bluuebunny/crossref_metadata_2025_split huggingface dataset:
Management: Information Security: Risk and Reward
Authors: Gauci Donald 
Published: February 2015

Information security is the bedrock of any information risk-management system, and oil and gas companies are becoming more adept at minimizing risk by bolstering these systems across their organizations. Information technology (IT) is becoming such an important facet to these businesses and their disaster-recovery and business-continuity planning that the security issues now often spread to the upper echelons of many organizational charts, even to boards of directors and audit committees.
In fact, the industry is seeing an increase in the number of executives in charge of company IT assets. Such arrangements play a powerful role in IT security and can result in strategically aligning IT-security issues with business objectives. Oil and gas companies should evaluate the following as global priorities when assessing information security:Integrating information security within the organizationExtending the impact of complianceManaging the risks of third-party relationshipsFocusing on privacy and personal-data protectionDesigning and building information security
Some of the regulatory changes that have taken place over the last few years, particularly related to the Sarbanes-Oxley Act in the United States, have caused companies to move from a reactive to a more proactive mode. While many energy companies still would rather spend capital on commodity assets than on information assets, they are slowly shifting as they recognize that information security is a top business driver. IT security is becoming a part of the discussion in the context of a company's priorities. Whether those priorities include adding new acreage or adding rigs, E&P companies are leveraging technology more and more, and, as that technology is leveraged, the need for IT security rises.

As Technology Is Leveraged, Risk Rises
As companies grow through expansion or from mergers and acquisitions, computer networks can multiply and expand like cell division. Gradually adding bits and pieces to a network, especially when knowingly or unknowingly commingling sensitive data, increases risks and elevates the need for IT security. Not long ago, petroleum engineers, for example, examined geology assets in a back room, working safely within a secured computer network. Today, more and more of these professionals are performing such work on broader company networks, a move that saves companies money, but also elevates the possibility of data being compromised.
The notion of E&P companies leveraging communications technologies is not new, but they are constantly breaking new ground where applications are concerned. Fiber-optic networks, for example, are commonplace, and energy companies are now investing billions of dollars to lay these systems in the Gulf of Mexico and at other offshore asset locations. They know that as they go out into deeper water, the fiber-optic network will offer better communications capabilities for current and future processing facilities and drilling activities.
Dynamic Depth Correction To Reduce Depth Uncertainty and Improve MWD/LWD Log Quality
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 103094, "Dynamic Depth Correction To Reduce Depth Uncertainty and Improve MWD/LWD Log Quality," by D. Dashevskiy, SPE, T. Dahl, A.G. Brooks, SPE, D. Zurcher, J.C. Lofts, SPE, and S. Dankers, SPE, Inteq, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24–27 September.
Accuracy of measurement-while-drilling (MWD) and logging-while-drilling (LWD) depth measurements can be improved by considering the dynamic variation in drillstring length caused by pipe loading under changing drilling conditions. A new method that uses surface torque, hookload, and temperature measurements was developed to determine force distribution in a drillstring and to compute apparent drillstring length. When available, downhole measurements of torque, weight on bit (WOB), and temperature are used to increase accuracy and robustness of the method.

Introduction
With longer and deeper wells in deeper provinces around the world and the use of drillpipe conveyance of MWD/LWD data, accurate depth measurements are critical. Depth accuracy is vital for calculating structural dip from borehole images, picking perforation points, and correlating geological units. Measured depth (MD) is used directly in the calculation of true vertical depth (TVD) (the primary depth used for reservoir delineation).
Errors in depth are difficult to detect with a single scalar measurement; however, comparing several logging curves with similar character (Fig. 1) can reveal these artifacts. Cross correlation and a depth "rubber-banding" technique are used to bring MWD/LWD measurements from different sources (even within the same bottomhole assembly) together, using measurements from the sensor nearest the bit as a reference. This method addresses the symptom, not the cause. Misalignment of curves serves as a good indicator of the formation-evaluation (FE) -measurements depth-placement uncertainty and should be used instead for validation of methods used to convert MWD/LWD data to depth logs.

