bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Industry Upturn with a Downside: Talent Needs Still Loom Large
Authors: McCormack Greg 
Published: February 2015

Talent & Technology
The oil and gas industry faces many challenging issues, now and in the future. Most industry participants are acutely aware of what they are. The knowledge gap created by “The Great Crew Change” that exists in most companies has been well documented and discussed. The problem is not one of filling the gaps. There are sufficient numbers of people entering the workforce to do that. The problem is one of “experience attrition,” and it is a challenge that must be addressed (Fig. 1).
The characteristics and expectations of “generation Y” or the “new millennials” have been examined and debated. The real issues at hand are the growing multigenerational aspects of the workforce with its mix of four distinct generations with disparate life experiences, varying ways of communicating, and distinctly different goals for their professional careers. The first of the baby boomers reached age 60 in 2008. In perspective, the average age for retirement in the oil and gas industry is 59. Along with the recent global economic slow-down has been a rise in the average retirement age. These three impacts—boomers, industry retirees, and economic changes—are all interrelated and impacted by the cyclical nature of the oil and gas industry.
This cyclicality is our industry’s hurdle in trying to resolve issues surrounding the employment of top talent going forward. Cyclicality is also the area over which the industry has least control. It is inevitable that the industry will be cyclical because it is based, quite simply, on supply and demand.
Why is cyclicality so important? The answer becomes clear from the perspective of career time spans and talent management. Most employees in the oil and gas industry are responsible for developing a career spanning an average of 35 to 40 years. During the last 40-year time span, there have been seven business cycles. Driven by Wall Street and shareholder interests, the industry has always reacted to these cycles by reducing fixed costs as they would in any downturn in the economy. However, the main element of fixed costs is employee expense. So if the oil and gas industry is driven by quarterly earnings, as are many other industries, then it will respond by driving down fixed costs and therefore, employee costs.
Techbits: SPE Summit Addresses Hydraulic Fracturing Issues
Authors: Veil John 
Published: February 2015

Techbits
The first SPE Technical Summit, titled “Hydraulic Fracturing: Ensuring Groundwater Protection,” was held in conjunction with the SPE Hydraulic Fracturing Technology Conference in the Woodlands, Texas, in January. About 80 people representing industry producers and service companies, consulting firms, academia, national laboratories, state and federal government, and national governmental organizations (NGOs) participated.
The discussion focused on the impact of fracturing on groundwater. The summit began with a keynote presentation by a state regulatory official on how state oil and gas agencies are evaluating and regulating hydraulic fracturing. Organized into four 90-minute sessions, each session had two or three short presentations by experts who provided information and stimulated discussion. The themes were:
What is hydraulic fracturing?
What are the issues?
Environmental risks and issues—facts vs. perception
How to move forward?
State Regulations
US states have the lead role in regulating most oil and gas activities, including hydraulic fracturing. Among the approximately 30 oil- and gas-producing states, there is a range of requirements and levels of detail regarding the type of hydraulic fracturing information that must be reported to the agencies.
One presentation introduced the collaborative efforts of a nonprofit, multi-stakeholder group known as the State Review of Oil and Natural Gas Environmental Regulations (STRONGER) that provides critical reviews of state oil and gas programs and offers suggestions for improvement. Teams made up of members from states, industry, NGOs, and others periodically conduct detailed reviews of state oil and gas regulatory programs. The group developed guidelines for hydraulic fracturing in January 2010. They set forth general principles such as:
Wells should be properly designed and constructed.
Water, wastewater, and waste management should be planned and conducted in a careful manner.
Information on the chemicals used in hydraulic fracturing operations should be disclosed and reported.
Focused reviews of state hydraulic fracturing requirements have been conducted in Pennsylvania and Ohio, and reviews of Oklahoma and Louisiana requirements are in progress. STRONGER also is an advocate for sufficient funding and training of state agency staff in order to provide a better oversight of oil and gas activities.
What is Hydraulic Fracturing?
This session discussed the history of hydraulic fracturing and its impact on the oil and natural gas industry both past and future. It laid out the foundation of horizontal wellbore construction and described the principles of hydraulic fracturing and its integral role in recovering natural gas.
The first use of the combination of horizontal drilling and hydraulic fracturing began in 1985 in the Austin Chalk in Texas. These efforts showed good results and were soon transferred to the Barnett Shale and later to other shale formations.
Digital Rocks Out to Become a Core Technology
Authors: Rassenfoss Stephen 
Published: February 2015

