bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil and Gas: A Relationship Game
Authors: Donaldson Kevin 
Published: February 2015

Guest editorial
Supermajors. Multinationals. Integrated oil companies. These are all terms used to describe the world's largest energy companies. All inspire thoughts of market leadership, control, and power. For many years, that would have been a fair assessment of status. But are things changing?
A recent Financial Times article titled "The New Seven Sisters: Oil and Gas Giants Dwarf Western Rivals" sought to develop an industry consensus regarding the most influential energy companies outside of Organization for Economic Cooperation and Development (OECD) countries. Numerous industry executives were polled and their responses collated. The resulting list included Saudi Aramco, Gazprom, CNPC of China, the National Iranian Oil Company, Petróleos de Venezuela, Petrobras, and Petronas.
These companies are overwhelmingly state-owned and control almost one-third of the world's oil and gas production and more than one-third of its total oil and gas reserves. And the old seven sisters—now four companies as a result of industry consolidation in the 1990s—produce about 10% of the world's oil and gas and hold just 3% of reserves.
So if state-controlled oil companies have the power, does this mean that the international oil companies (IOCs) have had their day in the sun? Are these once-giants of industry now shadows of their former selves, facing a future of begging at the table of the mighty national oil companies (NOCs)? Sensationalists may suggest this to be the case, but not most well-informed industry commentators.
It is a fact, however, that NOCs are more influential today than ever before. Their control over the bulk of global supply, reserves, and projected demand growth inherently gives them economic and political power. But this is not the only reason for their increasing influence on the sector. They also have become much more active in the market.
This increase in activity has been driven by governments asking more of their NOCs as they strive to ensure national security and prosperity. NOCs are, as a result, required to leverage their advantageous energy positions to deliver the infrastructure development (both energy and nonenergy in nature), job creation, energy security, and secondary and tertiary industries their respective governments desire.

New Continues To Need Old
IOCs retain significant influence over the global energy arena, and they collectively represent some of the largest reserves holders, producers, and petrochemical manufacturers operating today. Perhaps more importantly, they are also the technology, intellectual-property, and project-management powerhouses of the industry. As such, IOCs bring a lot to the global oil and gas party. They are here to stay.
A Diverless Retrofit-Tee Hot-Tap GMA-Welding Method
Authors: JPT staff _ 
Published: February 2015

Technology Update
The basic principle of hot-tapping is to establish a new branch pipeline connection to an existing pipeline while the primary pipeline is under full pressure. This involves connecting the branch pipe, including a valve, to the primary pipeline. Usually, this is accomplished by means of welding or a mechanical clamp connection—cutting a hole in the pipe wall with a machine connected to the valve, retracting the cutting head, closing the valve, and disconnecting and recovering the cutting machine. The pipe branch then may be extended by means of spools and a tie-in to a new pipeline in the normal way. This strategy has been shown to be very cost-effective, compared with alternative methods, including shutdown and tie-in at ambient pressure conditions.
To date, for underwater applications, divers have been used to weld the branch pipe to the primary pipeline, and all installation and cutting operations also have been performed by divers. The cutting machines are essentially marinized versions of standard onshore hot-tap cutting machines and not optimized for the subsea application. This makes it diver-intensive, requiring the training and qualification of diver/welders in advance for the substantial welding job and operation of the cutting machine.
The primary focus of the remote hot-tap project has been the development of a novel design for a diverless installation, combining the use of a remotely installed mechanical clamp, providing the structural integrity and interface with the isolation-valve module and hot-tap cutting tool, and a "seal weld" made by remotely operated hyperbaric gas metal arc (GMA) welding inside the branch pipe (Fig. 1). The intention of the seal weld is not to provide structural capacity as such, but to make a highly reliable, "metal-to-metal" seal meeting at least the same quality standard as that which traditional manually welded hot-taps are meeting today.
The seal-welding qualification program has included work to demonstrate feasibility for up to 2000-m operation and a full, specific program for a potential 145-m application. The programs have included work on mechanical-property characterization and hydrogen pickup, and demonstration of repeatable hyperbaric-GMA-weld quality, even though it is not a structural weld as such. The new remote system will represent a substantial cost reduction because the vessel alone that is used for the remote equipment costs approximately half as much daily as a diver-supported vessel, even before diver-qualification costs are considered. More importantly, the system will extend the capability of the hot-tapping method beyond water depths limited by divers. The remote hot-tap welding tool is shown in Fig. 2.
Pazflor Project Pushes Technology Frontier
Authors: Parshall Joel 
Published: February 2015