Background
All data from MWD/LWD tools are referenced to time. The moment in time when every measurement value was taken is known. However, it is necessary to know where the measurement was taken. To determine where measurements are taken, the following are needed.The wellbore profile—wellbore location in space.The time/depth profile—the location (with respect to the wellbore) of the bit at each moment in time.
This information can be used to place MWD/LWD measurements along the wellbore and, hence, in space. The assumption that the time/depth profile represents the TVD of the bit (and hence logging-sensor depths) at any moment in time often is incorrect. Bit depth is seldom equal to the summation of lengths of all steel run in the hole and the hook-height displacement, in part because of forces acting on the string that cause pipe to stretch, compress, or buckle. All errors in measuring time and depth will affect the quality of MWD/LWD logs.
The Status and Future of Remote and Automated Drilling Techniques
Authors: Ogg Jeremy 
Published: February 2015

Technology Update
The drilling industry is on a diving board looking down at automation, and we in this industry are currently deciding whether to join the other industries in the pool. We know that our industry will not be the first to embrace automation, and we also know that we are surrounded by other industries whose application of automation is proving, or has already proved, to be successful. Automation has been so successful that it has breathed new life into these industries, often revitalizing the way they supply their product. The results are generally a larger volume of product supplied faster, with fewer errors, and with more process standardization. Does this sound familiar?

Remote Linking and Real-Time Modeling
A number of automated products and services are making headway in the drilling industry, and this article will focus on two technologies of note.
DrillLink, developed by National Oilwell Varco (NOV) / M/D Totco, is a remote-linking automated control technology consisting of a device that facilitates the transmission of remote signals to the control system of a conventional drilling rig (Fig. 1).
Drilltronics, developed by the International Research Institute of Stavanger (IRIS) and NOV, is a drilling information technology that performs real-time modeling to improve drilling efficiency significantly (Fig. 2).
Logically, a crucial step in the drilling-process automation will occur as these types of technologies become capable of providing input for the other's output—where instructions can be communicated from one device to another to dictate operations. Are we at that point now? No. However, all the parts are developing that will make the whole. Conceptually, before we can automate commands on the basis of modeling, it first is necessary to determine whether commands derived manually can be automated.

Automated-Command Technology Tested
In 2004, MD/Totco and Schlumberger successfully drilled at a test rig in Cameron, Texas, by means of commands sent from Cambridge, UK, using the remote-linking automated control system already described. Achieving 100% success with the communication protocol, the Cambridge scientists were able to successfully control the weight on bit, flow rate, and the revolutions per minute of routine drilling operations of a rig more than 4,500 miles away.
Fundamentally, this technology places a communication box between the existing throttle signal from the drill-floor and the input to the power-control system that drives the rig. This box provides a means for the driller to allow control by a remote directional driller, regardless of whether the directional driller is at the rigsite or in an office anywhere on the globe. The driller remains in control, setting a maximum throttle that cannot be exceeded by others. Additionally, the driller has the ability to override the directional driller's signal at any time simply by changing the throttle on the console or turning off the linked system, thereby ensuring that ultimate control always remains on site.
Evolving Subsea Technology Tackles Huge New Risks of Today's Projects
Authors: Parshall Joel 
Published: February 2015

