bluuebunny/crossref_metadata_2025_split huggingface dataset:
Seeking Lower-Cost Ways To Deal With Fracturing Water
Authors: Rassenfoss Stephen 
Published: February 2015

Unconventional Water
The management of water used for fracturing oil and gas wells is all over the map.
In Pennsylvania, most of the produced water is treated so it can be used again for fracturing, but some is cleaned to the point at which it meets the stringent requirements for river disposal.
In Texas, fracturing fluids generally use fresh water, and what flows back to the surface is injected into a deep disposal well.
A 2012 report, prepared by the Bureau of Economic Geology for the Texas Oil & Gas Association, titled Oil & Gas Water Use in Texas, puts the percentage of produced water recycled for fracturing in the Eagle Ford shale at 0%, and in the Permian Basin near Midland at 2%. In these arid regions fresh water is used by a wide margin. In the Eagle Ford, 20% of the water for fracturing came from brackish aquifers, and 30% in the Permian around Midland used water too salty to be potable.
Things change fast in these booming plays. But the lead author of the report, Jean-Philippe Nicot, a research scientist at the Bureau of Economic Geology of The University of Texas at Austin, said: “I don’t think those numbers have changed much. There is likely some reuse/recycling in all plays, so 0% is probably not correct, but close to it.”
For Michael Dunkel, director of sustainable development at Pioneer Natural Resources, past performance in places like the Permian is not a useful indicator of the future in an area where so many are looking for alternatives. “I am confident what we are seeing today is just at the starting gate and it will continue to evolve,” he said.
Given the thousands of unconventional wells drilled, this may seem to be a slow evolution, but the staggering scale of these formations, particularly in the Permian, means operators such as Pioneer are just moving from scattered exploration drilling to concentrated development.
“We will be drilling for 30-plus years out there,” Dunkel said. While he is confident the industry will change how it manages water for unconventional development, there are a lot of ways it can go from here.
The decisions hinge on a complex mix of variables, which can be boiled down to a simple imperative: What is the lowest-cost option? The correct answers will vary from region to region, and from company to company depending on factors such as the scale of a company’s operation.
Chesapeake Energy treats most of the water produced in its wells in Pennsylvania for reuse in fracturing with a small amount sent for disposal, said Rick McCurdy, manager of chemicals and water reclamation at Chesapeake Energy Corp. In south Texas most of the water is pumped from freshwater aquifers and produced water is injected into disposal wells.
Offshore Europe 2013 Looks to Next 50 Years
Authors: Parshall Joel 
Published: February 2015

Conference review
SPE Offshore Europe (OE) hailed the first 5 decades of the North Sea oil and gas industry by looking forward to the next 50 years. It was a fitting theme for the biennial conference and exhibition held 3–6 September in Aberdeen as OE marked its 40th anniversary, a reminder of how the event has helped to shape the industry’s perspective almost from the first days of North Sea oil.
Sessions and speakers looked critically and hopefully at the North Sea industry, closely examining its many current and future challenges and presenting numerous scenarios and strategies for how it would survive and prosper. Some observers envisioned the North Sea sector strengthening the global oil and gas industry in the next half-century through continued production, the expanding resources of its supply chain, and the spread of its world-class expertise.
A plenary and 11 keynote sessions and the presentation of more than 100 technical papers and ePosters highlighted the conference, which also featured daily breakfast briefings and topical luncheons.
However, the event had a somber note. On 23 August, four offshore oil workers lost their lives when a helicopter flying them from their rig crashed off the Shetland Islands. Many of the presenters and speakers, including the Princess Royal, paid tribute to the four people and acknowledged the risks inherent in working offshore and the industry’s strong continuing commitment to safety.
Conference Chairman Malcolm Webb, chief executive of Oil & Gas UK, said that the United Kingdom oil and gas industry is the country’s greatest industrial success story in more than a hundred years and this year’s event served to underline that fact. “At the biggest Offshore Europe ever, we’ve addressed the key themes that will require industry focus to sustain activity in the UK Continental Shelf,” he said. “None of these is more important than safety.”
The Next Half-Century
Addressing the opening plenary session, the Rt. Hon. George Osborne MP, UK Chancellor of the Exchequer, stressed the continuing importance of the industry to the country.
“First, I recognize the vital role that oil and gas play in the UK economy and will continue to play for many, many years to come,” Osborne said. “Second, I also recognize that the oil and gas remaining in the UK Continental Shelf (UKCS) will be increasingly difficult and more expensive to extract, that this government commits to play our part in delivering the investment that’s needed. And third, I believe that the best way to support this industry and maximize the returns from this great national asset is by working together across the United Kingdom through mobilizing all of the UK’s resources and by pooling our risk to provide stability across the whole of the UK.”
Stark Realities of Managing Cybersecurity Risk
Authors: Drobny Chuck 
Published: February 2015

