bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Desander Removes Solids Without Deferring Well Production
Authors: Sherwood Colin 
Published: February 2015

Technology Update
As oil and gas fields mature, production of sand and other reservoir solids can become an increasing and sometimes major impediment to hydrocarbon production and facility operations. These solids can move through the wellbore into process facilities, causing flow assurance problems that affect system integrity, export line transportation, cleaning, and disposal. As operators seek to optimize production from mature assets, solids management is likely to take on additional importance. Sand and solids production can also be a problem on some new wells.
To address these issues, Stork Technical Services developed an advanced online desander (AOD) for managing separator solids, providing thermographic determination of sand accumulation, and enabling clean sand discharge to the sea, with no deferred production (Fig. 1). The system has been used successfully in eight deployments on the Hummingbird floating production, storage, and offloading system (FPSO), which supports Centrica’s Chestnut field, operated by Wood Group, in the United Kingdom North Sea.
Risks of Sand in Production Vessels
The presence of sand in production vessels reduces capacity and affects separation performance, which leads to deteriorating produced water quality and the carry-over of water in the oil phase. If not controlled, the sand can cause a separator to be taken offline and manually cleaned. This exposes facility crew members to process hazards and may damage downstream equipment.
Conventional sand management techniques require a shutdown of 10 to 14 days for manual sand removal, resulting in a significant delay and additional expense. Following this, oil-on-sand discharge rules may limit disposal options and compel storage of some or all of the sand.
The Online Desanding Technology
The desander is designed to allow more operator uptime and to reduce costs, compared with traditional vessel entry cleanout methods. With the new technology, there is no need to shut down production, and the elimination of manual cleaning improves safety. In addition, the technology enables operators to change their approach to planned shutdown periods. Because the system allows a high degree of cleaning to take place before shutdown, the team of technical experts needed for a shutdown can be smaller and planning for it simpler.
The system comprises a number of purpose-designed, integrated components including solids extraction, solids separation, and solids conditioning packages. A high-flow jetting unit with a recovered-liquid package recycles the separator water. The system complies with European Union hazardous area safety requirements and can be used in Zone 2 hazardous offshore environments.
The Keywords For Blowout Preventers Are Trust But Verify
Authors: Rassenfoss Stephen 
Published: February 2015

GE Oil & Gas displayed its new blind-shear ram, which is capable of cutting components older blowout preventers could not, at the 2012 Offshore Technology Conference.
Blowout preventers (BOPs) have become a constant concern. Periodic certifications of the equipment and maintenance used to be enough to ensure that this last line of defense would perform if needed. Now, users are constantly “wanting to know, is it ready?” said Chuck Chauviere, the general manager for drilling systems for GE Oil & Gas.
The question can be asked many ways. Is the BOP capable of cutting the pipe or connectors and sealing a blowout? Are the electrical and hydraulics systems working properly? Is the crew trained to quickly make the right decisions in an emergency? Will backup power and communications systems perform under extreme circumstances?
Much has changed in the 2 years since the Macondo disaster in which 11 people died; but, the process is far from over. A rewrite of the American Petroleum Institute (API) guidelines for BOP operations and maintenance, API 53: Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, was going through another round of revisions in mid-summer and could be published late in the year, said Roland Goodman, manager of upstream standards at API. The guidelines provide details needed to make changes in the sections of API 16 that cover BOP construction, testing, and recertification.
In May, the Bureau of Safety and Environmental Enforcement (BSEE) kicked off a push to write the first US BOP regulation with a hearing in Washington. Industry representatives got a taste of what is ahead when David Hayes, deputy secretary of the US Department of the Interior, said, “There are at least four things we are looking for in a new proposed rule:
“One, BOPs need to be able to cut whatever is in their way and completely seal off the well.
“No. 2, better maintenance for BOPs, like what you would expect of a jet engine or any other very sophisticated mechanical device upon which lives depend.
“No. 3, BOPs need better sensors to tell us what is happening at the bottom of the sea.
“No. 4, everyone working with BOPs should be fully and properly trained to handle any contingency.”
Key Elements of a Migrant-Worker Health and Welfare Program
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 151765, ’Key Elements of a Migrant-Worker Health and Welfare Program and Its Effect on a Major Construction Project,’ by Israr Ahmed and Herman Wirtz, Qatar Shell; Robin Patrick Donnelly and Alistair Fraser, Shell International; and Salvador Castillo, Qatar Shell, prepared for the 2012 SPE Middle East Health, Safety, Security, and Environment Conference and Exhibition, Abu Dhabi, 2-4 April. The paper has not been peer reviewed.
The Pearl gas-to-liquids (GTL) project required construction of a state-of-the-art hydrocarbon-processing facility with, at peak, 55,000 employed on site. The company created a worker health and welfare program, with a goal to enhance health and performance by creating a culture of care and concern for the wellbeing of workers throughout construction and to mitigate projected risks for a project of such magnitude.
Introduction
Traditionally, construction camps are high risk and high public exposure. There has been a historical tendency to leave the matter of construction-camp planning, design, and management to contractors, with associated risks of under-performance. It is unusual to find a holistic approach for camps that integrates the material aspects with quality of living conditions, action to create social cohesion, and an appreciation of overall worker welfare. However, the realization that there is an opportunity to go beyond compliance with design standards gave rise to a shift toward use of “behavioral and holistic interventions” to improve the safety culture and attitude among workers.
The worker-welfare program was born with the consideration of capitalizing on the caring aspect of safety. Particularly, the program envisioned to create a facility and community that show empathy for people, a place where members of a large multinational/multicultural workforce live happily and in harmony with each other, where they could enjoy high-quality fulfillment of basic needs and psychosocial support. Therefore, a holistic approach was used that aimed at delivering initiatives targeting the entire range of physical, emotional, mental, and even transpersonal needs of workers in a “high-risk” work area.
Theory
The challenge of making respect for people visible and objective in Shell’s practices was given further push in the area of health, safety, and environmental management. First, in the area of health management, it was imperative in building projects and in operations that controls and regulations be in place to protect and promote the health of employees, contractors, and neighbors by eliminating, reducing, or mitigating health risks in the workplace.
Managing Risk at Ground Level
Authors: Sajjad Joe 
Published: February 2015