As oil and gas development projects tackle some of the world's most remote locations and extreme environments, pushing out into 8,000 ft water depths or beyond and going several hundred miles offshore, innovations in subsea technology will play a vitally important role in enabling the execution of these projects and will form the basis of future, even more-ambitious plans.
Subsea technology comprises wellhead and related production infrastructure placed on the seafloor, rather than on a conventional surface platform, a spar, or a semisubmersible or other floating production facility. Subsea wells and infrastructure are tied back by flowlines, risers, and umbilicals to surface producing facilities that may be directly overhead or many miles away, possibly even onshore.
While deploying subsea technology can be very expensive, as water depths increase, conditions grow harsher, and locations become more remote, the alternative of building a larger, heavier surface facility to hold the wellheads, pumps, separation equipment, and other infrastructure is often more expensive, sometimes prohibitively.
"There are two things that drive much of the move toward subsea," said David Morgan, Director, Subsea Processing, Cameron. "One is cost, the other is the reservoir. Typically, you must have at least one surface facility for drilling, processing, or storage. But surface facilities are a huge expense, and reservoirs sometimes are very spread out, making it hard to drill from one surface facility. That starts to drive multiple drill centers or the move to subsea development. By minimizing the size and number of surface facilities, you can save your project a lot of money."
On the one hand, when equipment is placed on a surface facility, maintenance and interventions typically are conducted from that facility, and costs are easier to project and control—compared with contracting costs for a rig or vessel to service subsea equipment. On the other hand, space is at a premium on any kind of floating facility, and the need for additional equipment (e.g., separation, water-handling, and compression facilities) as a project matures is difficult to accommodate by retrofitting late in field life. By installing the additional equipment subsea, the need for platform changes can be minimized.
"How effective we are at developing subsea technologies and evolving existing technologies is going to be an indication of how successful we are in recoverable reserves and maintaining our increasing production globally," said Neil Holder, Vice President, Sales and Marketing, Aker Solutions. "More and more companies are looking at stranded gas, offshore oil, and resources in the Arctic with long tieback distances that without subsea technology can't be accessed at all. So it becomes a facilitator."
Autonomous Systems Improve Production
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112078, "Improving Production by Use of Autonomous Systems," by Jorn Olmheim, Einar Landre, SPE, and Eileen A. Quale, SPE, StatoilHydro, prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.
Several companies have reported a 2 to 5% increase in oil production, and in some cases up to 10%, by use of a closer collaboration between onshore-based production-optimization groups and offshore personnel. The concepts of variable and delegated autonomy from the domain of unmanned flight were applied in StatoilHydro's production process. Compared with traditional automation, the concepts of delegated and variable autonomy introduce negotiation between different subsystems and a more-adaptable human/machine interaction.

Introduction
The industry trend is toward increased instrumentation and the use of smart-well technology for new developments. This trend has increased information flow into the control room, presenting new challenges with respect to use of this information. Other industries have shown that increased information flow can contribute to information overload and lack of shared-situation awareness between key stakeholders.
In the control room of a large installation with 100 wells and each well producing 15 different signals, 1,500 different signals must be processed at any given time. Humans are not able to process this flood of data rapidly and efficiently. An objective of integrated operations is better use of technical experts, independent of location. Therefore, shared-situation awareness between control-room operators and remote experts is a pre-requisite. Achieving the required level of situation awareness can be assisted by an increased level of computerized support that is able to analyze complex data streams and transform raw data input into events and derived recommendations for further analysis and action.

Production Practices and Challenges
Production planning is based on an agreed production target or profile, in accordance with the field's drainage and injection strategy, or on a delivery-contract obligation. The individual well's contribution at any given time will depend on the required production rate as well as other factors such as limitations on wellhead or downhole pressure, sand-production potential, equipment restraints, coning/cusping conditions, and velocity restrictions. Also, total production to a facility will be dictated by the available handling capacity for the different fluid phases and export requirements, as well as by necessary maintenance work. A facility's production profile generally will be characterized as "well-limited" (well potential is the limiting factor) or "process-limited" (the production facilities are the bottleneck).
Connector/Conductor Wells: Multiple Wellbores With Downhole Connections
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 111441, "Connector-/ Conductor-Wells Technology in Brunei Shell Petroleum Achieve High Profitability Through Multiwellbores and Downhole Connections," by Shaikhan Al- Khodhori, SPE, Petroleum Development Oman; Hamoud Al-Riyami and Philip Holweg, SPE, Brunei Shell Petroleum; and John Wright, SPE, John Wright Company, prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
Connector/conductor (CC) wells were implemented in Brunei. The conductors (feeders) are horizontal wellbores drilled through the oil rims, with the section of the wellbore above the top of the reservoir abandoned. These conductor wellbores act as horizontal flow conduits in the reservoir. Production to the surface is through dedicated connector (producer) wells designed to connect several conductor wellbores and provide shared completion equipment to surface. Success of the Darat CC-wells project proved technically feasible for implementation in other fields.

