bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of a Security Process
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 108621, "Development of a Security Process To Meet the Requirements of Oil and Gas Companies in the Asia Pacific Region," by Matthew Quin, Chevron, originally prepared for the 2007 SPE Asia Pacific Health, Safety, Security, and Environment Conference and Exhibition, Bangkok, Thailand, 10-12 September. The paper has not been peer reviewed.
Security risks are some of the most pressing risk-management concerns of oil and gas companies in the Asia Pacific region. There is a strong requirement to develop a standard process that allows oil and gas companies to both manage security risks and meet their business requirements in the various countries in which they operate. The process, once developed, needs to be integrated into all relevant aspects of the business. The security process should be developed as a core feature of the operations-management system, allowing all levels of the organization to understand how security management fits into the business structure.

Introduction
Because of our dependence on oil, energy security is one of the most important issues facing the world economy today. The most common image of energy security is that of meeting the increasing demand for energy by ensuring a constant supply to consuming nations. However, there is an aspect of energy security that looks at the threats to the energy supply, the protection of the energy- supply systems, and physical protection of the people and assets that make up those systems. This second aspect is very much the subject of attention of security professionals working within the oil industry.
Security departments traditionally have not been seen as profit generators or business drivers and, therefore, have not justified the close attention of business managers and have not been well understood by them. It was the events of 9/11 that caused a major shift, when major oil companies with operations in the Asia Pacific region started to scrutinize more closely their security preparedness regarding the physical well-being of their personnel and assets. In a short period of time, security departments had to transform themselves from little-known entities into credible and accountable business units.
Security departments of major oil companies working in the Asia Pacific region have had to adapt to best serve the interests of one of the security profession's most challenging industries. The Asia Pacific region has the fastest-growing power sector in the world and is likely to be a growth engine of the world's economy throughout this century. Energy sources in the Asia Pacific region are fast replacing the maturing fields in more traditional regions, making security of the energy sources in this region an important issue. An effective solution is to modernize the role of a security department within the organization by developing a business-related process that enables an oil company to integrate its security function with all relevant aspects of its business operations.
Tar-Sands Drilling-Waste Management: A Clean Solution
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112368, "Tar Sands Drilling Waste Management: A Clean Solution," by C. Nilsen, SPE, K. McCosh, SPE, and M. Kapila, SPE, M-I SWACO, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
The full-length paper presents novel technology for treatment of tar-sands drilling waste generated from steam-assisted gravity drainage (SAGD) and other tar-sands drilling operations. The continuous treatment process is based on hot-water addition, mixing, and separation techniques to reduce the viscosity and specific gravity of the bitumen to separate it from the sand. Treatment of cuttings with light to heavy bitumen contamination has shown this treatment method to be a simple and effective means of producing clean sand and recovering the bitumen component.

Introduction
Tar sands are sandstone formations saturated with bitumen or heavy oil. The sandstone is thought to remain water-wet in the formation and can be unconsolidated, with the sand grains held together mainly by the bitumen. Alternatively, the sandstone can be consolidated, with silica or carbonate cement holding the sand together and bitumen filling the remaining voids. The bitumen deposits were formed in the geological past from crude oil that migrated to the surface of the Earth. Weathering and chemical and biological processes resulted in loss of the light fractions, leaving behind the very-viscous, solid or semisolid heavy fractions. Typically, bitumen has a density greater than 960 kg/m3. Over the millennia, weather and geologic action covered the semisolid bitumen with layers of soil, and today, most bitumen and heavy-oil production comes from deposits buried more than 400 m below the surface of the Earth. Bitumen deposits are found in more than 70 countries worldwide, but 75% occur in Canada and Venezuela. In Canada, most of the oil sands are located in three major areas in northern Alberta, which hold at least 175 billion bbl of recoverable bitumen.
Where the heavy oil is thin it can be pumped out of the sands with progressing-cavity pumps (PCPs). To increase recovery, cold heavy-oil production with sand also is used in which sand is encouraged to enter the well by aggressive perforation and swabbing strategies. Removal of the sand with the heavy oil increases the formation permeability, expands the high-permeability zone as sand is produced, and prevents plugging of the near-wellbore region by asphaltenes or fines.
The Selfish Technology Gene - Discussion and Reply
Authors: Thuriaux-Aleman Ben , Thompson David 
Published: February 2015

