bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Heavy Oil (March 2010)
Authors: Matthews Cam 
Published: February 2015

Technology Focus
What does the term “heavy oil” mean to you, the broad JPT readership? There are of course the various formal definitions that are tied mainly to API-gravity values (i.e., commonly 22°API), while others reflect both oil density and viscosity (preferentially referring to in-situ conditions). In general, however, recent literature suggests that heavy oil means quite different things to different people throughout this industry because it is used to cover a wide spectrum of reservoir conditions and field developments.
Only a decade or so ago, papers written about heavy oil typically referred to developments in Canada, China, USA (California), or Venezuela. Now, however, papers describing heavy-oil projects cover a much broader range, both geographically and in terms of the reservoir conditions involved, with a key distinction between onshore and offshore developments. Now, various types of onshore heavy-oil developments are under way in many countries and regions including the Middle East (Kuwait, Oman, and Saudi Arabia), Russia, Africa (Chad, Nigeria, Tunisia, and Libya), USA (Alaska), India, and Europe. Over the past few years, interest has grown rapidly in developing heavy-oil deposits off-shore Brazil, Mexico, Africa, China, Italy, Trinidad, Cuba, and elsewhere. These offshore fields include both carbonate and sandstone reservoirs with in-situ oil viscosities typically less than 400 cp. While such viscosity values are quite low relative to traditional onshore heavy-oil developments, they certainly can present significant technical challenges in an offshore environment.
The diversity among these recent heavy-oil developments is significant in terms of the recovery strategies being pursued and the technical challenges that must be overcome. These challenges include choice of recovery method, reservoir characterization and performance, complex-well-design and well-integrity considerations, production and artificial-lift difficulties, as well as fluid-processing difficulties.
The papers included in this feature were selected to showcase the wide range of heavy-oil developments under way throughout the world and the novel strategies and technology pursuits that go along with them.
Heavy Oil additional reading available at OnePetro: www.onepetro.org
PETSOC 2009-067 • “Evaluation of Recovery Technologies for the Grosmont Carbonate Reservoirs” by Q. Jiang, SPE, Osum Oil Sands Corporation, et al.
SPE 113625 • “The Zatchi B Heavy-Oil-Reservoir Development: The Unique Challenges of the TAML6 Multilateral Well ZAM-408ML” by L. Tealdi, SPE, Eni Congo, et al.
SPE 115240 • “Key Technologies of Polymer Flooding in Offshore Oil Field of Bohai Bay” by W. Zhou, China National Offshore Oil Corporation, et al.
SPE 121381 • “When Water Means Oil: Block 16 Case History” by C. Correa Feria, Repsol, et al.
En Route: Innovation and Creativity Needed
Authors: Labastie Alain 
Published: February 2015

President's column
Hydrocarbon resources are huge and may be sufficient to satisfy demand for another 100 years or more. But these abundant resources are mostly unconventional hydrocarbons, which are challenging to produce. We will have to deal with shale gas, coal seam gas, bitumens and extra-heavy oil, very tight reservoirs, extreme environments (like ultradeepwater and arctic environment), and oil shales. Also challenging is the oil to be produced by increasing substantially the recovery factor of our existing fields. Putting these hydrocarbons into production will require technology and innovation, capital, and staff well skilled and sufficient in number.
Innovation will be one of the keys for unlocking future production—new problems will need new solutions. Our innovation will be dependent on how rapidly we develop technology and our creativity in applying that technology. We’ll need new technology in all domains of our activity, including exploration (more subtle traps), appreciation (more complex reservoirs), drilling (cheaper, deeper…), and development and production (new problems due to the nature of the reservoir and the environment). Our creativity will be required to find really new solutions, through step-changes in applications as well as significant new uses of technology.
Certain conditions are needed for creativity to develop well.
Company culture should not be too risk averse (without compromise on safety, obviously!). I believe that in the last 20 years or so, our industry has in general been less innovative and has taken fewer risks than in the past, simply because it was not required, as we had a lot of “easy” production on the radar screen. But we are entering a new era of challenges, and we can already see a change in the attitude of the industry (in the domain of exploration, for example).