In its latest campaign to push the deepwater technology frontier on Angola's prolific Block 17, Total has embarked on the Pazflor project. Proceeding under a concession granted by the Angolan national oil company Sonangol, and following upon industry milestones established by Total on the same block at Girassol, Dalia, and Rosa, Pazflor will feature several world firsts for subsea technology, includingFull-field gas/liquid (G/L) separation and liquid boosting systems at the mudlineHybrid boosting pumpsVertical-separator technology
Located approximately 93 miles offshore Luanda and 25 miles northeast of the Dalia complex, in water depths of 2,000 to 3,900 ft, the Pazflor development will bring four fields into production, Perpetua, Acacia, Zinia, and Hortensia, which were discovered between mid 2000 and early 2003 (Fig. 1). The project derives its name from the initial letters of three of those fields (Perpetua, Acacia, and Zinia) and the similar-sounding Portuguese word pasiflor, for passion flower. Thus continues the floral nomenclature on Block 17 established by Girassol (translated: sunflower), Dalia, and the Jasmim and Rosa subsea tiebacks to Girassol.
Like the earlier core developments, Pazflor will be produced by means of a floating processing, storage, and offloading (FPSO) unit. The hull of this processing behemoth will weigh 82,000 tonnes, while its 15 topside modules will weigh an aggregate 37,000 tonnes. Combined, the weight of 119,000 tonnes will make this one of the largest FPSOs in the world. Holding accommodations for 240 persons, the FPSO will process the oil produced by a system of 49 subsea wells that includes 25 producers, 22 water injectors, and two natural gas injectors. The total subsea production system, linked by a network of 109 miles of pipelines and 51 miles of umbilicals, will be spread over a vast expanse of 232 sq miles—some seven times larger than the city of Paris—and have a north/south axis of 19 miles (Figs. 2 and 3). The FPSO will have an oil-processing capacity of up to 220,000 barrels per day (B/D) and storage capacity of 1.9 million barrels, bringing the installed production capacity on Block 17 to more than 700,000 B/D.
The Pazflor project carries a budgeted cost of approximately USD 9 billion. Total, as operator, holds a 40% share in the project, with the remaining interests held by StatoilHydro (23.3%), Esso (20%), and BP (16.7%). Major contracts have been awarded to Daewoo Shipbuilding & Marine Engineering to provide the FPSO; a consortium of SBM and APL to provide the buoy turret offloading system; FMC to provide the subsea separation and production systems; and a consortium of Technip and Acergy to provide the risers, umbilicals, and flowlines.
Technologies Contributing to Increased Recovery
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 19418, "Technology Contribution to Increased Recovery," by H. Kjorholt, SPE, A.H. Jorgenvag, SPE, and S. Strom, SPE, StatoilHydro, originally prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The full-length paper focuses on the past and present strategy of StatoilHydro in developing and implementing improved-oil-recovery (IOR) technologies and lists the technologies that have been key to increased recovery and gives indications regarding the way forward.

Introduction
Increased reserves from IOR activities in mature fields often turn out to be the cheapest and fastest way for an operator to find and develop new hydrocarbons. Technology development is mandatory to increase reserves through IOR.
As an operator, StatoilHydro will not in this setting "sit back" and wait for suppliers to come up with new ideas. They want to define the type of technology required to meet their IOR ambitions and establish partnerships with selected institutes and service providers.
When the technology is deemed necessary by the research and development organization, business assets, and management of the company, the basis for starting a structured research-and-development program is in place. The next phase is to select the supplier. It is believed that the suppliers also will benefit from such cooperation because a successful project will result in a dedicated customer.
Fig. 1 shows how the ultimate recovery in a number of assets has increased since the projects were sanctioned. The average ultimate recovery for all StatoilHydro-operated oil fields today is approximately 50%. The recovery for developments based on dry wellheads is 10 to 12% higher than the recovery in subsea developments. Even though these numbers are high compared to a worldwide average, the objective is to increase recovery by an additional 1 billion bbl, corresponding to a major-field development.
Some important characteristics of IOR volumes in mature fields are the following.Their presence is verified (no exploration in the traditional sense is required).Significant infrastructure is already in place.The knowledge of the reservoir is far better than for new developments.The economic boundary conditions are well known.
The challenge is to get the oil out of the ground with acceptable cost. The key is to develop technologies that can enhance drainage efficiency.
There are no obvious factors such as reservoir properties or drilling challenges responsible for the gap in recovery between subsea and platform developments; it is solely a consequence of the present economic reality of operating subsea vs. from a fixed installation.
Multiwell Case Study - Increasing Oil Production in a Mature Field With Rigless Intervention
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 11644, "Increasing Oil Production in a Mature Field by Rigless Intervention-A Multiwell Case Study," by Vivek Garg, ONGC, and Shubhranshu Ashesh (now with Shell), SPE, Kapil Seth, SPE, and Amit Govil, SPE, Schlumberger, prepared for the 2007 International Petroleum Technology Conference, Dubai, 4-6 December. The paper has not been peer reviewed.
Reviving production from brownfields is a major focus for oil and gas companies. Workflow and procedures are outlined that were adopted to increase oil production from seven wells by use of rigless intervention on an offshore platform off the west coast of India.

