bluuebunny/crossref_metadata_2025_split huggingface dataset:
Oil and Fat
Authors: Barbey Alex 
Published: February 2015

Guest editorial
In the oil and gas industry, the “S” is surely the biggest part of the “HSE” equation (health, safety, and the environment) in terms of liability and expense. But a lowercase “h” would better represent the lack of attention paid to health—yet “h” issues kill more people every year in the industry than the “S.”
Twenty years ago, when I started working for the industry, the people in this profession were perceived by the general public as young, dynamic, and healthy—traveling and working in remote places, and leading a glamorous, adventurous, Indiana Jones-type life.
However, the truth is sadly different. When medical professionals in this industry meet, although we are concerned that HIV/AIDS, tuberculosis, malaria, and diarrheal diseases are a problem among our workforce, we are shocked that their effects are minor in comparison with the number-one killer—lifestyle-related diseases. Obesity, in particular, is responsible for the high number of deadly heart attacks among oilfield workers.
The bottom line is that more people from the oil patch are dying from heart attacks today than from vehicle or work-related accidents. In 10 years, if nothing changes, half our workforce will be overweight or obese and at greater risk for experiencing heart attacks, strokes, high blood pressure, type 2 diabetes, high blood levels of artery-clogging cholesterol, respiratory problems, and an increase in certain cancers.
The Root Cause
In a world where 1 billion people are overweight or obese (defined by body mass index; see www.nhlbisupport.com/bmi) and where 20,000 people die each day from heart attacks, the oil and gas industry is faced with a workforce that is only getting older and fatter. A formal health-risk assessment is not required to understand the root cause of the problem. It is a simple case of too much food and not enough exercise!
The people in our industry, although well educated, show little understanding or motivation when told that they need to lose weight—until they have a heart attack themselves or learn of the brutal, unexpected death from cardiac arrest of someone close to them such as a family member, friend, or colleague. Many oil-field workers epitomize the “that’s life” or the “it won’t happen to me” mentality.
People just do not seem to take their health very seriously. They figure that life is too short to not enjoy fatty, high-calorie meals washed down with a few glasses of alcohol or soda. Modifying bad habits is always being put off until a few years from now. It is considered easier to take a medication to reduce blood sugar rather than to decrease consumption of extremely sweet carbonated soft drinks; another medication to reduce cholesterol levels rather than eat less butter, fries, fast food, and processed food; and a third medication to reduce blood pressure rather than lose a little weight by walking and moving more.
Achieving Sustainable, Optimal SAGD Operations
Authors: Acosta Erick 
Published: February 2015

Technology Update
To meet the global demand for energy, the petroleum industry has been gradually increasing its development and exploitation of unconventional heavy-oil reserves. The production of heavy oil (broadly defined as having a gravity of less than 20°API) can be profitable, but operators usually generate lower profit margins than in light-oil production because of higher extraction cost, the need for diluents, upgrading cost, and the lower market price for heavier crude oils. Consequently, heavy-oil producers have to manage their assets in a sustainable manner by using the best technology available to minimize their total cost of operation and ensure a timely return on investment.
The vast majority of the world’s heavy-oil reserves are found in Canada, Venezuela, and Russia. Canada has the largest heavy-oil reserves, approximately 175 billion recoverable bbl trapped in the form of oil sands. Extraction of heavy crude from the sands requires unconventional and unique methods (Farouq Ali 2003). The two preferred production methods are open-pit mining and in-situ processes, with steam-assisted gravity drainage (SAGD) being a commonly used in-situ method. Open-pit mining can be used to extract approximately 20% of the recoverable crude from oil sands, while in-situ methods such as SAGD can be used to produce the remaining 80%. In Canada, that would represent approximately 140 billion bbl.
Open-pit mining is a mature technology with a large environmental footprint, and this method can only exploit resources near the surface. On the other hand, SAGD has a much smaller footprint, even as it unlocks reserves well beyond the reach of mining operations. Thus, in areas such as the Athabasca and Cold Lake regions of Alberta, SAGD operations have been emerging and rapidly expanding. Fig. 1 is an artistic representation of an SAGD facility, including some common injection points for oilfield chemicals. In SAGD, the two most common types of chemical treatments are related to emulsion separation and water clarification for reuse of water in steam generation.
SPE Annual Conference Makes History
Authors: Donnelly John 
Published: February 2015