Staff should not be overloaded with everyday work, but on the contrary should have some degree of freedom to think forward. This means that a management style that favors creativity is needed. This also means that the historical trend of decreasing the staff count per barrel (or equivalent) produced should be at least stopped.
Staff should be diverse. Diversity in education, cultural background, experience, and gender is also essential to encouraging creativity. I believe that an organization with a staff mostly of male petroleum engineers coming from a small group of universities in the same country would be poorly positioned to address the oncoming challenges.
Swift Acceptance of Innovative Technologies Will Reap Rewards
Authors: Liddle David 
Published: February 2015

Guest editorial
It is a hard fact that it is tougher to bring new technology to market in the oil and gas industry than any other, excluding only space exploration. It can take on average up to 16 years from concept to full field deployment, which is almost twice as long as most other sectors. Greater collaboration is a key to breaking down some of the barriers that will help address the many challenges our industry faces.
The common drivers of how to find new resources, maximize recovery of existing reserves, operate fields safely, and ultimately, do it cost effectively will never change, but the mechanisms to propel us forward as an industry will need to. This will require a much bigger investment in research and development to enable ground-breaking technologies.
New technology can make mature fields more cost effective and allow small field developments to become economically viable. The importance of innovation cannot be stressed enough in helping organizations deal more efficiently with a volatile economy. That is why the rate of implementation of proven new technologies needs to be increased.
Full-scale tests must, of course, be completed before a technology can gain market acceptance. Commercializing technology in the oil and gas market place can be costly and time intensive. With many technologies destined for hostile and sometimes remote environments, such as deep waters or high-pressure/high-temperature wells, new developments need to undergo extensive testing and field trials to prove their capability.
Over the past few decades there has been a definite shift in the source of new technology. In the 1980s major oil and gas companies began to decrease their research and development (R&D) spending driven in the main by a decision to “buy versus build.” As a result, service companies stepped in to partially fill the gap by increasing their R&D spend. Nevertheless, it was only a few years ago that the oil and gas industry was at the top of the league for increased R&D spend, but the recession in the global economy put a dramatic dampener on that position.
The UK Continental Shelf is recognized globally for its excellence in mature province value realization through the accelerated development and use of new technology and innovative practice. There is a strong need to maintain that position through knowledge and skills retention, and stimulation of the innovative community to maintain a creative environment. Also, there exists in the UK an opportunity to transfer some of these skills to other energy industries that should be realized to ensure that the industry capture the ambition of becoming an energy hub now and beyond oil and gas.
BHP Billiton Forges Ahead With Large, Complex Projects
Authors: Donnelly John 
Published: February 2015

Company Profile Series
Editor’s note: This is the latest in a series of profiles of leading operators, including key international and national oil companies around the globe.
Although it may be known more for its mining business than its petroleum ventures, BHP Billiton has quietly built an impressive portfolio of large-scale oil and gas upstream projects throughout the world. Its strategy is to continue to undertake massive, complex projects, using a balance sheet that offers a long-term view of its holdings.
BHP Billiton Petroleum—one of the core pieces of the BHP Billiton Corporation based in Australia—has exploration, development, production, and marketing activities in more than a dozen countries around the globe, including a significant deepwater position in the Gulf of Mexico, as well as operations in Australia, the UK, Africa, the Middle East, and Asia. Its worldwide oil exploration organization is located in Houston.
The company’s core upstream oil and gas philosophy is to strive to be diversified globally while focusing on largely proven basins, such as in the US Gulf of Mexico and Australia. The firm also has a range of promising prospects in the South China Sea, Trinidad and Tobago, Algeria, Pakistan, and Malaysia.