Introduction
The Champion West field has several oil rims that are displaced vertically and laterally from each other. The volumes in these rims are too small to justify a dedicated producing well for each rim. The CC-well concept shown in Fig. 1 was proposed to develop these marginal oil rims. Also, it was recommended that the concept be proved further in the Darat asset before full implementation in the Champion West field because Darat is a lower-cost environment, has less-complicated subsurface features compared with Champion West, and has existing suspended exploration wells for intersection and connection.
Fig. 2 shows the plan for the Darat CC well, where Well S-840 is a land well acting as the connector and Well S-833 is an offshore well acting as the conductor. Well S-833 was drilled at the end of 2005 and completed in November 2006, with two gravel-packed completion zones. The Darat CC well was to prove the following.The ability to "home in" and achieve a close proximity with the existing well of less than 40 cm at approximately 90° incidence angle without a plugback.The ability to connect the two wells (conductor and connector) mechanically and hydraulically and sustain sufficient flow through the connection.
Two technical challenges or key technology areas that were critical for success were improving ranging accuracy and making a hydraulic connection between the two wellbores.

Technical Solutions

Homing-in and Bypass Strategy.
Borehole-surveying instruments [e.g., measurement-while-drilling (MWD) and gyro technology] do not have sufficient accuracy to achieve the required trajectory and proximity to make a perforated connection. To close this gap, homing-in or ranging technology would be required. Two techniques were selected: single-wire guidance sys-tem (SWGS) and rotating-magnet ranging system (RMRS).
Real-Time Fiber-Optic Casing Imager for Continuous High-Resolution Casing Monitoring
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 109941, "Real- Time Fiber-Optic Casing Imager," by M. Appel, SPE, D. Dria, SPE, J. Freeman, F. Rambow, SPE, and M. Shuck, SPE, Shell Intl. E&P, and B. Childers, S. Poland, SPE, and T. Dominique, Baker Hughes, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November. The paper has not been peer reviewed.
During the last few years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance. The full-length paper details recent advances in development of a real-time fiber-optic-based casing imager that is designed for continuous, high-resolution monitoring of tubular shape and enables determination of strain imposed on the tubulars. Small-scale and full-casing-size laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10°/100 ft and covers compressive and tensile axial-strain ranges from less than 0.1 to 10%.

Introduction
In many regions of the world, regular monitoring of casing deformation needs to be an essential part of the reservoir-surveillance program because reservoir compaction and other geological conditions can impart significant loads on casing, which can lead ultimately to loss of the well. By monitoring the shape of the casing or the strain imposed on the casing, data may be available at a sufficiently early stage to enable remedial actions to prevent casing damage. Continuously monitoring casing deformation in real time improves the understanding of compaction and other strain-related reservoir conditions, which is essential for optimizing production and reserves recovery.
Subsurface compaction and stress-change behavior can be investigated remotely by use of several indirect-measurement techniques. On land, subsidence monitoring in combination with microseismic detection, supported by tiltmeters and data derived from global-positioning systems, has been used to characterize reservoir compaction. Microseismic, seafloor pressure gauges, and seafloor tiltmeters give indications of changes occurring on the seafloor and subsurface. More recently, reservoir changes have been analysed using time-lapse-seismic techniques.
Real-Time Casing Imager (RTCI)
Considering the limitations of traditional in-well monitoring, a measurement technique was developed to measure real-time distributed strain and temperature along a well tubular with a very high spatial resolution. The technology is called RTCI and is based on fiber-optic technology. The main components of the RTCI include the following.A sensing fiber-optic cable attached to downhole equipment.A fiber-optic lead-in cable that would be run in the well with the downhole equipment and enables sending laser light to the sensing element of the fiber-optic cable.A surface interrogation unit designed to provide the laser light and to analyze detected signals.