bluuebunny/crossref_metadata_2025_split huggingface dataset:
Turning a Scientific Tool Into an Engineering Machine
Authors: Rassenfoss Stephen 
Published: February 2015

Rock Tester
Nobody knew where the oil and gas was trapped inside shale until a scanning electron microscope (SEM) showed the pores within the organic material inside.
Now there are a growing number of machines creating three-dimensional (3D) digital replicas of these rocks by combining SEM imaging with a focused ion beam (FIBSEM), which cuts off ultra-thin slices like a meat slicer, revealing multiple layers within.
These 3D digital images are incredibly detailed, but they are based on cubes whose longest side is 10–20 micrometers—millionths of a meter—making them small enough to fit into the spaces in porous sandstone. When it comes to building reservoir models, it leaves engineers wanting more.
“The real challenge is we are creating micron-sized images and dealing with square miles of resources,” said Carl Sondergeld, a professor at the Mewbourne School of Petroleum and Geological Engineering at the University of Oklahoma (OU). “If we can transcend those scales we can do a better job of characterizing reservoirs.”
In the pursuit of more, he and Chandra Rai, professor and director of the Mewbourne School, have built up one of the largest unconventional rock research laboratories, backed by 12 oil companies. The focus has been on understanding the workings of the nearly impermeable rocks, which has changed how some properties are measured.
The large lab displays Sondergeld’s constant hunt for improved tools for analyzing how rocks and reservoirs perform. The laboratory recently added the latest generation of scanning electron micro-scopes from one of the biggest makers of these instruments, FEI.
One thing that sets this FIBSEM machine apart is its ability to stitch together thousands of micron-scale images to create 2D pictures covering rock surfaces measured in millimeters rather than micrometers. These hyper-detailed pictures offer an overview of an area, with the option of zooming in for a closer look to see if low-resolution impressions are correct. They often are not.
Another plus is its ability to create images using extremely low power—as low as a 100 V compared with 30,000 V for older machines—creating images that may offer better ways of measuring critical details, such as the amount of kerogen—the organic material that is the source of the oil and gas.
Technology Focus: Offshore Drilling and Completion (April 2013)
Authors: Santos Helio 
Published: February 2015

Technology Focus
We all know that things have changed significantly for offshore drilling and completion in the last 3 years. Regulations have been reviewed, and operational procedures and requirements have changed. Requirements for the well design to be reviewed by independent parties and new equipment testing procedures and certification were just a few additions that regulators brought to the scene. Several initiatives were launched to develop equipment to cap flowing wells offshore, new ways to record and control testing of critical equipment, and new systems to assess and monitor the barriers present in the well more effectively.
The industry has shown a significant creativity, as usual, to demonstrate to society in general that we can continue to drill and produce hydrocarbons offshore in a responsible manner. And, by offshore, we now mean wells located in waters as deep as 10,000 ft. In the industry’s move toward these challenging environments, most of the time we use technology known and proved for shallow waters and just resize the equipment. However, the challenges are not restricted to a deeper column of water. Many wells are facing additional challenging situations such as being subsalt or pre-salt, having high-pressure/high-temperature prospects, and having total depths in excess of 25,000 ft. Many specific conditions must be addressed in these new environments, and simply extending the envelope of current solutions to more challenging conditions may not be enough or suitable anymore. The lack of riser margin and the challenges posed by a long chokeline during well control operations are just two examples of the new conditions that did not exist 30 years ago and, therefore, require a shift in the thinking process to allow wells to be drilled and completed more economically in these new challenging environments.
After a period of uncertainty for offshore operations, wells are now being drilled again, albeit under more strict rules and guidelines. Most of the new rules and guidelines have been applied to well design and the preoperational phase. It is important also that operations be conducted under proper conditions, providing people on the job with all the means and tools necessary for them to conduct their jobs successfully.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 152861 A Solution to the Problems Associated With Tight-Clearance Boreholes: The Close-Tolerance Press-Fit Stop Collar by J.A. Wimberg, Chevron, et al.
SPE/IADC 151182 Blowout Preventer Health Monitoring by Jim McKay, BP, et al.
SPE/IADC 150047 Successful Qualification and Deployment of a High-Pressure Drillpipe Riser in West Africa by Mathieu Camus, Total, et al.