BHP Billiton produced 158.6 million BOE in 2010, a 15% increase over 2009 and has posted an 11% compound annual growth rate for output since 2007. Projects in the Gulf of Mexico and Australia contributed largely to the output increase. The firm has had more than 100% reserves replacement the past four years, said J. Michael Yeager, chief executive of BHP Billiton Petroleum. The outlook for production growth this year is flat, however, because of the impact of the drilling moratorium in the Gulf of Mexico brought on by the Macondo disaster.
The petroleum sector’s strategy mirrors that of the larger corporation, with a focus on large projects with a long life span. That makes BHP Billiton different from many of its peers that have smaller assets, said Yeager. In 2010, the company spent more than USD 800 million on exploration and USD 2 billion on development. The spending allowed four major projects to come on stream last year, the latest of which was the Pyrenees oilfield development offshore Western Australia. Pyrenees, the Stybarrow FPSO development in Western Australia, and the Neptune and Shenzi tension leg platforms (TLPs) in the deepwater Gulf of Mexico are examples of the company’s large, technically challenging projects in diverse environments, Yeager said. Over the past four years, the company has tripled its upstream acreage and begun its most aggressive drilling campaign to date.
Technology Focus: Production Operations (March 2011)
Authors: Alhanati Francisco J.S. 
Published: February 2015

Technology Focus
While most operators track the amount of water that they produce (a lot), associating a cost figure to it is more difficult. And while there are some obvious cost items, such as drilling and completing disposal wells or chemicals used to enhance oil/water separation, other costs are not that straightforward, such as the share of the artificial-lift and/or corrosion-control costs associated with the water production. A commonly used rule of thumb is USD 0.50/bbl of water; however, this figure can be much higher (e.g., USD 2.00/bbl of water), depending on circumstances. Therefore, when water cuts reach the 90–95% range, operating costs associated with water production can become a significant portion of the total operating costs.
Dealing with this issue adequately is a great challenge. So much so that some believe that accepting to be in charge of a company’s “water-management” strategy is likely a bad career move. Any solutions that involve high capital expenditures, such as a facility expansion, usually are ruled out on the basis of a low rate of return or long-term payout. On the other hand, attempting to use the available water-shutoff technologies often is considered a very risky proposition because results often are uncertain or very short-term; at a minimum, they usually require very good knowledge of the reservoir to be successful. Generally, from an economic standpoint, only options that allow for the upside of more oil production (for instance, by increasing reservoir recovery or debottlenecking an existing facility so that existing wells can produce more) are attractive enough. Nevertheless, as some of the papers featured in this issue (or listed below) illustrate, some people have achieved success. So, there is hope!
Production Operations additional reading available at OnePetro: www.onepetro.org
SPE 131055 “Thief Zones and Effectiveness of Water-Shutoff Treatments Under Variable Levels of Gravity and Reservoir Heterogeneity in Carbonate Reservoirs” by Shawket Ghedan, SPE, Petroleum Institute, et al.
SPE 132253 “Water Management vs. Water Control: Profitability, Not Cost, Driving the Paradigm Change” by E.P. Anthony, SPE, Staatsolie Maatschappij Suriname, et al.
SPE 139336 “An Integrated Methodology for Water Management Under Operational Restrictions” by Eduin O. Munoz Mazo, State University of Campinas, Brazil, et al.
SPE 139308 “Laboratory Development and Successful Field Application of a Conformance Polymer System for Low-, Medium-, and High-Temperature Applications” by J. Vasquez, SPE, Halliburton, et al.
Fiber Optic Sensing - Learning How It Really Feels Downhole
Authors: Rassenfoss Stephen 
Published: February 2015

Fiber optic sensing
Magnus McEwen-King describes his company’s vision by saying it is out to build “the Earth’s nervous system.”
The company, Qinetiq, has a venture, OptaSense, which is developing practical ways to use fiber optic cable for distributed acoustic sensing in oil wells. It is essentially installing a long string of digital microphones in a well. In partnership with Shell, the former British defense contractor has created systems that track what is happening during hydraulic fracturing and record sound waves during seismic testing.
