bluuebunny/crossref_metadata_2025_split huggingface dataset:
Total Spreads Its Wings
Authors: Sheehan John 
Published: February 2015

Company Profile Series
Editor’s note: This is the fourth in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.
Integrated French energy giant Total is continuing to spread its wings as it focuses on liquefied natural gas (LNG), deep offshore developments, and heavy oil. The company is seeking to maximize production from its existing fields, while at the same time boosting output from a raft of new projects it is bringing on stream over the next 5 years.
Total has ambitious plans to grow oil and gas output by 2% per year and it is trying to strengthen its upstream arm through exploration, partnerships, and targeted asset deals.
Total is the fifth-largest publicly traded integrated international oil and gas company in the world and is divided into three business segments—upstream, downstream, and chemicals. It produces oil and gas in more than 30 countries, including Angola, Australia, Nigeria, Algeria, Canada, China, Russia, and Qatar.
Production of liquids and natural gas was 2.36 million BOEPD in the second quarter of this year, up 8% from the second quarter 2009, while total 2009 output was 2.28 million BOEPD. The company estimates that the share of gas in production will increase from 44% in the first half of 2010 to 46% in 2014.
Yves-Louis Darricarrère, president of Total’s Exploration & Production Division, said: “Total E&P wants to grow profitably and be one of the best of the majors. To achieve this objective, Total must maximize production from existing fields. This is being done by improving recovery rates from mature fields and by extending production plateaus. Technology and investment are the keywords here.”
He said the company plans to bring on stream a large portfolio of projects and that startups between 2010 and 2015 will account for 880,000 BOEPD of production (i.e., approximately 33% of Total’s production in 2015).
The main startups between 2011 and 2014 include Trinidad Block 2C, Islay in the North Sea, Usan and Ofon 2 offshore Nigeria, Halfaya in Iraq, Angola LNG, Bongkot South in the Gulf of Thailand, and Kashagan Phase 1 in the Caspian Sea off Kazakhstan.
“We must also focus on reserves replacement,” he added. “This means renewing Total’s portfolio by focusing on organic growth (ongoing exploration, access to discovered resources opportunities awaiting development), and completing it with selective acquisitions.”
Technology Focus: Reserves and Asset Management (December 2010)
Authors: Hinkle Delores 
Published: February 2015

Technology Focus
Reserves and resource estimation and asset management continue to be oil- and gas-industry topics with a high degree of interest. Asset management has evolved from simply making a decision about when to abandon an operation into a complex integrated evaluation of well, reservoir, and facility performance that includes continual real-time data collection and analysis. Complex fields, sophisticated completion techniques, and challenging economics combine to require detailed, ongoing asset management to achieve maximum asset value.
Reserves- and resource-estimation research has been dominated in recent years by the introduction of the SPE Petroleum Resources Management System and the US Securities and Exchange Commission’s modernized rules. Efforts within the last year have broadened to topics not affected by reporting regimes: to issues such as estimation of reserves and resources in unconventional plays and the application and use of probabilistic assessments. Explanations of the underlying concepts and properties improve, clarifying the reserves- and resource-estimation process and the ultimate use of the volumes for both external reporting and internal planning.
With both topics, the themes of flexibility and continuous improvement are repeated in numerous contexts. The papers summarized in this section represent only a small subset of the many informative papers presented recently and available from OnePetro.
Reserves and Asset Management additional reading available at OnePetro: www.onepetro.org
SPE 133768 • “Development and Application of an Improved Workflow for Developed-Reserves Forecasting” by P.A. Lyford, SPE, Santos Ltd., et al.
SPE 134602 • “A Process To Evaluate Unconventional Resources” by Phillip Chan, SPE, AJM Petroleum Consultants, et al.
SPE 128834 • “Well- and Reservoir-Management Project at Salym Petroleum Development” by Andrew Mabian, SPE, Salym Petroleum Development, et al.
SPE 128542 • “Greater Plutonio—Real-Time Reservoir Management in a High-Cost Deepwater Environment” by Dave Booth, SPE, BP plc, et al. (See JPT, September 2010, page 43)
Insight Into Integrated Reservoir Management Using a Top-Down Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 132621, ’New Insight Into Integrated Reservoir Management Using a Top- Down, Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field in the Middle East,’ by Amirmasoud Kalantari- Dahaghi, Shahab D. Mohaghegh, and Yasaman Khazaeni, SPE, West Virginia University, prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed.