Proposed Cluster Liquefied-Natural-Gas Production System Raises Tolerance of CO2
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23261, ’Development of CO2-Tolerant LNG-Production System,’ by JungHan Lee, Jeheon Jung, and Kyeongmin Kim, SPE, Daewoo Shipbuilding and Marine Engineering, prepared for the 2012 Offshore Technology Conference, Houston, 20 April-3 May. The paper has not been peer reviewed.
During natural gas liquefaction, CO2 must be removed to prevent icing and plugging in the system. The CO2-removal system may be the most important part of the gas-treatment system. CO2 removal systems require complicated amine contactor and regeneration systems with substantial heat sources. The CO2-tolerant natural-gas-liquefaction system called cluster liquefaction accepts approximately 1% of CO2 for the liquefaction and related systems. The CO2-tolerant characteristics of this liquefaction process will provide a multifold safety margin against CO2 problems in cryogenic systems and valves.
CO2-Tolerant Liquefied-Natural-Gas (LNG) Production System
Considerations. Natural gas liquefaction at higher pressures and equivalent higher liquefaction temperatures has the advantages of reducing liquefaction energy and adopting more-efficient refrigerant. Despite the advantages, the higher-pressure storage requirement for the produced LNG has been a cost burden in overall LNG chains. For that reason, natural gas liquefaction at higher pressures has not been adopted by the industry.
The specific weight ratio (SWR) of natural gas, defined as the natural gas weight divided by the containment system weight, is an important indication of capital expenditures. The typical SWR of conventional LNG is approximately 10–20 times that of compressed natural gas (CNG). Even for the increased- pressure LNG, the SWR is typically 10 times that for CNG. Hence, storage as a liquid after cooling and insulation is far more efficient than CNG.
For increased-pressure LNG, the main cost contributor has been the cryogenic material for the higher pressure. However, if a cost-effective solution for increased-pressure containment is developed, it may become a viable option.
Examples. Intermediate-Pressure LNG (20 bara, 1% CO2). Substantial CO2 can be dissolved in LNG produced at increased pressure. CO2 in the LNG should be liquid, not solid or as two phases. During cool down at a predetermined pressure, the feed gas can pass through the solid formation region in the interim stage. Hence, this region should be avoided by liquefying the natural gas at a higher pressure before reducing the pressure. If the CO2 level is sufficiently lowered during the gas treatment, the solid formation can be avoided regard-less of the liquefaction temperatures and processes.
Data Gathering to Smooth the Bumpy Path to Optimization
Authors: Rassenfoss Stephen 
Published: February 2015

Fracturing
Noble Energy has had powerful motivation to invest in learning how to maximize the return on its wells in the Wattenberg field in Colorado—its biggest current investment and key to the company’s aggressive growth program.
Over the past 3 years, the independent oil company has drilled nearly 600 wells in extremely tight Niobrara formation rock. The company plans to go from 320 wells per year in 2014 to 680 wells in 2018, according to a recent Noble Energy investor presentation. This effort is needed as it works to double its daily production over the next 5 years.
For the team working to maximize production and profits in that field, one of the biggest questions has been, and continues to be, how many wells to drill per square mile.
This is a common question in the industry, but the company has done something uncommon to help answer it: Noble created an “Underground Laboratory.” It is in a section of land with nine horizontal wells, spaced at varying intervals. The “Laboratory” includes a pair of horizontal wells with multiple fiber-optic and pressure sensors amid a cluster of vertical monitoring wells and provides a multidisciplinary team of geoscientists and engineers a rare and unusually detailed look at oil production in the Niobrara on a meter-by-meter basis.
“What we are trying to do is essentially bring the equivalent of high-definition television down underground to directly observe what is happening and then come back and figure out, how do we explain what we see,” said Dave Koskella, exploration and reservoir systems manager at Noble.
What looks like a geoscientist’s fantasy come true—a list of diagnostic tools included in a presentation at February’s SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, consisting of 13 items, some with subheads—was created to answer critical questions facing the business. “It is a laboratory that is challenging our insights and beliefs about why and how things are working in our wells,” he said.
While Noble’s investment in diagnostics is exceptional, the problems it is trying to solve are common for the companies focusing their exploration and production program on developing unconventional formations in the United States and Canada.