Baker Hughes has a partnership with Shell covering the sense of touch. It is using specially modified fiber optic cable to measure small changes impacting 40-ft-long sections of a well in the US Gulf of Mexico deepwater Mars field. The recently completed injection well has also been wired with fiber optics gathering temperature, pressure, and sound data.
Shell’s third venture, with a Dutch company named TNO, will try to sniff out changes in well chemistry using fiber optic cables coated with specially formulated gels. The gels are designed to absorb specific molecules. When the concentration of the target chemical, such as carbon dioxide, increases, the gel absorbs more of it and swells, which is observed by the sensitive fiber.
Shell’s goal is to create permanent monitoring systems that make intelligent wells smarter by observing conditions inside a well, meter by meter. Vianney Koelman, chief scientist and fiber optics program leader at Shell International E&P, said fiber optics can directly gather information that helps answer pressing questions, including “‘Is a well producing the way I think it is producing?’ ‘Is it working the way the computer model is telling me?’ It can be quite different than what you think.”
Fiber optic temperature measurement systems—ranging from gauges using fiber for measurements in one spot to fiber doing meter-by-meter measurements throughout a well—have been installed in thousands of wells going back to the mid-1990s. The fastest growth has been in heavy oil fields where temperature monitoring improves the efficiency of high-temperature steam injection systems used to coax heavy oil out of the ground.
New Global Awards Launched for Petroleum Engineering Faculty
Authors: Howes Susan , Heinze Lloyd 
Published: February 2015

Talent & Technology
At the 2010 SPE Colloquium on Petroleum Engineering Education, discussion focused on the challenges that petroleum engineering faculty face. Fig. 1 illustrates the trend of the increasing ratio of student to faculty in US petroleum engineering schools over the past two decades. Although the data are not available, we believe that similar trends exist internationally.
A survey of US petroleum engineering faculty demographics (Fig. 2) shows that 30% are over age 60, 38% are age 50-59, and 32% are under age 50. While some professors may continue to teach past the traditional retirement age of 65, this data indicates that about 30% or more of current petroleum engineering faculty may retire in the next five years.
As a result of the colloquium’s findings, a task force was commissioned by the SPE Board of Directors Subcommittee on Educational and Professional Activities to look into the recommendations on attracting, developing, and retaining faculty worldwide. The task force used survey methods and focus groups to determine root causes for the petroleum engineering faculty shortage and to make recommendations in three areas:
What universities can do
What the industry can do
What SPE can do
Based on survey results, some of the root causes of the problem appear to be:
Competition with the industry with respect to compensation
Lack of a pathway for petroleum engineering PhD candidates
Insufficient research funding/sources to support new faculty
The industry and petroleum engineering departments share a symbiotic relationship as students with petroleum engineering degrees are uniquely qualified for work in the energy industry. Unlike other disciplines, petroleum engineering graduates work primarily in the petroleum industry. The industry also expects them to be able to contribute immediately upon employment. Without good instruction, new graduates may not be adequately trained. Fig. 3 illustrates the cyclical nature of the number of bachelor’s, master’s, and PhD degrees in petroleum engineering granted in the most recent 40 years in the United States.
Although there is a concern that history will repeat itself in that the steep rise in undergraduate enrollment will be followed by an equally steep decline, a comparison of the trend of petroleum engineering freshmen enrollment between the 1973–1992 period and the 2001–2020 period shows striking differences in the influx of freshmen (Fig. 4).
Technology Focus: Hydraulic Fracturing (March 2012)
Authors: Olson Karen 
Published: February 2015

Technology Focus
Hydraulic Fracturing: 2012 and Beyond
It is a good time to be in the oil industry. The rig count, drilling activity, and oil prices are high, and shale plays are a significant reason for each. And, because it is shale, it is an especially good time to be a completion engineer!
