bluuebunny/crossref_metadata_2025_split huggingface dataset:
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 The paper has not been peer reviewed.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.
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.