E&P Notes (April 2014)
Authors: Jacobs Trent 
Published: February 2015

E&P Notes
Why Global Shale Development Drags
While shale unproved technically recoverable resources have been identified around the world, development has been limited to North America. At the SPE Hydraulic Fracturing Technology Conference in The Woodlands, Texas, in early February, service company executives offered reasons why international development could be years off.
Even in countries where there is an urgent need for more oil and gas, such as India and China, there are obstacles to development ranging from electrical code incompatibility issues to the lack of equipment needed for factory-like development to questions about rock properties and mineral rights. A sample of the barriers to development in Australia, China, Saudi Arabia, and India shows why it takes time to develop a country’s shale gas or oil potential.
Controlling BOP Downtime
Shell and Transocean formed a partnership to work on designing a more reliable control system for blowout preventers (BOPs). Their goal is “eliminating BOP control system downtime” with a 3-year project to design fault-resistant and fault-tolerant control systems that could be used to retrofit BOPs currently in use.
Using Lasers in the Arctic
Using laser beams to send high-speed streams of data, a technique that has been used by the US Navy for secure submarine communications through ice, is being offered as an option for offshore oil operations. The possibilities range from using pulsed laser signals to both measure the thickness of ice sheets and detect oil leaks beneath them in the Arctic, to providing data links for autonomous underwater vehicles (AUVs) harvesting data from wireless seismic sensors on the ocean floor.
So far, the most concrete version of this idea is the simulation provided by defense-contractor-turned-offshore-oil- technology-company Qinetiq (pronounced kinetic). It presented its ideas about laser communication and testing at OTC’s Arctic Technology Conference in Houston, Texas, this February. The company is also working on options for communication links in deep water, where there are a lot more potential users.
Surface-Controlled Formation-Isolation Valves Used for Temporary Well Suspension
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23997, ’Case Study: Surface-Controlled Formation-Isolation Valves and Their Application as a Barrier for Temporary Well Suspension,’ by Oguzhan Guven, Joao Mendonca, and Dan Thai, Schlumberger, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
To increase deepwater-drilling-rig availability, operators have adopted the strategy of transferring subsea-tree-installation responsibility from offshore drilling rigs to subsea-equipment- support vessels (SESVs). The installation from a rig can take 1 to 3 weeks; transferring this responsibility to the support vessel enables the rig to move to the next well sooner and offers significant time savings. This paper introduces a fit-for-purpose surface-controlled formation-isolation valve (SFIV) designed for the temporary well suspension required for this strategy.
Introduction
One of the deepwater subsea-field-development operations being transferred to SESVs is the vertical-tree installation employing the “tree-by-wire” technique. One of the key components of this technique is the use of two remotely operated formation-isolation valves that suspend the well after installation of the tubing hanger. Once the well is suspended, the rig can be moved to the next well. The tree is then installed by use of a heave-compensated wire from an SESV.
A new generation of SFIVs has been designed to enable the well suspension involved in this technique (Fig. 1). Several critical requirements were considered in the development of these valves:
Reliable bidirectional sealing.
Repeatable remote operation.
Fail-as-is: In case of a failure in the control system or the valve itself, the valve must not change its position.
Ability to open under high differential pressure.
High debris tolerance.
Two sizes of SFIVs were developed that meet these requirements. These were fully field tested in 2011 and 2012 in 11 different field installations.
Design and Key Features
The ball section of the SFIV is designed to tolerate the debris common in harsh well environments. The SFIV uses a nontranslating ball valve with bidirectional sealing, which is the ideal valve system for high-debris environments. The ball-valve primary seal is a gastight seal and sustains its integrity even after repeated actuations under pressure differentials.
To allow for increased setting depth, the SFIV actuation section uses a displacement-based fail-as-is mechanism, which functions independently of the setting depth. Most other lubricator valves use a holding system that counteracts the hydrostatic pressure in the event of a control-line leak. At extreme depths, the hydrostatic force acting on the actuation piston creates a large force, increasing the holding force for the valve position as well. This can create operational issues.
Inshore Floating LNG for Liquefaction of Onshore Shale Gas
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24091, ’Development Options for North American LNG Export: The Merits of Inshore-Deployed FLNG for Liquefaction of Onshore Shale Gas and Examination of Principal Technology Drivers,’ by Joe Verghese, WorleyParsons Europe, and Nancy Ballout, WorleyParsons Houston, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission.