Management
Worldwide, the cybersecurity threat is real and growing. The oil and gas industry’s technological critical infrastructure has been especially hard-hit, absorbing 40% of all cyber attacks globally. Yet the realities are not resonating effectively with industry executives, because many companies have yet to put comprehensive protection plans into action.
This issue is potentially so devastating that it figuratively shouts for a short course about the chances that companies are taking, what vendors and purported experts are advocating, the grave risks, the unvarnished truth about hackers and company vulnerabilities, and how waiting for disaster is a dead-end choice.
Largely because of its worldwide exploration and production scope and the vast population dependent on energy, oilfield companies cannot simply blend in with the landscape and become unrecognizable as a major cyber target. For example, Telvent, which makes a control system for smart grid networks, was recently hacked. Project files for its supervisory control and data acquisition (SCADA) system were accessed and malware was installed on its network in the attack.
Other attacks have occurred against Saudi Aramco, which required 10 days to get its network back online after a Shamoon Wiper malware cyber attack disabled more than 30,000 workstations in a supposedly politically directed action by a group of hackers called the Cutting Sword of Justice. In a costly move only possible with a sovereign nation, the company sequestered its entire network while determining the cause of attack and fully restoring service. Meanwhile, the Chinese military has been accused of attempts to hack all types of industries, with a particular focus on oil and gas, according to the Mandiant Intelligence Center Report.
Response Offerings
This disturbing news has had polar opposite effects. One is that the threat message is not getting through to many oil and gas companies. It is akin to a tree falling in a forest when nobody is there to hear the crash. Conversely, springing into action are vendors, so-called cyber experts, and conferences offering cyber-security solutions to the executives who are receptive to the message. With this growing demand for both information and installed protection, more companies are taking the cue that they need technical cyber expertise they do not have internally to survive the hacking they may have never expected (“Nobody would attack us. We are too small.”).
When companies do become engaged in seriously protecting their organization and its resources, the budget should not be arbitrary. Rather, it should be allocated on a basis commensurate with the spending on any other insurance or similar budget items. Benchmarking the traditional safety budget is a good approach, since it is typically proportioned over several years based on risks. Similarly, in terms of perspective, physical or plant security offers comparable guidelines in allocating resources to both deal with the threat and its consequences.
Packer-Leak Repair: Slurry Design and Complex Coiled-Tubing Well Work
Authors: Denney Dennis 
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper IPTC 17091, ’Extending Mature-Well Life by Innovative Slurry Design and Complex Coiled-Tubing Well Work,’ by M. Hairi A. Razak, Aulfah Azman, SPE, and Haryat Timan, Petronas, and M. Heikal Kasim, SPE, and M. Fakhrurazi Ishak, Schlumberger, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
A well in the South China Sea was diagnosed by ultrasonic and temperature logging to have a well-integrity problem, forcing the operator to shut in the well because the leak created a high tubing/casing-annulus pressure. Through-tubing well work was used because it is more economical than a full workover, particularly for wells in a mature field with depleted reserves. Enhanced and optimized cement slurry was engineered with a well-work approach that specified acoustic fluid-level monitoring. The packer leak was repaired successfully.
Introduction
This oil and gas field is 260 km from Kerteh, Malaysia. Discovered in 1971, first oil production was in 1978. The field is in the southeastern part of the Malay basin at an average water depth of 70 m. The field contains both gas and oil reservoirs. In August 2002, communication was observed between the production casing and tubing of the subject well, indicating a leaking production packer. Four major attempts to correct the problem were conducted, all unsuccessful. The first attempt was in February 2003 by bullheading calcium carbonate (CaCO3) into the annulus. This procedure was attempted again in May 2003. In August 2007, a coiled-tubing (CT) unit was used to spot cement inside the production tubing and displace it into the annulus through a gas lift mandrel to the top of the packer. Another cementing job was attempted in December 2008, through the same gas lift mandrel.
Diagnosis
Lessons learned from the first cementing failure, in 2007, were used to design the attempt in 2008. Even though job execution was smooth in the field, several mistakes occurred that were not realized by the team during the job-design process. The experiences of those cementing attempts helped mature the subsequent design and decisions, ensuring success for future packer-cementing jobs in peninsular Malaysia operations.
Cement-Slurry Design. CT-cementing procedures are different from those of conventional/primary cementing from a rig, with the biggest difference being the need for batch mixing for CT cementing vs. on-the-fly mixing for primary cementing. Batch mixing requires higher mixing energy compared with primary cementing, with an additional mixing energy to pump the cement slurry through the CT relative to pumping down the casing. The higher mixing energy decreases thickening time (TT) such that the cement slurry has potential to accidentally set inside the CT, thereby requiring a suitable retarder to prolong the TT.
Challenges of Tight and Shale-Gas Production in China
Authors: Denney Dennis 
Published: February 2015