Top-down intelligent reservoir modeling (TDIRM) integrates reservoir-engineering analytical techniques with artificial intelligence and data mining to arrive at an empirical, cohesive, and spatiotemporally calibrated full-field model. The model is used to predict reservoir performance to recommend field-development strategies.
Introduction
TDIRM attempts to provide insight into fluid flow in the reservoir by starting with field measurements such as well-production history and well logs. Other data such as core analysis, well tests, and seismic can be used to increase model accuracy. Although not intended as a substitute for conventional reservoir simulation of large complex fields, this approach to reservoir modeling and management can be used as an alternative to traditional reservoir simulation and modeling for cases in which performing conventional modeling is cost and manpower prohibitive. If a conventional model already exists, TDIRM may complement the conventional technique with an independent assessment of the reservoir/well data to optimize development-strategy and recovery enhancement.
In this study, TDIRM was performed on a giant complex oil field in the Middle East that has produced for a half-century. The reservoir has produced under natural depletion, with a strong waterdrive maintaining reservoir energy. The formation is a complex mix of clastics and carbonates of variable reservoir quality. This prolific reservoir has highly complex flow behavior.
Methodology
TDIRM uses accepted reservoir-engineering techniques such as decline-curve analysis, type-curve matching, (single-well) production-history matching, volumetric-reserves estimation, and calculation of recovery factors. These analyses are performed on individual wells. By use of statistical techniques, multiple production indicators [i.e., first 3-, 6-, and 9-month cumulative production and the 1-, 3-, 5-, and 10-year cumulative oil, gas, and water production and gas/oil ratio (GOR) and water cut] are calculated. To model the behavior of nondeclining-production characteristics such as GOR and water cut, intelligent decline-curve analysis is performed on GOR for which a negative decline is normal behavior. Intelligent decline-curve analysis is specific to TDIRM, and it is performed by use of an adaptive time-series-modeling technique that trains itself with existing data and predicts system behavior for a specific length of time into the future.
The Performance of Mud Motors With Two Different Bent Housings
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125858, ’The Performance of Mud Motors With Two Different Bent Housing on Drilling a Lateral Section of Horizontal Wells in North Dakota,’ by Andy Syahputra, SPE, Bill Blaschke, and Jerry Hudson, SPE, Halliburton, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed.
Drilling across two sections in a horizontal well in the Middle Bakken formation of North Dakota offers challenges and opportunities for improved well-construction performance. The wells in this area were drilled with three different hole sections after setting the 16-in. conductor at 60 ft. The lesson learned on three offset wells in this area found that a bend setting of 1.15° has contributed to reduce tortuous well paths, controlled dogleg severity, and stayed in a very tight target interval while drilling the lateral section of 10,000 ft along the hole.
Introduction
Many operators are finding success drilling horizontal wells to develop the Middle Bakken in the Williston basin, which is relatively stable tectonically as compared with other intracratonic sections. The Bakken formation comprises the lower, upper, and middle members. The middle member is the target of the current development and typically consists of silty sand-stone and very-fine-grained sandstone, which is very calcareous and slightly dolomitic in the zones with the best oil and gas shows. The full-length paper focuses on drilling and the performance of mud motors with two different bent housings on three different wells in North Dakota.
Discussion
The bent housing tilts the axis of the bit relative to the axis of the hole. Significant bit side force is achieved for a relatively small bit offset. This allows the bit to build inclination and/or change the hole direction when the rotary-table topdrive is locked and to drill straight ahead when the drillstring is being rotated. The number of round trips thus is reduced dramatically, provided that the correct bit [polycrystalline-diamond-compact (PDC) bit of six-bladed aggressive designs with durable cutting structure] and bottomhole assembly (BHA) are chosen. The BHA is provided with vibration tools with sufficient weight to be run to the shoe and drill to section total depth (TD) in slide or rotating mode of drilling.
The surface-adjustable bent housing allows an incremental adjustment of the bend in the motor from 0 to approximately 3°. This changes the magnitude of the side force generated at the bit while slide drilling and, as such, the achievable build and turn rates. As the bent-housing offset angle is increased, bit side force increases and it becomes more difficult to slide. In the rotary mode, it becomes more difficult to rotate.