Discussion
To the Editor:
In their guest editorial, "The Selfish Technology Gene," (April 2008) authors Robert K. Perrons and Lew Watts provide an interesting scenario in which oil and gas companies would keep their technology investments proprietary. Arthur D. Little believes that this oversimplifies the current situation. The industry is characterized by a range of technology strategies (Fig. 1) and, while there may be a shift towards increased proprietary technology, the industry cannot afford to develop all its own technology in-house and will need to think carefully about which technologies should be proprietary.
In our work on technology management, we have highlighted that companies need to balance ownership of their technologies with opportunities for value creation from their investments. Keeping technologies proprietary prevents companies from extracting the full value of their technology investments. Shell is a case in point—it has made significant progress in extracting value from its technology investments by making some of these commercially available.
Although third-party technology suppliers have not always been responsible for the invention of new technology, they have excelled at refining the technology. While this is often not counted as technological development, it has played a great part in bringing new technologies to the right price point and reliability, something the oil companies could not afford to do on their own. For this reason, we do not see service companies being threatened in the near future.
The comparison with investments for a fabrication plant for chip manufacture in the article is unhelpful. Microchip manufacturers keep their technology proprietary because it influences chip design and performance, key factors in an industry in which differentiation and performance are very important. But a barrel of oil is a barrel of oil. Oil and gas E&P companies sell commodity products, and technology investments serve to access resources or reduce production costs.
The key area where Arthur D. Little feels that technology will be kept proprietary is in the development of unconventional reserves. This is because there is considerable uncertainty about pay-offs from this area and the potential for technology development.
Ben Thuriaux-Alemán, Manager, Arthur D. Little, UK
David Thompson, Senior Manager, Global Energy Practice, Arthur D. Little
Comments: Fracturing Threat
Authors: Donnelly John 
Published: February 2015

Editor's column
Legislation introduced in the US could place heavy restrictions on the widespread use of hydraulic fracturing, resulting in higher drilling costs and production delays.
With a new administration and Congress in place, the US oil and gas industry appears to be facing a new era of regulation. Three Democratic congressmen introduced a bill in June that would eliminate an exemption for hydraulic fracturing under the federal Safe Drinking Water Act. Currently, individual states in the US regulate fracturing but not the federal government. The legislators claim that fracturing may be releasing harmful chemicals and contaminating underground water reservoirs.
No federal or state studies have concluded that fracturing contaminates the water supply or has caused health problems. The exemption for hydraulic fracturing was part of the 2005 energy bill passed by Congress during the Bush administration and followed a US Environmental Protection Agency (EPA) report that found little or no threat to drinking water from fracturing. And in a report earlier this year, the US Department of Energy stated that "ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers."
The industry, including the American Petroleum Institute and the Independent Petroleum Producers Association, is gearing up for battle over regulating this common production practice. Fracturing is widely used in the US, and is critical in some of the country's biggest production areas, including the Haynesville, Barnett, and Marcellus shale plays as well as tight gas production in the Rocky Mountains region in the western US.
The proposed legislation could give the EPA power to limit the type of fluids used in hydraulic fracturing, control chemicals used in the practice, or prohibit hydraulic fracturing altogether. The proposed bill also would require companies to detail what chemicals or additives they use in fracturing, information that is usually considered proprietary. Fracturing fluids are generally water-based fluids mixed with additives to help the water carry sand proppant into fractures. Water and sand make up 98–99% of fracture fluid, with the rest chemical additives. The use of fracturing is one reason why shale gas production has become economically feasible in the past few years.
Eliminating the use of fracturing would cause a 45% drop in US natural gas production and a 17% decline in oil production within 5 years and continued declines after that, according to a study by IHS Herold. Restricting fracturing fluids would cut gas and oil production by 22% and 8%, respectively, while restricting chemical injection would lead to a 10% fall in gas output, according to the study. In addition, more regulation in this area would lead to higher costs, delays in drilling plans, and the possibility of litigation.
Lessons Learned from 2008
Authors: Al-Husseini Sadad I. 
Published: February 2015

