bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reservoir-Fluid Characterization From Tests on Tight Formations
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164887, ’Reservoir-Fluid Characterization From Tests on Tight Formations,’ by Brian Moffatt, Michael Fawcett, Jaimar Maurera, and Anna Bruzco, Petrophase, prepared for the 2013 European Association of Geoscientists and Engineers Annual Conference and Exhibition incorporating SPE Europec, London, 10-13 June. The paper has not been peer reviewed.
Drillstem testing of low-permeability reservoirs is challenging because high-pressure drawdown around the wellbore lowers fluids below saturation pressure and creates two-phase flow into the wellbore. The fluids produced at surface no longer represent the original reservoir fluid. This paper shows the benefits of a careful methodology of data selection and equation-of-state (EOS) modeling to validate data used to characterize the reservoir fluid.
Introduction
There are significant technical difficulties in capturing representative fluid samples from tight formations. Attempts to flow to surface from tight formations induce a fall in pressure around the well-bore that may take the reservoir oil or gas below its saturation pressure. Two-phase flow in the wellbore can cause significant errors for sampling downhole, although surface sampling can be less prone to error. However, because the gas within the formation is more mobile than liquid, the surface gas/oil ratios (GORs) are higher than those of the native fluid. This can lead to erroneous assumptions about the reservoir fluid if the separator samples are recombined to the prevailing GOR without reference to what is happening in the reservoir.
Two case studies are presented that resolve apparently conflicting data and use a wider range of well-test data than single data points to define reservoir fluids. Neither study had the benefit of downhole pressure/depth gradients to corroborate reservoir-fluid properties.
Characteristic Test Results for Tight-Formation Drillstem Tests (DSTs)
DSTs performed where the flowing bottomhole pressure (FBHP) stays above saturation pressures are ideal for surface sampling or for taking bottomhole flowing samples. However, the low deliverability of tight-formation wells often makes it difficult to establish stable flowing conditions. The FBHP, flowing well-head pressure, and separator conditions may all be unstable, causing difficulties in establishing the correct GOR even when the total wellbore composition is constant. A further complication can arise if the gas rates are too low to lift liquids to the surface.
GORs for bottomhole samples (BHSs) are measured in the laboratory by flashing the sample to specified conditions. The same wellstream composition sampled at the surface will normally have a lower GOR because separator conditions favor an increase in stable liquid volume. Surface and bottomhole GORs will match only under identical flashing conditions. Typical GOR characteristics for BHSs and surface samples for a tight formation containing oil are shown in Fig. 1.
Review of Water Use at Canada's Oil Sands Points Toward Environmental Sustainability
Authors: Wilson Adam 
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156676, ’Water Use in Canada's Oil-Sands Industry: The Facts,’ by Stuart Lunn, Imperial Oil Resources, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.
Concerns have been expressed and published about the amount of water used in Canada’s oil-sands industry. The oil-sands deposits are geographically separated from population and agricultural centers in the province of Alberta and are within some of the most prolific river basins. Analysis shows that the amounts of water used by oil-sands operations are low and sustainable. A track record of continuous improvements at existing operations and the application of new technologies will maintain the sustainability into the future.
Introduction
Canada’s oil sands are in three deposits in northern Alberta (Fig. 1). The oil-sands deposits hold 1.8 trillion bbl of oil with 169 billion bbl of economically recoverable reserves. This represents 97% of Canada’s oil reserves, which are the third largest in the world.
The term “oil sands” is used to describe unconsolidated bituminous sands. The oil saturation in the sands has very high viscosity and is commonly called bitumen or tar. The deposits are found within the McMurray, Clearwater, and Grand Rapids formations of the Mannville group. They are of varying depth, from near surface in some parts of the Athabasca deposit to more than 300 m deep in the Peace River and Cold Lake deposits. Where the oil sands are shallower than 70 m, they may be mined by surface strip mining. This represents 3% of the surface area of the oil sands and 20% of the reserves. The remaining 80% of reserves across all three deposits are accessible only by use of in-situ recovery methods. Both mining and in-situ methods are water based.