Conference review
SPE’s first Annual Technical Conference and Exhibition (ATCE) held outside the US drew 4,700 oil and gas professionals from more than 70 countries to the historic city of Florence, Italy. Approximately 60% of this year’s attendees came from Europe, the Middle East, Asia Pacific, Russia and Caspian area, Africa, and South America as the event attracted a truly international crowd.
This year’s conference also received 1,800 paper proposal submissions, the most ever for an SPE event. Of those, more than 400 were selected for presentation. More than 250 exhibiting companies from 17 countries showcased new and novel technologies for the E&P industry during the conference as well.
The Chairman’s Luncheon Address and the Opening General Session highlighted the first day of the conference. ATCE 2010 General Chairman Claudio Descalzi, chief operating officer for E&P of Eni, delivered the address to a packed ballroom. His theme was how operating companies must refocus on improving competencies, their relationships with producing countries, and corporate culture if they are to succeed in the future. Over the past decade, the industry has been effective in finding new resources, but not in bringing those resources into production, he said. And with global demand predicted to soar, both international and national oil companies must become smarter, more effective, and more efficient in their operations, he said.
Operators outsourcing technology development to the service sector over the past 2 decades has caused operators to lose some expertise, Descalzi said. Going forward, operators must improve in the following areas, he said:
Raise technological competency and learn how to apply technology more efficiently, and create knowledge-management systems to capture skills needed and lessons learned.
Improve relationships with host producing countries. Technology alone is no longer enough to offer countries with resources.
Instill a meaningful corporate culture. “Laws and regulations change from country to country and from time to time,” he said, but the industry needs a model of common standards, especially in the area of health, safety, and the environment.
“The applications of these three steps will bring many positives to our industry,” Descalzi said, including making it more competent, efficient, and competitive.
The Future Ain't What It Used to Be, Or Is It?
Authors: McIntosh John 
Published: February 2015

Management
If a man tells you he knows a thing exactly, then you can be safe in inferring that you are speaking to an inexact man. —Bertrand Russell
In “The Difficulty of Assessing Uncertainty” (SPE 5579, 1976) E.C. Capen described how oilfield engineers struggled to quantify variables. Capen asked groups of SPE members to estimate 10 quantities (e.g., dates, distances, times) using ranges with a prescribed confidence level. What he found (and others before and afterward confirm) is that very few people are good at this exercise.
Probabilistic methods and in particular Monte Carlo Simulation (MCS) are often thought to solve the problems presented by Capen. However, MCS can make matters worse if a misleading estimate appears to be backed up by a detailed process, voluminous research, and specialized software. All estimates need to be calibrated, that is, substantiated by reference to reality.
For clarity, it is worth defining the terms uncertainty and risk. Uncertainty is used here to describe the fact that for any future project a range of outcomes exist. Risk is used to describe less-desirable outcomes; typically risk relates to a project running late and over-budget.
The purpose of this article is to suggest that a calibrated estimate of well project duration and cost should be a standard part of the investment decision-making process. A calibrated estimate will substantiate a wide range of possible outcomes and improve the quality of information available prior to allocating capital. Communicating information related to risk is also an area where the E&P industry can learn from others.
Rating and Describing Risk
Rating systems exist to describe in broad, concise terms the nature of risks associated with particular financial investments. The risk being rated is the less desirable outcome that the borrower defaults on the money invested. Standard and Poor (a credit-rating agency) use the term “AAA” to describe the lowest investment risk to capital. In the Standard and Poor system, 13 basic levels of long-term credit risk are described using a scale from AAA to D. With the potential project costs faced by the E&P industry, it seems strange that standard tools have not been established so that risk can be measured and communicated.
The credit-risk system has been through a difficult period and is thought to have contributed to a large number of bad investment decisions. The fact that the risk of collateralized debt obligations (CDOs) was thoroughly underestimated reflects badly on the system. But lessons can be learned from the financial industry. First, although the system was flawed, it has not been abandoned and will be improved. Secondly, so much has been written and published about financial risk that it would be irrational not to use knowledge gained from these expensive lessons. Thirdly, the cost of poorly understood risk is illustrated well by public errors such as the CDO fiasco.
Improving Human Resources Through Benchmarking
Authors: Lincoln Darren 
Published: February 2015