Guest editorial
The year 2008 may go down in history as the year of many lessons learned but soon forgotten. For the oil industry, it is important to reflect on what in fact those main lessons were and what their relevance is to the future.
One answer should not surprise most oil professionals. The industry discovered that it had been operating at a production capacity plateau for several years and no longer can provide the supply elasticity required by global oil demand given the cost and complexity of the oil-supply chain.
The oil price surge that started in 2003 and collapsed in 2008 had its roots in 1998. At that time, oil prices had sunk to USD 10/bbl, which resulted in the drying up of capacity investment across the world. In time, low oil prices resulted in runaway oil demand that could not be matched by increases in supplies. This shortfall resulted in the rapid increase in oil prices that eventually contributed to the global recession and the price collapse of 2008.
Even though the industry returned to making massive investments between 2003 and 2008, it could not match the tide of rising oil demand. Ultimately, it was unable to exceed a production plateau of 85 to 86 million BOPD in spite of the best efforts by OPEC and non-OPEC producers alike.
The attendant surge in oil prices to USD 147/bbl was, therefore, hardly surprising given these structural realities. These oil-supply limitations could not help but fuel the speculative fervor and hedging that occurred in the financial markets.
In hindsight, all of these events should have been predictable. While the global economy can shift its rate of growth within months, the energy industry is too complex and too mature to respond effectively, even under the most favorable economic circumstances. Politics, logistics, basin maturity, and technological limitations all converge to create an oil-supply plateau that cannot satisfy the growth of unconfined energy demand.
The existence of this ultimate supply ceiling will not recede under the current prospect for reduced upstream investments. In fact, there are good reasons to believe that this production plateau will become even more restrictive in the coming years.

Preventing the Boom and Bust Cycle
This vicious circle of rising energy demand, finite energy supplies, and volatile oil prices will repeat until the oil industry comes to terms with the need for better energy planning. Forward oil-supply planning is, in fact, the only option for setting constructive energy policies that can begin to facilitate the management of oil-price volatility.
Techbits: Efficiency Improvements for Facilities Focus of Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
Innovations aimed at improving efficiencies in surface facilities were the focus of an SPE Applied Technology Workshop (ATW) titled "Surface Facilities: Improving Efficiencies in Production, Energy Conservation, CO2 Reduction, and Waste Management" held in Dubai. More than 50 attendees from 25 companies and 16 countries reviewed the challenges of oil/water/gas separation, conservation, emission, and waste management in the backdrop of increasingly stringent regulatory requirements.
Abbas Ahmed Yousef, field manager for Adco's Bab field, opened the ATW with a keynote address focusing on the means to improve surface-facility efficiency, emphasizing the need for operators to adopt more enhanced oil recovery (EOR) techniques to improve production efficiencies. He also touched on the importance of energy conservation and emissions and waste management, particularly as producing fields mature.

Oil/Water/Gas Separation and Handling
In the ATW's first session, Ahmed Abdulmajeed of Saudi Aramco discussed process enhancements in gas/oil separation plants within his company. He reviewed how a new mixing valve for wash water going to desalters was able to reduce wash water consumption from 50 to 30 gallons per minute, resulting in more than 10 million gallons of water savings over one year. He also discussed how the implementation of a smokeless, high-pressure air-assisted flare system, which employs a new flare-tip design and additional flare-tip shield, provides for better gas combustion. Saudi Aramco is also testing an in-line water separator that promises to remove approximately 70–80% of water without the need to treat in a gas/oil separation plant and with quality in the range of 22–35 ppm of oil in water.
Alexander de Kruijf of Petroleum Development Oman (PDO) discussed the pitfalls of improper oil and gas sampling and made predictions on future process-equipment design. Inaccurate measurement of H2S in one PDO application led to deteriorating sales gas quality, with H2S concentrations reaching 5 ppm. The result was 4 months of deferment equivalent to approximately 100,000 BOPD. To prevent acid corrosion in equipment, de Kruijf stressed the importance of routinely measuring for organic acid, using corrosion-resistant alloys with increased corrosion allowances, and implementing organic pH neutralizers. In general, he advised that production chemistry programs should be an integral part of a project's process.
Oliver Garnier of Total reviewed a strategy to maintain production from his company's mature Abu Al-Bukhoosh field. The field has been producing since 1974, and present production is 15,000 BOPD with an average basic sediment and water (BS&W) of 86%. By implementing improvements, including increasing the impeller size in the gas recovery compressor, closing wells with too high a BS&W, optimizing well productivity by using multiphase flowmeters, and implementing de-emulsifier injection with gas lift, Total has managed to level the oil production potential to above 16,000 BOPD since 2007.
Efficiency Improvements for Subsea Operations in Deepwater Angola
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119651, "Improvements in Efficiency for Subsea Operations in Deepwater Angola," by Jason Zook, SPE, ExxonMobil Development Company, and Arran Keith, Swift Technical Group, originally prepared for the 2009 SPE/ IADC Drilling Conference and Exhibition, Amsterdam, 17–19 March. The paper has not been peer reviewed.
Esso Exploration Angola Limited (EEAL) has realized substantial improvements in the efficiency of subsea operations in the deepwater environment of Angola Block 15 (AB15). EEAL has increased its efforts to improve efficiencies for subsea operations, specifically during simultaneous operations. Improvements in efficiency and schedule certainty were realized as a result of dedicating a work vessel primarily to subsea operations. The full-length paper presents case histories of various operations and discusses the effect on efficiency of a dedicated work vessel.