Guest editorial
The term “risk management” is not new to the oil and gas industry, but its meaning continues to evolve to reflect changing challenges. For many, risk management might be synonymous with safety, or taking proper precautions to minimize the occurrence of an incident or unsafe condition. And while safety is a fundamental component of risk management, the concept also incorporates mitigating risks to service quality, productivity, and the environment.
Although the majority of companies in the oil and gas industry share a commitment to constantly improving their risk mitigation strategies, the execution is sometimes lacking. This is supported by statistics showing that the number of total recordable incidents in the United States upstream oil and gas industry has reached a plateau in recent years, despite the industry’s best efforts to lower them (Fig. 1).
It is perhaps human nature to take a reactionary approach to changing risk management strategies only after one or more dangerous and environmentally harmful events have occurred. In the past few years, however, operators and service companies alike have been changing their mind-set on risk mitigation by adopting a forward-thinking approach to managing safety, quality, and environmental threats.
This requires a fundamental shift in a company’s risk culture. With regard to safety, for example, many companies historically have fostered a compliance-based safety culture—one that stresses safety for the sake of complying with regulatory guidelines or passing an audit. With this mind-set, the ultimate responsibility for safety might fall to one or more health, safety, and environment (HSE) officers, who perform the audits, fill out a checklist, and point out unsafe practices. Soon after the audit is over, however, the temptation to drift back to the old ways of performing work may be too strong to resist.
Changing Behaviors
A preferred approach, which is gaining traction in the industry, is to build a behavior-based safety culture, one in which each worker is committed to performing his or her work functions with the highest regard to safety, even when no one is looking over his or her shoulder. This behavior-based approach should be supported by top executives, but must start at the ground level, with the rig crews and workshop personnel who are most immediately affected. Achieving this culture begins with empowering employees through a comprehensive training program that gives them the tools and leadership skills to perform their tasks safely, and to intervene when they observe an unsafe act.
New Test Probe Yields Key Reservoir Answers
Authors: Arman Kate , Martin Robin , Tevis Chris , De Santo Ilaria 
Published: February 2015