Talent & Technology
Oil and gas companies are facing human resource (HR) challenges that require a different approach if companies want to be competitive for attracting and retaining talent. SAIC is in its third year of running its Oil and Gas Human Resources Benchmarking Study. The study, organized at the request of two supermajors and a major refiner, focuses on recruitment, retention, the aging workforce, HR costs, and diversity. The following reviews some of those results from the first two studies.
Recruitment and Retention
Recruitment and retention of the right people are vital to the success of the organization; however, common performance metrics for HR groups can work against filling positions with the best candidates. Our study found that HR groups that focus on “time to fill” as a measure of performance have higher first-year separation rates. The correlation was striking with the shortest average time to fill of approximately 30 days having a first-year separation rate of almost 20% (Fig. 1). The company with the longest average time to fill of 120 days had a first-year separation rate of less than 5%. This indicates that companies that spend more time reviewing, interviewing, and vetting candidates have more success keeping those people who are hired.
We found a similar trend when comparing offer acceptance rate to first-year separation rate. Our study shows that HR groups with higher college offer acceptance rates have higher first-year separation rates. At first, this seemed counter intuitive but the trend might be explained by thinking of recruiters as salesman and their product as the company; some recruiters may be overselling and not fully disclosing the details. This trend falls apart when looking at experienced offer acceptance rate. Presumably experienced people are better at selecting and vetting companies before receiving offers.
Two other peculiar correlations we found are:
Companies with higher average tenures have longer time to fill
Companies with a higher percentage of employees more than 50 years old have lower offer acceptance rates
Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 132207, ’Changing the Safe Drilling Window With Invert Emulsion Drilling Fluids: Advanced Wellbore Stability Modeling Using Experimental Results,’ by Terry Hemphill, SPE, Halliburton; William Duran, SPE, Saudi Aramco; and Younane Abousleiman, SPE, Vinh Nguyen, SPE, Minh Tran, SPE, and Son Hoang, U. of Oklahoma, originally prepared for the 2010 CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, 8-10 June. The paper has not been peer reviewed.
Often the range in drilling-fluid densities required to prevent hole collapse without fracturing the wellbore (i.e., the safe drilling window) is narrow. This often is the case for wells having high deviation angles, and is of particular concern in extended-reach-drilling (ERD) wells. With increasing stepouts, the drilling equivalent circulating density (ECD) continues to climb with increasing measured depth (MD) while the true-vertical depth (TVD) remains fairly constant.
Introduction
The drilling of challenging wells often is characterized by a narrow safe drilling window, with the fracture-initiation pressure as the upper bound and the wellbore hole-collapse pressure as the lower bound. For those cases where the collapse pressures are below the pore pressure, the pore pressure then serves as the safe-drilling-window lower bound. The safe drilling window commonly is gauged in terms of equivalent mud weight (EMW) and represents the acceptable range of density for maintaining wellbore stability. When the wellbore is circulated, for example during drilling operations, the EMW is equivalent in value to the ECD. When the wellbore is static, the EMW is equivalent in value to the equivalent static density (ESD). Depending on the downhole pressure and temperature conditions, the ESD often is not equal to the density measured under ambient conditions, especially when drilling with invert-emulsion drilling fluids (IEFs).
In the modeling of stresses around an intact wellbore, the safe drilling window becomes more narrow with increasing hole angle. Specifically, a deviated wellbore profile requires increased EMW to prevent collapse and reduced EMW to initiate fractures. Hence, in ERD wells, the safe drilling window can become very narrow at the higher angles of deviation.
In the drilling of ERD wells having long departures, the ECD will continue to increase with increasing MD, as the frictional pressure produced while circulating increases with hole length while the TVD does not increase by much, if at all. The effect of ECD in these kinds of wells serves to increase the operating EMW to the point where the upper bound of the safe drilling window can be violated and initiation of wellbore fracturing is predicted. Consequently, much effort has been focused in recent years to widen the safe drilling window safely without sacrificing wellbore stability.
Technology Focus: Gas Production Technology (November 2010)
Authors: Wilson Scott J. 
Published: February 2015