The future of oil and gas exploration depends on rocks such as carbonates and shale that can be described as tight, complex, nearly impermeable, and even stubborn. On the production side, the goal has long been to get more of the oil out of the ground, but recovery percentages have hardly budged.
The search to better understand the inner workings of these rocks that challenge traditional laboratory testing has led to a new approach known as digital rock physics. It is a technological hybrid drawing on fields ranging from medical testing to microchip production. By marrying computerized tomography (CT) and other X-ray scanning technologies, pioneers in this emerging field are creating 3D images showing the internal structure—including pore spaces and how they connect—as well as the minerals and organic matter within.
Digital rock physics providers promise faster, better, lower-cost analysis. The potential payoffs could include wells targeting the most productive rock, more effective well completions, and simulations speeding the development of enhanced oil recovery (EOR) techniques.
The graphics are stunning. The attention to detail is exacting. But using imaging to directly measure reservoir properties is still a work in progress. Getting a clear look at the smallest details in some rocks requires scanning samples that are measured in microns. Finding ways to accurately scale up this data to provide telling details about a formation will define the future of this young business.
The oldest of the three fast-growing companies selling digital rock physics services for exploration and production (E&P) goes back four years. Even the name “digital rock physics” is not set in stone. The growth in demand is in difficult formations such as shale and carbonates, and for simulating EOR projects that are hard to analyze using traditional means. Chevron, Shell, Statoil and Schlumberger are among the users.
At Chevron Energy Technology Company, the digital rock work is led by Jairam Kamath, who organized a SPE forum to consider the future use of this technology. “The more you work with it, the more you are convinced,” he said. “It took me a couple years, but I am convinced this is how we will be doing business five or 10 years from now.”
Shell is working with Schlumberger on a digital rocks project. It is one of many research projects at Shell seeking new ways to increase the output from aging fields. “I do believe there are large opportunities” there, said Gerald Schotman, chief technology officer of Shell. He described it as a way to deal with anomalies, when indicators such as the production history are out of line with predictions by the reservoir model.
Building for a Strong Future
Authors: Parshall Joel 
Published: February 2015

For the offshore heavy lift vessel industry, the market re-mains very challenging with a return to robust conditions likely to wait several years. Reflecting the lag in the way multiyear project activity responds to changes in the economy, it wasn’t until late 2009 that the sector’s utilization rate began to plummet. From a 70% rate in August 2009, as calculated by market research firm ODS-Petro-data, utilization sank to 46% by December and 37% by January 2010, edging up only to 42% by the end of the first quarter. With the delay or cancellation of several new vessel projects, as utilization tumbled, excess supply began to dwindle. Utilization stabilized and even pushed above 72% in August, before settling at 56% for the year—hardly a brisk pace but at least well off the early-year lows. While newbuild vessel activity did not disappear and continues this year, there have also been additional project delays and cancellations, according to Mark Rae, senior market analyst at ODS-Petrodata.
“I think the industry is going to start to see an uptick in 2013, where heavy lift contractors are indicating that operator interest is increasing,” said Keith Smith, enterprise category manager for offshore installation and heavy lift at Shell International E&P. “Even with the newbuilds coming on, there appears to be a growing demand.”
A major question remains on how soon field development activity in the US Gulf of Mexico (GOM) will return to levels comparable to those seen before the Deepwater Horizon disaster. The effect of the US drilling moratorium, now lifted, was to displace vessels to other global markets. Some of those markets were already beginning to tighten, according to Smith. When GOM activity picks up again, he predicts “there will be a pull on resources.”
Bruce Gresham, vice president for North America at Heerema Marine Contractors US, said the utilization rate in the upper tier of the heavy lift market where his company operates “is still healthy, although we have gaps.” Looking at the GOM, he said, “This situation on drilling permits, or lack of drilling permits, without a doubt is going to have an impact on a steady stream of projects going forward. Whereas 2013 looks to be a busy year for us here in the Gulf with some major facility installations, the moratorium on drilling will cause some projects that would have otherwise been executed in 2014 to slip back a year. But the opportunities are there, certainly plenty of prospects in deep and ultradeep water that will create a significant amount of work in the future. We have a bump in the road right now.”
Technology Focus: Deepwater Projects (May 2011)
Authors: Olson Karen 
Published: February 2015