Technology Update
Extreme downhole conditions pose a challenge to formation testing. Acquisition of accurate reservoir pressure data and high-quality formation fluid samples has proved difficult in cases of low reservoir permeability, extremely viscous crude oil, or unconsolidated formations with poor borehole conditions. Opera-tors have often considered these wells untestable. When testing is possible, it is frequently time consuming and costly with the need to set and cement pipe, shoot perforations, and bring in coiled tubing to run the test. Even then, formation pressure estimates on such wells are frequently inaccurate.
However, a new tool has proved able to extend formation testing parameters to extreme formation and borehole conditions. The Saturn 3D radial probe (Fig. 1) developed by Schlumberger is a complementary module to the Modular Formation Dynamics Tester tool. The probe is capable of performing accurate pressure tests in fluid mobilities as low as 0.01 md/cp, and obtaining high-quality fluid samples in mobilities lower than 1 md/cp.
In Mexico, a friable sandstone reservoir containing 7.5 °API crude oil in extremely unconsolidated formations was successfully sampled by the 3D radial tool in a very rugose borehole with 12% ovality. The data collected would have been unobtainable with previous test assemblies and was critical for a sub-sequent thermal recovery design. Despite the difficult conditions, the new tool was able to conform to borehole irregularities to achieve and maintain a reliable hydraulic seal.
Formation Fluid Challenges
Acquiring representative samples of heavy, viscous crude is only part of the story. A North Sea operator took full advantage of downhole fluid analysis (DFA) to characterize viscous, biodegraded oil in a poorly consolidated field. The Catcher area fields, operated by Premier Oil on behalf of colicensees Cairn Energy and Wintershall, contain 300 million bbl of original oil in place, making them one of the most significant recent discoveries in the United Kingdom Continental Shelf. Six wells and three sidetrack boreholes have been drilled to date.
The fields are partly characterized by a series of sand injectites, overpressurized sediments that are remobilized and forced upward to intrude into overlying layers. Injected sands are typically characterized by high porosity and high permeability, which is why they are often considered as attractive hydrocarbon targets. However, injectites often range from poorly cemented to unconsolidated, which makes attempts to sample high-quality fluid very challenging.
EC-Drill Eliminates Effect of Equivalent Circulating Density
Authors: JPT staff _ 
Published: February 2015

Young Technology Showcase
When drilling offshore wells, the most common method is to drill with a single gradient fluid with the fluid column extending from the bottom of the well back to the drilling rig. Even in shallow water, this sometimes represents a significant challenge if the formation cannot withstand the hydrostatic pressure from the fluid column. An example would be drilling from a jack-up where hydrostatic fluid pressure causes fracture under the shoe of the conductor pipe.
As water depth increases, so do problems associated with having the fluid column all the way back to the rig. The effect of the water depth is particularly significant in the upper part of the well and, consequently, if it can be eliminated, drilling performance can be significantly improved. For this reason, the industry has been working with developing dual gradient drilling technology for decades.
Several methods can be classified as dual gradient drilling. The most common are the seabed pumping and mid-riser pumping methods. For seabed pumping, the drilling riser typically is filled with seawater and the drilling mud is pumped (or lifted) back to the rig from the seafloor. This represents a drilling method in which the effect of the water depth can be eliminated and the well basically drilled as if the drilling rig were sitting on the ocean floor. The same can be achieved with the mid-riser pumping method, but in this case, the riser is typically filled with a gas.
Another significant problem is the effect of dynamic pressure loss (friction) while circulating drilling mud through the wellbore in order to transport drill cuttings back to the rig. In deep water, the margin between pore pressure and fracture pressure is small; hence, there is a narrow drilling window. For static conditions, the mud must have a weight or density great enough to create a wellbore pressure that is above the pore pressure (static overbalance). When the rig mud pumps are started to circulate fluid around the well, the wellbore pressure increases as a function of friction and the pressure may exceed the fracture gradient (typically at the shore above) and result in lost circulation. This may again result in a kick. For low-pressure reservoirs or depleted fields, this problem is significant and may make the wells undrillable with conventional technology.
This dynamic effect, equivalent circulating density (ECD), is a significant drilling challenge in terms of safety and lost time.
Saudi Aramco Expands Reach Through New Technology Centers
Authors: Henni Abdelghani 
Published: February 2015

Saudi Technology Centers
Knowledge is power and technology is a game-changer. Those are the key maxims that Saudi Aramco says it is using to shape its strategy as it aims to become the world’s leading integrated energy and chemicals company by 2020.
“At Saudi Aramco, we are pushing forward from a traditional role as buyers and consumers of technology to our new global technology and R&D strategy. We envision becoming an enabler and creator of new technologies,” Khaled Al-Buraik, vice president of petroleum engineering and development at Saudi Aramco, said during the Offshore Technology Conference (OTC) in May in Houston. “There is new urgency as well as new optimism about where we are going. In the past we have been focused primarily on crude oil and gas; now we are progressing to become fully integrated in gas production, including unconventionals, refining, and chemicals.”
To help meet the goal, the company is boosting its global network of R&D centers. In addition to its local center in Dhahran, the Advanced Research Center in the Exploration and Petroleum Engineering Center, Saudi Aramco plans to open three new centers in the US. “We are emphasizing high-impact technologies that typically involve long-range strategies. We are pursuing R&D to bring about breakthrough achievements—not simple or merely incremental enhancements,” Al-Buraik said. “We believe that achieving our research and technology goals requires expansion and interaction with the best talent worldwide.”
The objective of these centers is to leverage international scientific expertise, gain better access to technology, and strengthen collaboration with industry and academia.
A new center in Houston will be the company’s largest center outside Saudi Arabia. A second North American center will be located in Cambridge, Massachusetts, focusing on computational modeling and nanotechnology research. The third center will be located in Detroit, and will be designed to extend the energy giant’s global research and development network. The Houston and Cambridge centers will be operational by the third quarter of this year, and all three will be operated by Aramco Services Company, a subsidiary of Saudi Aramco. The company also has research centers in Thuwal, Saudi Arabia; Delft, Netherlands; Paris; and Beijing; and a technology center in Aberdeen.
Shell Deploys Next-Generation TLP for Extended Field Development in GOM
Authors: Jacobs Trent 
Published: February 2015