Comments: The Prize, Updated
Authors: Donnelly John 
Published: February 2015

Editor's column
The history of the energy industry is a study in technical innovation, entrepreneurs, political figures, and how singular decisions changed not only the oil and gas industry, but also the world at large.
That history is captured particularly well in the writings of Daniel Yergin, chairman of IHS Cambridge Energy Research Associates. He recently published a sequel to The Prize: The Epic Quest for Oil, Money, and Power, which is titled The Quest: Energy, Security, and the Remaking of the Modern World. Published in 1991, The Prize told the story of the history of oil—the technologies, people, and politics that changed the modern world. The new book tells how the current modern energy world came to be and how it might look different in the future.
Much has happened since the first book was written—the conclusion of the Gulf War, the collapse of the Soviet Union, the wave of oil industry consolidation in the late 1990s, and the sharp growth in Chinese and other developing countries’ energy demand. Energy was greatly affected by or central to all of these events and will continue to play a leading role on the world stage, writes Yergin, who addresses several significant contemporary issues in the book:
Peak oil theory is nothing new and this is the fifth time in modern history that there has been widespread fear that the world is running out of oil. The first time was in the 1880s when oil production was primarily concentrated in the US state of Pennsylvania. But the theory greatly discounts the industry’s ability to innovate and invest as it finds new and better ways to develop resources.
The growth in shale gas production, and the use of technologies such as hydraulic fracturing and horizontal drilling, are one of the industry’s most significant advances and have permanently changed the global gas landscape in a remarkably short time. He believes the industry will continue to innovate and make progress to try to satisfy some of the public concerns about hydraulic fracturing.
One natural or geopolitical event can change the energy industry overnight. An example is the nuclear power accident at Fukushima in Japan earlier this year after a tsunami hit the country. That may have ended thoughts of a nuclear power renaissance meeting the needs of a growing global demand for electricity.
Concerns about energy supply, and energy demand, will continue to drive geopolitical discussion, including how nations can become energy secure from natural disasters and cyber security threats. And political discussion of climate change could significantly affect the world’s future energy mix.
Sometimes overlooked, he writes, is the promise of energy efficiency, which he believes “has the potential to have the biggest impact of all” in satisfying future energy demand. Both the industry and environmental groups agree that the issue is critical and it may become the “first fuel” in any future discussion of balancing global demand with climate change.
Cathodic Protection Custom Retrofit Ensures Integrity of Subsea Manifold
Authors: McKinnell Gordon 
Published: February 2015

Technology Update
Preventing corrosion on subsea architecture is critical for operators in their effort to maintain an asset’s integrity and extend field life. Failure to do so can lead to unscheduled maintenance, deferred production, and possible punitive costs should environmental damage occur.
Cathodic protection (CP) can be a cost-effective means of preventing corrosion and should be considered as part of any long-term integrity management strategy. With accurate datasets, it is possible to predict the most likely future state of a structure’s integrity, which aids in planning preventive measures.
When a CP system reaches the end of its design life, a retrofit system is often required to ensure that an asset’s integrity is not compromised. A recent example was a custom retrofit system designed, engineered, and supplied by Stork Technical Services to Marathon Oil for the cathodic protection of its West Brae field subsea manifold in the UK North Sea. The system needed repair and the measures had to be carried out without causing a major disruption to oil and gas production.
Developing a CP System
A CP system comprises an anticorrosion coating and either sacrificial anodes, the most commonly used subsea, or impressed current anodes with a power unit to drive them. A system is designed to operate for a fixed period, usually between 10 and 30 years. However, the extension of field life and addition of facilities to an asset can compromise the original design by increasing the surface area and members, which may reduce the effectiveness of the anodes installed as part of the original design.
The aim of a CP system is to polarize a structure as quickly as possible and maintain the optimum protection for the design life. When depolarization begins, the system has reached the end of its design life. Either a retrofit system is installed or the structure is allowed to operate in an underprotected state. Underprotection may be allowed because installing a new system may overprotect another connected component, and that could create other failure risks with a higher impact.
Overprotection and the materials used must be evaluated in the CP system design. Hydrogen blistering, cracking, and embrittlement can occur when a system is overprotected. Susceptibility to such damage depends on the structure and hardness of the metal in question. For example, super duplex steels are the metals most commonly affected by overprotection hazards in subsea oil and gas applications. As the supply of a high current at low voltage is central to CP, a proper consideration of the equipment and its use is essential to ensure that repeatability, historical traceability, and accurate measurement in the range of &lt;10 mV are achieved.