Even though we have been able to make these unconventional reservoirs economic by drilling horizontal wells and by multistage fracturing, it is important for us to realize (especially with low gas prices) that there is still plenty to learn about shale fracing (not spelled “fracking”). Buzz words fly around the industry: complex fractures, brittle vs. ductile shale, proppant transport in slickwater, and more. Each is a start, but what I challenge everyone to do is to ask the questions: What is really happening when we are fracturing the various shale plays; and how do we model it so that we can predict and optimize performance?
Economic and political implications of shale are enormous. The USA recently, for the first time in many years, became a net exporter of energy. The USA has clear shale-development advantages compared with other countries at this time because it has the rigs, hydraulic horsepower, personnel, and a long history of hydraulic fracturing.
But truth be told, there are disadvantages that must be dealt with. The USA is dealing with an oversupply of gas, which is reducing prices and making shale-gas plays marginally economical. To date, despite industry efforts, there still is no political will to substitute fuel sources on a large scale, create a widespread gas-fueling infrastructure, or increase automobile shale-gas usage appreciably.
So even though it is a good time to be in the oil field, remember that as completion engineers it is our job/duty to understand what is happening downhole when we are fracturing—Do we really have complexity? Does complexity occur in every shale interval or just the brittle ones? Does proppant “turn the corner” and go into the natural fractures? Knowing the answers to these and other questions can make the economics of shale plays become even better.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 147652 An Experimental Investigation of Spontaneous Imbibition in Gas Shales by B. Roychaudhuri, University of Southern California, et al.
SPE 139984 Hydraulic Fracture Crossing a Natural Fracture at Nonorthogonal Angles: A Criterion, Its Validation, and Applications by H. Gu, University of Ganguly, et al.
SPE 147248 Revisiting Microfrac In-Situ-Stress Measurement Through Flowback—A New Protocol by Alexei A. Savitski, SPE, Shell, et al.
Fracturing-Fluid Effects on Shale and Proppant Embedment
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146658, ’The Effects of Fracturing Fluids on Shale Rock-Mechanical Properties and Proppant Embedment,’ by Ola Akrad, SPE, Jennifer Miskimins, SPE, and Manika Prasad, SPE, Colorado School of Mines, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.
Development of shale reservoirs has grown significantly during the past few decades, driven by evolving technologies in horizontal drilling and hydraulic fracturing. The productivity of shale reservoirs depends highly on the design of the hydraulic-fracturing treatment. To design a successful treatment, a good understanding of the shale mechanical properties is necessary. The results of this study show that the greatest reduction of Young’s modulus occurs at high temperature and in samples with high carbonate content.
Introduction
In geology, shale traditionally has been defined as a sedimentary rock containing a high percentage (&gt;50%) of clay and lower percentages of silica or carbonate minerals. However, many current shale prospects are not shales as defined in geology. Instead, they are “prospective-shale” reservoirs: fine-grained clastics characterized by ultralow permeability and usually composed of silica and carbonate minerals with a small amount of clay.
Success in these shale systems depends largely on excellent hydraulic-fracturing designs that require a good understanding of the mechanical properties of the subject and confining formations. In hydraulic-fracturing design, Young’s modulus is a criterion used to determine the most-appropriate fracturing fluid and other design considerations. Young’s modulus provides an indication of the fracture conductivity that can be expected under the width and embedment considerations. Without adequate fracture conductivity, production from the hydraulic fracture will be minimal, or nonexistent. This study of Young’s modulus shows a significant decrease in the presence of certain fluids. Such decreases in Young’s modulus lead directly to decreases in fracture conductivity and, therefore, should be taken into account when designing the treatment to obtain a required fracture conductivity in a given reservoir.
Methods and Testing Procedures
It is known that fracturing fluids can affect the formation face of the created factures and cause damage. This damage can manifest itself as filter cake, fluid imbibition, and other damage mechanisms. A possible additional damage mechanism in prospective-shale systems is the potential weakening of the rock frame or modification of Young’s modulus, which could allow additional proppant embedment to take place. Such embedment, if occurring, could affect the fracture conductivity of a given treatment adversely.