This article, written by Dennis Denney, contains highlights of paper IPTC 17096, ’Production-Technology Challenges of Tight and Shale-Gas Production in China,’ by Hon Chung Lau, SPE, Shell (China) Projects and Technology, and Meng Yu, SPE, Shell International Exploration and Production, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.
Natural-gas production from tight and shale-gas reservoirs will be increasingly important in China as the country shifts from coal-based energy to cleaner energy sources. Recent Chinese sources have estimated that the gas-in-place resources from tight and shale-gas reservoirs in China are at least 12×1012 m3 and 31×1012 m3, respectively. In 2008, annual production from tight gas reservoirs reached 20×109 m3, approximately 23% of the natural-gas production in China. Commercial production from shale-gas reservoirs has not begun but is expected to grow rapidly.
Introduction
Since 2010, the consumption of natural gas in China has far exceeded domestic production. To bridge this gap, domestic production of natural gas, especially from unconventional resources [e.g., coalbed methane (CBM) and tight and shale-gas reservoirs], must be increased significantly. From a review of published literature and their own observations, the authors identified several relevant production technologies that could have a significant effect on tight and shale-gas production in China.
Unconventional Gas Resources
The US Energy Information Administration estimated that China had 0.289×1012 m3of proved CBM reserves in 2011, although other recent estimates of recoverable reserves are 9.9×1012 m3. Fig. 1 shows most of China’s gas-producing basins. CBM resources are in the north and northeast, the Sichuan basin in the southwest, and the Junggar and Tarim basins in the west. In China, tight gas resources total approximately 12×1012 m3. The Sichuan basin is one of the largest tight gas basins in China and is reported to have approximately 1.8×1012 to 2.25×1012 m3of natural gas. The Sulige gas field in the Ordos basin is the largest tight gas field in China.
Most of China’s proved shale-gas resources are in the Sichuan, Tarim, and Ordos basins. Estimates of China’s total tight and shale-gas resources range from 36×1012 to 100×1012 m3. Although there was no commercial shale-gas production as of 2012, the Chinese Ministry of Land Resources has set aggressive targets of 6.5×109 m3/a by 2015 and at least 59.5×109 m3/a by 2020.
Management of Hydrogen Sulfide (H2S) Risks
Most of China’s sour-natural-gas fields are in the northeastern and western parts of the Sichuan basin (mostly conventional gas fields). An evaluation of shale-gas potential in the Weiyuan area showed significant shale-gas reserves. Therefore, it is important to determine the likelihood of penetrating sour reservoirs and to manage H2S risks. In general, a rigorous H2S safety-management plan will be needed if tight or shale-gas development will require drilling through or near zones containing H2S.
En Route: The Production Capacity Challenge
Authors: Labastie Alain 
Published: February 2015

President's column
Peak Oil Theory has been a subject of intense discussion since it was established by M. King Hubbert in the 1950s. The theory basically states that production is limited by resources—i.e., geology. I believe that, although it will be a reality one day, the theory is not correct globally for the short and mid term. But I also believe that we are in fact facing another limitation, one caused by production capacity.
For conventional hydrocarbons, explorationists have literally invented new domains for seeking oil and gas, and this has proven to be very efficient. A good example is the deepwater domain (now subsalt), which has added a large amount of reserves in various parts of the world and will certainly continue to do so for a while. The Hubbert decline curve, which historically has been a good fit with the production of the US Lower 48 states, is no longer applicable because of this domain extension; it works for a given domain.
We have produced most of the conventional hydrocarbons—these have been easy to produce, but in relatively small volumes. As illustrated by the resource triangle (Fig. 1), a concept invented by Steve Holditch, there are huge resources in unconventional hydrocarbons in both oil and gas but they are difficult to produce. Interestingly, the production from these resources is also difficult to predict. Look at the booming activity and production of shale gas in North America, for example; very few forecasts, if any, were anticipating that boom 10 years ago or even less. The resources are abundant.
The challenge we face comes from production capacity. I will illustrate what I am talking about with oil, but the situation is similar for gas. On one side, we will have a slight increase in demand—1% to 1.5% per year, according to the International Energy Agency’s “reference scenario.” On the other side, our producing fields are ageing, and will decline at a rate of about 5% per year. As a consequence, the gap between demand and production from existing fields will widen, to be filled by new production. These figures illustrate this challenge:
2009 production was about 85 million BOPD.
2019 demand will be about 95 million BOPD.
Taking into account the decline of existing fields, to go from 85 to 95 million BPOD we must add not 10 million BOPD production capacity, but about 45 million BOPD of new production. That represents half of today’s production.
This is an enormous challenge—the production capacity challenge. Huge efforts will be needed. To be successful will require technology, innovation, capital, and staff.
Technology Focus: Production/Facilities (December 2010)
Authors: Skeels Brian 
Published: February 2015