Introduction
EEAL along with coventurers is developing several fields in AB15, 145 km west of Soyo, Angola, and approximately 386 km northwest of Luanda. Water depths range from 700 to 1435 m. Exploration rights were awarded in 1994, and drilling began shortly thereafter. AB15 currently is producing from five floating production, storage, and offloading (FPSO) facilities. The Kizomba C development project, which supplies FPSOs Mondo and Saxi-Batuque, is under way, and a Kizomba Satellites development project is in the planning stages.
To bring these developments on line in the timeliest manner possible, as many as six rigs have operated simultaneously on the different fields within AB15. Two of these rigs are tension-leg platforms, and the remaining rigs were mobile offshore drilling units (MODUs) working on a drilling schedule of more than 100 subsea wells distributed amid 18 subsea drill centers. This high amount of activity within the block created the potential for large schedule conflicts as a result of installation-vessel and MODU simultaneous operations.
In response to these potential conflicts, EEAL evaluated operations to identify which nondrilling tasks could be separated from critical-path MODU operations. Removing these tasks from the MODU schedule increased schedule flexibility and decreased cost.

Suction-Embedded-Plate-Anchor (SEPA) Installation
Early in the project planning for the AB15 development, drill centers were planned in close proximity to one another to enable the most cost-effective subsea architecture. The decision was made that AB15 would use one or possibly more conventionally moored MODUs for its subsea development wells. To achieve such a subsea layout and its related cost savings, the anchor pat tern of a conventionally moored MODU must become more compact. This more-compact anchor pattern required the use of taut-leg-mooring (TLM) systems to allow a MODU to moor safely over drill centers set relatively close to each other.
Technology Focus: Health, Safety, and Environment (August 2009)
Authors: Veil John 
Published: February 2015

Technology Focus
Health, safety, and environment (HSE) considerations continue to be integral parts of all sectors of the oil and gas industry. The health and safety of the industry work-force as well as of residents in producing regions are of paramount importance to the continued viability of the industry. In a recent example of an international health issue, the April 2009 emergence of a rapidly disseminated strain of swine flu created great concern around the world. Oil and gas industry personnel travel frequently between countries and can contribute to spreading of diseases.
Last year I commented on the safety challenges of keeping up with the strong drilling demands resulting from high oil prices. This year offers a new set of challenges. With lower oil prices, companies may have cut back on some activities and programs. Hopefully, safety and environmental programs will remain as important and central elements of everyday work.
Industry performance in traditional air- and water-quality and waste-management programs remains very important. Overlain on these are highly visible global issues such as climate change and carbon capture and sequestration. Projects for injecting carbon dioxide into underground formations will need to draw on the decades of expertise in the oil and gas industry.
Previously, I have written about the challenges of selecting a small number of top papers to represent three separate disciplines (health, safety, and environment). My own work focuses only on environmental issues. This year, I enlisted the assistance of Tom Knode of Halliburton to help identify the top papers in health, safety, and social responsibility, which are areas within his scope of responsibility.
Health, Safety, and Environment additional reading available at OnePetro: www.onepetro.org
SPE 121065 • "The Use of Risk Analysis in Design: Safety Aspects Related to the Design and Operation of an FPSO" by Lars Tronstad, SPE, StatoilHydro.
SPE 118176 • "Health-Reporting System in the Oil and Gas Business" by Claudio Zappador, Eni, et al.
SPE 120973 • "Integrating Social Responsibility Into the Health, Environment, and Safety Management System" by Carolina Ortega Barrales, SPE, Occidental Oil and Gas, et al.
SPE 121104 • "Breakthrough Mobile-Water Treatment Converts 75% of Fracturing Flowback Fluid to Fresh Water and Lowers CO2 Emissions" by Aaron D. Horn, SPE, Newfield Exploration.
SPE 121050 • "Time To Protect: Layout Methodology for Safe SimOps in High-Pressure, High-Percent-H2S Facilities" by A. Blyth, Shell International.