Introduction
The field was discovered in 1987 and was put on production in 1994. The main reservoir is a Middle Eocene carbonate deposit characterized by vugs, dissolution channels, and fractures (both vertical and horizontal). Hence, high-permeability streaks provide conduits for early water breakthrough, which has been primarily responsible for the decline in oil production. The average water cut in the field is 80%.
The offshore platform posed a special challenge because of its proximity to two water-injector platforms. Injection-water accumulation in the drainage zone covered by the wells of this platform was determined by current temperature anomalies and salinity contrast between the formation water and the accumulated injection water in the vicinity of the wells. The challenge was to study the flow dynamics so that additional perforations in the bypassed section would yield water-free oil.

Method
The strategy included well diagnostics followed by workover intervention to increase oil production and reduce the water cut. Production logging identified the flow profile. Then, pulsed-neutron logging was performed where required to determine hydrocarbon (HC) saturation in the cased-hole environment. Integration of data from openhole logs, production logs, and pulsed-neutron spectroscopy helped identify depleted zones and zones of bypassed oil. Through-tubing isolation plugs were placed to isolate water-producing intervals. Oil in bypassed zones was accessed with additional perforations. Formation-water salinity was calculated from pulsed-neutron logging to identify zones of injection-water breakthrough. Such intervals were avoided when adding new perforations.
Seven intervened wells yielded a 53% increase in oil production to 2,708 BOPD. The average water cut of the platform decreased from 80 to 76%.

Candidate Selection
The objective of the operation was to increase oil production while minimizing water and gas production. Because no rig was available, operations had to be carried out with a modular skid unit, which constrained available tools and methods.
Increasing and Enhancing the Supply of Petroleum Industry Talent
Authors: Sprunt Eve S. , Simon Monique , Thorness Steve , Musson Paul 
Published: February 2015

Talent & Technology
Much has been written about the big crew change. Hiring and retaining the next generation is now a top issue for the industry. Energy supply and demand is one of the critical issues facing this generation. While alternative energies and conservation may mitigate some of the supply and demand challenges, petroleum will play a major role in powering societies for the foreseeable future. To meet this challenge takes people. And not just any people. It takes talented, highly educated, and motivated engineers and scientists to find, develop, and produce hydrocarbons.
Recognizing this people challenge, the SPE Talent Council was formed in 2007 to provide a forum in which industry, academia, and nongovernmental organizations could collaborate on initiatives to increase the quantity and enhance the quality of talent available to our industry. This involves increasing the number of students interested in the energy industry, enhancing the quality of educational programs worldwide, and encouraging graduates to pursue a career in the oil and gas industry.
To better understand what factors are important in the attraction and retention of young people, the SPE Talent Council had SPE Market Research conduct a survey of SPE members below the age of 35, who are not currently students. Invitations to participate in the survey were sent to 8,833 members in February and March 2008 and 1,711 (19.3%) responded. The distribution of the respondents’ regions of origin is shown in Fig. 1.
More than half of the respondents hold a minimum four-year university degree (52%), while another 40% hold master's degrees, and 7% have a doctorate. The most common university discipline is petroleum engineering at 46%, followed by mechanical engineering and chemistry/chemical engineering at 15% each. This discipline distribution is not surprising since those polled are all members of SPE. The next most common discipline for those who replied is geology at 5%. A multitude of disciplines make up the remaining 19%. Men are the overwhelming majority at 79% of the total.
Comments: Betting on Gas
Authors: Donnelly John 
Published: February 2015