Shell Olympus
As the towering Olympus tension leg platform (TLP) entered service in July, it marked the beginning of a mission to extend one of Shell’s most productive deepwater projects in the US Gulf of Mexico (GOM) to at least 2050. The oil company said this is the first time an additional deepwater production facility has been added to an existing field in the GOM.
Shell expects to begin first production from the newly commissioned Olympus TLP at the Mars field next year. The Olympus is the largest TLP the company has deployed in the GOM. The Mars field is located about 100 miles south of New Orleans in approximately 3,100 ft water depth. With 24 well slots, the Olympus TLP will produce up to 100,000 BOEPD from Shell’s West Boreas, South Deimos, and Deimos discoveries. The reservoirs are located at depths ranging from 10,000 ft to 22,000 ft.
When the Mars field began production in 1996, Shell estimated up to 700 million BOE of recoverable reserves. Since then, the field has produced more than 770 million BOE, and it is estimated that there may be 1.1 billion BOE yet to be produced. Shell is calling the field extension project Mars B.
Shell has gone to great lengths to plan for a decades-long development that ties in new innovations with les-sons learned from five other TLPs that Shell operates in the GOM. “It is a next-generation [TLP] just in the sheer size and capability we have with this rig,” said Arno van den Haak, Shell’s well delivery team lead for the GOM.
At 126,000 tons, the Olympus TLP is more than twice the displacement of the neighboring Mars TLP located only a mile away. The Olympus TLP’s drilling rig has a 2-million-lbm hook load, double the load of the Mars TLP rig, giving it the capability to drill and complete wells at depths of up to 35,000 ft—the deepest for a Shell platform.
Advances in Special-Core-Analysis Data Interpretations of Multiscale Measurements
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164140, ’Advances in SCAL Data Interpretations of Multiscale Measurements From Different Carbonate Rock Types in a Giant Oil Field in Abu Dhabi,’ by Moustafa R. Dernaika, Ingrain Inc.-Abu Dhabi; Samy Serag El Din and Zubair Kalam, ADCO; and Loay Hannon, Weatherford Laboratories, prepared for the 2013 SPE Middle East Oil and Gas Show and Exhibition, Manama, Bahrain, 10-13 March. The paper has not been peer reviewed.
The evaluation of complex carbonate reservoirs is a challenging task, and a detailed understanding of reservoir heterogeneity is still lacking. In this study, the effect of static rock type and sample size was investigated on special-core-analysis laboratory (SCAL) data derived from capillary pressure and resistivity-index experiments at reservoir temperature and net confining stress. Whole cores were generally found to yield different capillary pressure and saturation exponents that may not be possible to derive from average plug data.
Introduction
Most carbonate reservoirs are characterized by multiple-porosity systems that impart petrophysical heterogeneity to the gross reservoir interval. Reservoir heterogeneity is dependent upon the depositional environments and subsequent events in the history of the reservoir. In previous work, the effect of multiscale measurements (whole cores down to small trims) was studied on porosity/permeability and cementation factor. The whole-core samples were taken from a single well in a carbonate reservoir in Abu Dhabi, where 1.5-in. core plugs were drilled adjacent to the whole cores. Small trims were cut from the plugs for mercury-injection capillary pressure (MICP) determination. The main findings were that whole-core porosity matched log data very well and the plug porosities, when compared with the whole-core data, were systematically higher. The degree of heterogeneity played a major role in comparing whole-core to plug permeability: In the low- permeability range (less than 10 md), whole cores could enhance 3D connection pathways and yield higher permeability values, whereas, in the high-permeability range, permeability can be overestimated in plugs through relatively larger porosity channels. The cementation factor was systematically reported to be lower in the measured whole-core samples. X-ray computed-tomography (CT) scanning was essential in explaining most of the variability seen in the measured rock properties at different scales. In another investigation on four different wells in the same reservoir, these earlier observations were confirmed on hundreds of multiscale samples.