Technology Focus
This year’s technical papers discuss employing advances gained in computational fluid dynamics (CFD) to induce multiphase-fluid separation through novel piping configurations and rotational dynamics rather than internal mechanical processes and baffles. These novel flow-chamber designs are reducing facility footprints and tank sizes, lending themselves to reduced platform-deck sizes offshore and extending water-depth ratings subsea. CFD also is improving the strategic placement of insulation barriers, piping geometry, and mixing of treatment chemicals to improve flow assurance and minimize erosion. Other techniques use biotechnology to detect and treat harmful microbial action at previously undetectable levels so that corrosion or increasing sour-service conditions can be avoided long before the number of microbes can grow to harmful levels. These papers demonstrate the oil industry’s continued vigor despite uncertain economic and regulatory times.
Production/Facilities additional reading available at OnePetro: www.onepetro.org
SPE 136292 • “Engineering Approaches—Progress in Calculation of Inhomogeneous Turbulence in Pipelines” by S.N. Kharlamov, National Research Tomsk Polytechnic University, et al.
SPE 136390 • “In-Line Technology—New Solutions for Gas/Liquid Separation” by E. Kremleva, SPE, FMC Technologies, et al.
IPTC 13121 • “Prediction of Optimum Thermal-Insulation Thickness for Oil and Gas Process Piping and Equipment Using a Simple Method” by A. Bahadori, Curtin University of Technology, et al.
SPE 130744 • “Rapid Determination of MIC in Oil-Production Facilities With a DNA-Based Diagnostic Kit” by Torben Lund Skovhus, Danish Technological Institute, et al.
SPE 126318 • “Ecological Advantages of Carbon-Enhanced MBRs Treating Oily Wastewater” by William G. Conner, Saudi Aramco.
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2010)
Authors: Mensa-Wilmot Graham 
Published: February 2015

Technology Focus
Performance Drilling—System Approach Will Yield Sustainable Improvements
The industry continues to develop new tools, technologies, and processes to help drive down drilling costs. This commitment to improve drilling efficiency and reliability, through effective questioning of relevant data, also has strong positive effects on drilling operations. Strides have been made, but there is more to be done.
In most instances, efforts to understand and develop sustainable-improvement strategies tend to isolate and focus on specific components [e.g., drill bit, drilling fluid, bottomhole assembly (BHA), and drive system]. In relating to these components, we usually are guided by past experiences and “rules of thumb.” Without a doubt, it is clear that the effect and value of our experiences are immeasurable. However, we need to shape our data-questioning processes around our experiences to challenge the rules of thumb. We have tools that will speed up this process.
First, we need a system approach to performance drilling. Extensive research has contributed to the development of high-performance positive-displacement motors and turbines. In addition, development of rotary-steerable tools has been extended successfully into slimhole applications. Earlier limitations of these tools, in terms of torque vs. revolutions-per-minute relationship, as well as product reliability, have seen tremendous improvements. What usually is missing is the selection analysis from a drilling-system perspective rather than as an individual component.
BHA design and modeling, a critical part of the system approach, must be practical and field driven. Negative effects of vibrations, with regard to downhole-tool life, borehole quality, and overall drilling performance, have been clearly established. As a means to vibrations mitigation, sources and specific modes must be identified. BHA design, as part of the system approach, must be cognizant of the drilling system’s functional requirements. In addition, performance-improvement discussions must focus on practical aspects of the application. System-based solutions will ensure consistent and sustainable improvements.
We have the key, let’s open the door.
Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org
SPE 128767 • “Decoupling Stick/Slip and Whirl To Achieve Breakthrough in Drilling Performance” by Sean Xianping Wu, Smith Technologies, et al.
SPE 128211 • “High-Frequency Downhole Dynamic Measurements Provide Greater Understanding of Drilling Vibration in Performance-Motor Assemblies” by Andrew D. Craig, SPE, NOV, et al.
SPE 134488 • “Downhole-Vibration Measurement, Monitoring, and Modeling Reveal Stick/Slip as a Primary Cause of PDC-Bit Damage in Today’s Applications” by L.W. Ledgerwood III, SPE, Baker Hughes, et al.