Editor's column
ExxonMobil’s purchase of XTO Energy last month—one of the largest merger and acquisition deals this decade—is another sign that future prospects for gas appear brighter than ever. The supermajor’s buyout of a leading developer of unconventional gas resources in North America gives it a major foothold in what has become the hot E&P play of the moment.
In a panel session at last month’s International Petroleum Technology Conference (IPTC) in Doha, Thomas Walters, president of ExxonMobil Gas and Power Marketing, laid out his company’s view of the future of gas, a week before the XTO deal was announced. Gas demand will see strong growth over the next 20 years and resource holders must find new ways of developing supplies to meet this demand, he said. Presenting information from ExxonMobil’s 2009 Energy Outlook, Walters said that fossil fuels would continue to be the main energy source for decades and that gas demand would grow faster than demand for other hydrocarbons.
Global demand for natural gas will challenge the industry to deliver, from developing unconventionals such as shale to massive liquefied-natural-gas (LNG) projects, such as those that have been built in Qatar, panelists said during the IPTC session. Gas, in particular, will play an important role in the future energy mix because of its abundance, smaller environmental impact, and its desirability as a fuel for power generation.
Since its founding in the mid-1980s, XTO has grown by acquiring mature assets and expanding reserves through technology know-how. It owns large interests in major US shale, tight gas, and coalbed methane plays, and has reserves estimated at 45 Tcf of gas equivalent. ExxonMobil said it plans to create an upstream organization to manage global unconventional resources. Other companies are betting on a bright future for unconventionals as well. BP, Statoil, and Eni all have bought significant shale gas assets in the US in the past year. And Devon Energy announced in November that it was selling all of its Gulf of Mexico and non-North American E&P assets to focus on US and Canadian onshore. Devon holds key stakes in several of the largest US shale plays.
Although projects in North America have drawn the most attention, other regions have begun estimating the huge potential of unconventional resources. Poland has attracted the interest of Marathon and ConocoPhillips for potential shale development. Saudi Arabia is also eyeing tight gas and shale projects, Abdulla Al-Naim, vice president of Exploration with Saudi Aramco, said during IPTC. He predicted that the exploration staff of the future would be focused on unconventionals.
The rise of gas as a future fuel source continues to boost the prospects of a global gas producers’ association similar to OPEC. The 11 member countries of the Gas Exporting Countries Forum met in Doha during the week of IPTC to discuss strategy. Although gas has had limited scope as a global commodity, the growth of LNG has contributed to gas becoming a more fungible and less regional commodity.
Technology Focus: Mature Fields and Well Revitalization (January 2010)
Authors: Ali Syed A. 
Published: February 2015

Technology Focus
The focus on finding and developing new fields sometimes overshadows attempts to recover more hydrocarbons from brownfields. Nevertheless, innovative projects are being implemented around the world to revitalize mature oil and gas fields.
Every mature field has unique characteristics, and often several viable options are available for revitalization. Once a decision is made to implement a particular revitalization option, it is very expensive to change course and attempt an alternative solution. Therefore, it is imperative to minimize the risk of pursuing a wrong alternative. Simulations and pilot projects can generate data to narrow down options. However, economic constraints may limit actual data gathering. Thus, previous experience in revitalizing similar types of fields can be very leveraging.
Archived SPE papers can be used to identify and rank revitalization alternatives. These papers can provide useful details regarding the challenges and success of hundreds of revitalization techniques. Furthermore, recent SPE papers include current details on the use of best-available technology to revitalize mature fields effectively around the world. The revitalization techniques presented in these papers may be well-established techniques, but much can be learned by reviewing the approach taken to investigate potential solutions, the types of options considered, and the progression from ideas to realities.
Mature Fields and Well Revitalization additional reading available at OnePetro: www.onepetro.org
SPE 124605 • “Forties: Creating a Long-Range Development Plan for a Large, Mature, Complex North Sea Oil Field” by Alan Chesterman, Apache North Sea, et al.
SPE 122402 • “Optimizing the Development Concept of a Mature Gas Field in Intensive-Drilling Context: Tunu Field Case” by Bhayu Widyoko, Total, et al.
SPE 122338 • “Optimizing Horizontal-Well Placement and Reservoir Inflow in Thin Oil-Rim Reservoirs Improves Recovery and Extends the Life of an Aging Field” by G. Kartoatmodjo, Petronas, et al.
SPE 124647 • “Mature-Field Production Optimization Through Standardization of Operating Procedures for Reservoir Monitoring” by Vikas Bhushan, Shell, et al.