Ranking Production Potential From Key Geological Drivers - Bakken Case Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14733, ’Ranking Production Potential Based on Key Geological Drivers - Bakken Case Study,’ by Robin S. Pilcher, Jessica McDonough Ciosek, Kelsey McArthur, John Hohman, and Peter J. Schmitz, SPE, Hess Corporation, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November 2011. The paper has not been peer reviewed. Conference rescheduled to 7-9 February 2012.
The Bakken play is a complex, low-porosity/-permeability system with variable source maturity, reservoir pressure and temperature, and fluid type. Target reservoirs are thin and variably affected by subtle structure, faults, or natural fractures. Many horizontal wells with multistage completions will be required to develop the Bakken play. A method is presented to assess the underlying production potential of the reservoirs on the basis of key geological drivers. With an extensive well-log database, petrophysical uncertainty can be addressed and stock-tank oil originally in place (STOOIP) can be calculated and mapped.
Bakken Play
The Williston basin oil province was discovered in 1951, and the Bakken formation was formally described in 1953. First oil was produced from the play in the same year. However, most of the early vertical wells, with the exception of those in the heavily fractured Antelope field, proved uneconomical to produce. The Bakken play is a hybrid of conventional (although tight) reservoirs and continuous resource plays that require development by use of closely spaced horizontal wells and multistage-hydraulic-fracture completions.
Production Potential and Ranking Goals
Regional ranking of future drilling locations is inherently challenging because of the many geological factors involved, and is complicated further by the influence of drilling, completion, and production operations. Traditional ranking schemes try to describe the relative potential of acreage and provide empirical support for the ranking by correlating the resulting rank to some measure of production performance. The production measure may be either a cumulative volume over a certain time frame (e.g., 90-day cumulative production) or a modeled estimated ultimate recovery (EUR) for the life of the well. Horizontal wells and multistage completions are a relatively new technology in the basin, with short production histories. As a result, use of actual production or actual production normalized per hydraulic-fracture stage is preferred because EUR introduces more assumptions and unknowns. A minimum period of 90 days of production was used in this study. Calibrating the regional-ranking predictions to actual production data will, inevitably, prove impossible to match past performance because the producing wells are subject to rapidly evolving technology and to variations in drilling, completion, production history, and operatorship.
Twelve Steps To Engineering Safe Oil and Gas Facilities
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141974, ’Twelve Steps To Engineering Safe Oil and Gas Facilities,’ by J.E. Johnstone, SPE, and J.V. Curfew, SPE, Contek Solutions, prepared for the 2011 SPE Americas E&P Health, Safety, Security, and Environmental Conference, Houston, 21-23 March 2011. The paper has not been peer reviewed.
The safety of an onshore facility is a function of how safely the facility was designed. People are injured, and sometimes killed, when explosions, fires, and toxic-gas releases occur at oil- and gas-producing facilities that were designed without including measures that could have prevented such incidents. The safety of people and equipment must be considered and included along every step in the engineering and design of oil and gas facilities.
Introduction
Many wellsites, tank batteries, and production facilities are at risk because of design or installation errors. These errors may have occurred when the facility was built or because the facility had been enlarged or upgraded through the years. Lack of proper engineering design can lead to equipment failure, lost production, human injury, or harm to the environment. Design and equipment selection will affect the safety and health of perhaps generations of workers who will be working on and near the equipment.
Safe Facilities
When designing a facility for a discovery, companies may choose to make sure that all facilities are designed and operated in accordance with standards and good engineering practices and with regulatory requirements. The other choice is to make decisions that inevitably lead to equipment failure, personnel injuries, and environmental damage.
The full-length paper details 12 key areas for facility designers and engineers to include when designing facilities for safe operation. The following is a short summary of these areas that should enable designing and building safe facilities that reduce the risk of major incidents. See the full-length paper for citing of applicable recommended practices, codes, and standards.
Design-Standards Policy. Each producing company, no matter how small, must implement a policy regarding the use of industry design standards that can be articulated to the production and operations groups regarding how surface facilities should be built. Setting a design policy to use industry standards will reduce the risk of injury to personnel or the occurrence of an environmental event at the facility. Most industry standards and regulations were developed in response to safety-related events and continually evolve to incorporate lessons learned from other safety-related events. Building a facility to industry standards provides the user with industry-accepted safety criteria.