The advent of shale-gas production onshore North America, the resulting overhang of gas supplies, and the downward pressure on gas prices have led operators to consider the possibilities of liquid-natural-gas (LNG) liquefaction plants for the export of LNG from coastal locations to international markets. Several proposals for onshore liquefaction relate to the conversion of existing LNG regasification sites. The paper assesses the technology implications of migrating LNG floating production, storage, and offloading (FPSO) concepts to inshore service.
Market Context
The energy markets have seen a remarkable evolution in gas developments driven by a number of factors including the relative abundance of this energy resource and its global availability, flexibility in use, and low carbon number. According to the International Energy Agency (IEA), gas will increase its share of the global energy mix from 21% in 2009 to 25% by 2035.
Against this backdrop, the shale-gas revolution in North America has already led to gas self-sufficiency, with North America poised to be a net exporter by 2016. According to the IEA, the introduction of horizontal drilling, hydrofracturing, and resource targeting technologies has led to a 27% increase in natural-gas production, from 2005 levels to 23 Tcf in 2011 (Fig. 1). A further increase of 44% from this 2011 level is foreseen by 2040. US natural-gas production has outpaced growth in demand by a ratio of 2:1 since 2005, leading to downward pressure on natural-gas prices.
These factors have prompted owners of existing LNG regasification terminals to sense a shift in the demand/supply balance, and to seek approval to install liquefaction facilities for export of LNG. By the end of May 2012, 15 applications had been submitted to the US Department of Energy for export authorization, amounting to a staggering 145 million t/a of capacity.
The sweet spot for floating liquefaction units lies precisely in the greenfield phase of the LNG-export scenario. For greenfield developments, the atshore or inshore deployment of floating LNG (FLNG) can offer interesting advantages over its onshore counterpart. These include potential for faster permitting, a faster construction schedule, and significant potentials for standardization and redeployment.
Advances in OH Multistage Fracturing Systems - A Return to Good Frac-Treatment Practices?
Authors: Themig Dan 
Published: February 2015

Technology Update
New developments in fracturing systems have returned focus to good fracturing practices that have been all but abandoned with the advent of horizontal wells. In major plays, such as the Barnett Shale of east Texas, operators have employed fracturing practices that are often inefficient and ineffective. Examples would include the massive overdisplacement of prop-pant and extended shut-in periods during a well’s completion phase, instead of initiating immediate flowback and load recovery.
One of the problems with resource plays is that field development moves at a very rapid pace. In addition, most of the work is designed to simulate a manufacturing assembly-line process, i.e., use the minimum number of technical people to complete the maximum number of wells. Much of the engineering used in completion design has been replaced with a one-size-fits-all process. In our view, good fracturing practices developed over some 40 years are being ignored in the field-development strategies of many of today’s resource plays.
Fortunately, there are now major developments in multistage fracturing technology that address many of these problems. One example is a new series of high-density, openhole (OH) fracturing systems that allow more than 20 fracture treatments to be performed in a single, seamless operation (JPT 2009).
High-Density Fracturing Technologies
The first OH multistage fracturing systems were installed in late 2001. At that time, it was believed that four to five stages would be sufficient to drain most horizontal wells. It would have been unimaginable to think that a few years later, the industry would be installing fracture liners with more than 40 OH packers. Key developments have taken place across a number of venues to make this possible. One item that was in question in the early days, but has now been clarified, is the ability to push long, high-density frac liners into a well. The industry now has the ability to accurately model installations of frac liners with OH packers with a high degree of certainty.
In addition, hardware developments have taken place to allow higher-density fracturing. Issues such as abrasion and erosion encountered in massive hydraulic fractures, with millions of pounds of proppant, had to be addressed. The primary activating method for these OH systems is a ball-actuated port mechanism. Continued advancement in the systems, including 8 years of R&D into materials and the mechanics of the process, has greatly enhanced industry capabilities. More than 10 types of ball materials now are offered, as well as numerous port-design options. The net effect is that capabilities have increased from four or five fracture stages per well to more than 20 stages, using this mechanism. Engineering work is under way to increase these numbers to more than 60 fractures in a single horizontal. (The current record for number of stages is 47, installed in a ~10,000-ft lateral in the Bakken Shale of North Dakota [Slawson Exploration/Packers Plus Energy Services, 2010].)