Technology Focus
Lessons (Hopefully) Learned
The BP Macondo incident, late April 2010, profoundly changed the way work will be performed, on and offshore. After losing 11 men, injuring others, and losing an exploration rig, it is an appropriate time for the industry to evaluate what changes to industry standards are necessary to ensure that a similar event does not occur again.
The incident affected people’s lives in many ways, both seen and unseen. Obvious issues include lost tourism in several states, dead marsh and fish, idled rigs and workers, and areas placed off-limits to exploration. Nearly a year after the incident, the rig count in the Gulf of Mexico is down 50%. The unseen and to-be-determined issues include the uncertain regulatory field still arising from the event, previously marginal fields now shelved, and abandonment of or significant delay in developing high-pressure large-oil-in-place fields. Undoubtedly, these results will have a major effect on national energy security and will lead to higher energy costs.
What, then, are the lessons learned? First, management must not lose focus on the risks, however remote the odds. Second, when assessing staff adequacy, critical and honest evaluations of people and skill levels including technical expertise and requisite experience are required. In this context, technical or operational expertise should not be ignored, even if there is additional cost or time. Remaining lessons pertain to proper planning and vendor management. Proper equipment planning (availability and functionality) is required. Vendor management (must ensure that each project requiring new/sophisticated equipment has sufficient service-company-management buy-in and adequate resources and support) will be critical when offshore work returns. Striking the appropriate balance between cost and safety should err on the side of safety.
Now for the good news: two entities were established to respond to spills, and lessons learned by BP from Macondo can be used to avoid similar incidents.
Companies must be careful to avoid thinking that such an event “can’t happen to us.” Careful evaluation of risks, coupled with a realistic and thorough evaluation of company practices and processes, could help avoid another Macondo. Low-probability events can/do happen, sometimes with draconian consequences. Offshore development can be highly profitable, but the risk/return tradeoff should not be ignored.
Deepwater Projects additional reading available at OnePetro: www.onepetro.org
SPE 140498 • “Challenges of Designing Multistage Frac Packs in the Lower Tertiary Formation of the Cascade and Chinook Fields” by Ziad Haddad, SPE, FOI Technologies, et al.
SPE 137220 • “GOM Deepwater Field-Development Challenges at Green Canyon 468 Pony” by Michael H. Weatherl, Hess Corporation. (See JPT, April 2011, page 70.)
SPE 140228 • “Case History: Lessons Learned From Retrieval of Coiled Tubing Stuck by Massive Hydrate Plug When Well Testing in an Ultradeepwater Gas Well in Mexico” by Victor Vallejo Arrieta, Pemex, et al.
New Approach To Extend Horizontal-Drilling Reach
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137821, ’New Approach To Improve the Horizontal-Drilling Reach,’ by O.M. Vestavik, SPE, H. Syse, O. Hole, SPE, and J. Aleksandersen, Reelwell, prepared for the 2010 CSUG/ SPE Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed.
A drilling method was developed to enhance extended-reach managed-pressure drilling. A conventional drillstring with a special inner string forms a dual concentric drillstring (DCD). The inner string is used to remove drill cuttings from the bottom of the well. A separate hydraulic-fluid system is used to push the drilling assembly forward using fluid pressure from the surface. Development began in 2004, and the system has been through several full-scale operations in Norway. In 2009, the DCD method was used to directionally drill the 81/2-in. section of an onshore well.
Introduction
As targets for new petroleum resources become increasingly challenging, there is a need for new technology to keep exploration and production costs at an acceptable level. Development of the DCD method was supported by the Research Council of Norway, Statoil, and Shell.
DCD method
The DCD method, shown in Fig. 1, is based on conventional drilling, with the following components added to the system.
The dual drillstring (DDS) facilitates closed-loop circulation of the drilling fluid. The cuttings are trans-ported to the surface by the drilling fluid through the center pipe, leaving the wellbore annulus free of cuttings.
The top-drive adapter (TDA) is a dual-conduit swivel that facilitates rotation of the drillstring and accommodates the discharge and return conduits and a slip ring for power and data transmission.
The dual-float valve (DFV) enables downhole pressure isolation of the well and facilitates controlled-pressure drilling and nonpressured pipe connections.
The sliding piston is used to pump the bottomhole assembly (BHA) into the horizontal section of the well. The piston provides hydraulic weight on bit (WOB) and provides the ability to push the limits of extended-reach-drilling.
The flow-control unit is a control valve for the active drilling fluid to ensure constant downhole pressure during drilling and pipe connections. The unit is equipped with pressure and flow sensors on both the drilling-fluid inlet and the return lines. A computer monitors and controls the status of the well. An annulus-control unit is used to keep a constant pressure in the annulus behind the piston.
A main difference between this method and conventional drilling is the circulation path of the drilling fluid. In conventional drilling, the fluid returns through the wellbore annulus. The DCD method pumps the drilling fluid into the DDS annulus through the TDA. The drilling fluid flows down the DDS annulus to the DFV, which terminates the DDS at the top of a conventional BHA.
Opportunity, Challenge Meet on Arctic Horizon
Authors: Parshall Joel 
Published: February 2015

