauseo, E. Valero, and J. Espinoza, PDVSA-Intevep, prepared for the 2005 SPE International Symposium on Oilfield Chemistry, Houston 2–4 February.

An acrylamide-based polymer cross-linked with organic reagents is commonly used in water-conformance treatments. This study tested the gel against water of various salinities. It was found that the gel swelled depending on the difference between the salinities of the water used to prepare the gel and that of the added water. The performance of this gel in porous media was evaluated by coreflood experiments.

Introduction

The aqueous gels prepared from crosslinking reactions of water-soluble polymers are used to reduce the formation permeability in water-conformance treatments. There still are many questions regarding the behavior of gel inside porous media. One question is how the reservoir fluid affects the gel. This work studied the influence of the difference between the salinity of the reservoir water and that of the water with which the gelling system was prepared.

Gel is an intermediate state between liquid and solid. As a result of this dual character, gels can exhibit intermediate properties between cohesion of the solid and transport of the liquid. The polymer network holds the liquid in place, and the liquid pre-vents the networks from collapsing into a compact mass. These gels have the capacity to swell or shrink according to the external media against which they are put in contact. A gel can swell or shrink when there are changes in the external environment (e.g., pH, temperature, and salinity).

Previous studies on gel swelling demonstrated that small changes in the external conditions, such as ionic strength or an external electric field, can induce drastic changes in the state of the swollen network. In particular, under certain conditions, poly-electrolyte gels may undergo a discontinuous volume change. The volume of gel is influenced by osmotic pressure.