Technology Focus
Those who cannot remember the past are condemned to repeat it. George Santayana
Rarely a day goes by when a new shale-gas conference is not advertised; each will highlight the rapidly changing state of the art in fractured horizontal wells and shed light on what will always be a very complex and challenging way to complete wells. With increased interest and activity comes the need to evaluate and forecast the performance of these wells accurately with little production history as a basis. This problem has plagued engineers since the first wells were drilled in the 19th century. How does one predict the future of a new kind of well when few examples exist with enough production history to guide the forecast, and the reservoir behaviors are not understood well enough to simulate the performance mathematically?
Lessons from the past may help. Typically, a new play is ignited by an operator that is stubborn enough to keep trying new things while ignoring years of failure and the peer consensus that the operator is crazy. Soon after the secret is discovered, this newly exposed fertile ground attracts other operators desperate for better opportunities. The increased demand for leases, equipment, and services and increased regulation drive the economic returns down, not to mention the glut of production if the play lives up to its promise. Meanwhile, a new set of contrarians will begin to question the assumptions that created the boom in the first place; because rarely is there enough history to definitively prove the long-term outcomes before most have lost interest and moved on to the next hot play.
Buffering this emotional ebb and flow are operators who are not swayed by the prevailing thought. The selections for this month’s feature are examples from those who diligently look for patterns from the past to improve their accuracy in predicting the future.
Gas Production Technology additional reading available at OnePetro: www.onepetro.org
SPE 127919 • “Analysis of Data From the Barnett Shale Using Conventional Statistical and Virtual-Intelligence Techniques,” by Obadare O. Awoleke, Texas A&M University, et al.
SPE 130151 • “Enhanced Gas Recovery—Challenges Shown in the Example of Three Gas Fields” by Torsten Clemens, OMV, et al.
SPE 131714 • “The Permeability Factor in Coalbed-Methane-Well Completions and Production” by Ian Palmer, Higgs-Palmer Technologies
A Compression Strategy for Tight Gas Wells in South Texas
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124869, ’Low Pressure System for Gas Wells: Do We Need It? How Low Should We Go? A Compression Strategy for Tight Gas Wells in South Texas,’ by Quynhthy Bui, SPE, Larry Harms, SPE, Efren Munoz, SPE, and Joe Becnel, SPE, ConocoPhillips, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.
In a large field with thousands of wells of different ages and qualities, determining the optimum operating pressure is a challenging task. This study looks at the Lobo field in south Texas, which has approximately 1,800 tight gas wells currently in production, to determine the effect of pressures on recovery and the benefits vs. costs of compression. Wells were divided into three groups that share similar characteristics and were modeled using integrated-production-modeling tools to evaluate recovery vs. line pressure.
Introduction
Initial field development began in the late 1970s. As the field matures, reservoir pressure declines, and as a result, so does production. Optimizing production requires optimizing surface pressures. The continuous drilling program, while adding to potential recovery, exacerbates the optimization challenge because the mixture of older and newer wells has a large range of pressure needs. The long lead time of compression projects, combined with the flow and load-up characteristics of numerous wells, can result in a significant range of uncertainty for design volumes. Timing, location, horsepower, capacity, throughput, and compressor configuration are some of the numerous variables that need to be determined, with constantly changing needs. Addressing questions on this issue presented a unique opportunity for a multifunctional team of reservoir, production, facility, and operation disciplines to work out a compression strategy. It was necessary for the team to work together to align goals and production philosophy and to manage a balance between top-priority projects in the short term and longer-term projects. A strategy that balances the costs and benefits of compression for the different types of wells was developed. The full-length paper focuses only on the methodology used to determine the benefits and estimated costs of reduction in wellhead pressure, including timing of compression.
Definitions and Descriptions of Process
The general characteristics of the wells were evaluated to determine the best modeling methodology. The wells produce from the Lobo Lower Wilcox sands at depths ranging from 7,000 to 13,000 ft. These are typical tight gas plays, with permeabilities from .01 to 1 md and net pays from 15 to 150 ft. The average production rate per well in the field currently is less than 200 Mcf/D.
Spectrum: Training for Your Future
Authors: Thakur Ganesh 
Published: February 2015

President's column
This is a great time to be an engineer. Global workforce changes and other challenges today present tremendous opportunities for personal growth and career advancement. We E&P professionals are witnessing an extraordinary convergence of factors that are reshaping the energy workforce and will profoundly impact our industry and our careers. I would like to share with you my thoughts on this situation and suggest how SPE can help members maximize their opportunities for professional growth.
According to the latest Schlumberger Business Consulting (SBC) HR Benchmark survey,* four global workforce realities are significantly shrinking the availability of technical talent in our industry: the “big crew change,” the shortage of mid-career professionals, the shift to more unconventional oil and gas resources, and post-Macondo regulatory challenges.
The big crew change, long talked about, is now in full swing. An entire generation of Baby Boomers, who entered the work force in the late 1960s and early 1970s, is moving on to other activities. The SBC survey found that about 25% of the current experienced workforce of petroleum engineers and geoscientists is over age 50, with the majority likely to retire in the next 3 to 5 years. This amounts to about 22,000 experienced professionals expected to leave the industry by 2014. The SBC survey also found that graduate schools are expected to replace only about 17,000 of those in that same time period, leaving the industry with a technical talent gap of 5,000 experienced professionals in the next several years.
At the same time, to meet the growing demand for energy, the industry must use ever more complex and sophisticated technologies. That will require that our E&P professionals stay current on the latest technologies and their applications. How can SPE help you respond to these challenges and better enable you to ply your engineering skills in an energy-thirsty world?
SPE does many things extremely well, such as meetings and publications. But there are some areas, such as training and education, where we can focus more attention. That is one area where SPE is already making great efforts. Today, SPE offers more than 80 training courses** to help you solve real-world problems. You can find our courses across the globe, held in conjunction with SPE conferences and workshops as well as at our regional training centers in Calgary, Houston, and Dubai. Courses are also offered in other venues to meet member needs.
** “2010 SBC Oil & Gas HR Benchmark, Schlumberger Business Consulting, March 2011 (www.sbc.slb.com/SBCInstitute).
** See www.spe.org/training/.