On the stark expanse of the Milne Point field on the Alaska North Slope, the BP Mount Elbert well tests the reservoir productivity of methane hydrate in a joint project with the National Energy Technology Laboratory of the US Department of Energy during 2007.
The Arctic represents a large expanse of opportunity for discovery and development of oil and gas resources, but one matched equally with technical challenges that test the limits of the industry.
In the 2008 Circum-Arctic Resource Appraisal (CARA), covering 33 geologic provinces considered prospective for petroleum, the United States Geological Survey (USGS) calculated that the sum of the mean estimates for each province indicated that 90 billion bbl of oil, 1,669 Tcf of gas, and 44 billion bbl of natural gas liquids (NGL) remain to be found in the Arctic, of which 84% was expected to lie in offshore areas. The study included only resources that are technically recoverable, that is, those considered recoverable using existing technology.
The obstacles of ice, the most severe weather conditions, seasonal constraints, minimal infrastructure, daunting and uncertain logistics, and the high cost of operations begin but do not end the list of challenges to Arctic exploration and production.
“The extensive Arctic continental shelves may constitute the geographically largest unexplored prospective area for petroleum remaining on Earth,” the study said.
The challenges may explain exactly why that is so and cause some to conclude that these areas will always be underexplored, with many of these estimated resources never developed. Yet the matter can be viewed quite the opposite way. As the area is so underexplored, will we someday find these estimates low if we answer the challenge to explore and develop the Arctic?
Unconventional resources, such as coalbed methane, methane hydrate, oil shale, and tar sand, were explicitly excluded from the 2008 study. Perhaps that is just a footnote. But considering what has happened in only the past few years with the tremendous growth of shale resource estimates, perhaps it is not. It is questions like that, and always knowing that there is so much we do not know, that keep the Arctic on the horizon of opportunity for the oil and gas industry.
Assessing the Magnitude and Consequences of Reservoir Souring
Authors: Schofield Mick , Stott Jim 
Published: February 2015

Reservoir souring
Reservoir souring, defined as the unplanned increase in hydrogen sulfide (H2S) in produced fluids during field life, is a growing concern for the petroleum production industry. H2S is a poisonous, dense gas with serious safety implications; it can lead to sudden catastrophic failure of nonresistant metallic materials from sulfide stress corrosion cracking or hydrogen-induced cracking, and it can enhance pitting corrosion rates.
But how does reservoir souring develop, and how can its consequences for materials be anticipated? Consideration also needs to be given to the currently available options for souring control and their shortcomings.
Despite the significant advances that have been made over the past 30 years or so in the understanding of H2S- related materials degradation mechanisms, H2S still causes many failures every year. While it may be understandable that such failures continue to occur in operating environments where reservoir souring is a new phenomenon, failures are also occurring where the industry is mature.
For example, recently in the UK, a carbon steel pipeline transporting sour hydrocarbons onshore failed by sulfide stress cracking (SSC) after 6 weeks of operation, necessitating replacement at a cost of GBP 100 million.
Over 2000–01, sour gas pipelines failures, including those affected by both microbial and chemically induced corrosion, accounted for 35 (4%) of the 952 pipeline failures in Alberta, Canada.
The challenge of dealing with H2S is likely to rise in importance as an increasing number of high-temperature, high-pressure (HTHP) reservoirs are exploited in the future. This will require more widespread use of corrosion resistant alloys (CRAs), increasing the costs of wells and downstream equipment.
Therefore, we need more corrosion data on a range of alloys when there are fewer materials engineers (particularly metallurgists) coming into the industry and fewer corrosion testing facilities in steel companies, meaning that operating companies and even fabrication contractors are having to take on the task of generating materials susceptibility data.
H2S Generation and Mobility
Reservoir souring is the production of increased concentrations of H2S in well-stream fluids from production wells subject to water injection for secondary recovery. It is generally acknowledged to be caused by the activity of a specialized group of microorganisms, the sulfate-reducing bacteria (SRB). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery.
Biogenic H2S originates solely from SRB activity in the water phase and subsequently partitions between water, liquid hydrocarbon, and gas, dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios, and a number of other factors. However, the progress of reservoir souring is routinely measured and expressed in terms of H2S concentrations in the gas phase at separator conditions and the corresponding partial pressures of gaseous H2S.