How Water Is Used in Canada’s Oil Sands
Because of the high viscosity of the bitumen within the oil sands (8–12°API, &gt;50,000 cp), it does not flow easily and is difficult or impossible to recover with conventional oil methods. The vast majority of commercial operations rely on hot water or steam to reduce the viscosity of the bitumen to allow its recovery.
For in-situ methods, this involves the injection of steam into the oil-sands reservoir and subsequent recovery of the bitumen once it is reduced in viscosity. For mining, the water is used to slurry the oil, transport it, and finally separate it from the ore.
The Search for Rock Testing Tools That Are Better Than a Drill Bit
Authors: Rassenfoss Stephen 
Published: February 2015

Rock Scans
Whiting Petroleum has made an extraordinary commitment to rock testing. In its office tower in downtown Denver, its digital rock imaging laboratory analyzes about 6,000 ft of core samples each year, examining details down to pores only a few nanometers across.
When evaluating new plays, or considering alternative plans for its proven fields, the independent oil company uses a battery of imaging devices. The common question faced is: “Is it going to work?” said Lyn Canter, a senior geoscience adviser who manages the laboratory at Whiting.
She has been asked the same question by other companies considering whether there is a return for investing in in-house rock imaging. Her answer is: “We think it gives us a competitive edge” by providing timely answers to questions raised by complex tight oil formations, many in the Niobrara and the Bakken, that cannot be answered using routine core testing methods.
One example of its value was that Whiting decided not to go forward with a costly proposed field development project after rock tests indicated it was not permeable enough to support profitable production, Canter said. While she said the equipment has paid for itself at Whiting, it represents an unusual level of support, which would be difficult for others to replicate.
Service companies see growing interest in digital rock testing, but few companies regularly use digital imaging as a reservoir analysis tool, and only a couple of majors in the United States have their own in-house equipment, Canter said.
Generating credible results likely to influence decision makers has required a significant, long-term commitment of equipment, skilled personnel, and the time needed to develop the workflows for generating results that exploration teams will use. This requires selecting representative samples, as small as a grain of sand, to image the pore-scale details from complex rocks with features that are consistently inconsistent.
The tools and processes needed to turn observations of the rock microstructure into measurements is an emerging technology. As a result, engineers are the ones asking the toughest questions about the results, she said.
“We want engineering to buy in to what we are doing,” Canter said, adding, “They are naturally skeptical, but can be convinced by making a good case that the results offer a view of the average properties of the larger reservoir.”
Technology Focus: Formation Evaluation (August 2014)
Authors: Harrison Bob 
Published: February 2015

Technology Focus
Any oil and gas deal, whether it is acquisition, divestment, greenfield, brownfield, or out of left field, usually involves a data room, where rich seams of proprietary information can be mined for a limited period. However, this physical data room, as opposed to a virtual version where data are downloadable, is the bane of due diligence.
Some may recall caffeine-fueled assignments to paw through boxes brimming with confidential documents that allegedly held the financial secrets of a potential acquisition. The process is expensive; can be a logistical nightmare of travel arrangements, visas, and inoculations; and is always stressful because of time pressure. Data rooms are migraine inducing.
The priority of the petrophysicist on a data-room team is to access digital data for all wells—for example, logs, wireline formation pressures, and deviation surveys for depth conversion. Often neglected are the log headers themselves, which provide data on tool setup, bottomhole temperature, mud properties, and the casing program and present the logging engineer’s comments. Gathering data is less straightforward if they are in an unfamiliar language or are vintage (noncombinable tools with unfocused measurements requiring more runs). These factors require translation, tool response modeling, and increased depth matching, adding time, cost, and potential for error.
Petrophysicists audit the hydrocarbons in place by reviewing previous studies to confirm the all-important trinity of porosity, water saturation, and net pay claimed by the seller. The appropriateness of the saturation-height function in the geomodel is checked for the assumed hydrocarbon and rock type, or merely to ascertain that one was used at all. Proposed fluid contacts must be verified, no mean feat when faced with structure maps showing only oil-down-to (ODT) and water-up-to (WUT) depths, with the contact possibly being anywhere in between. Some companies assume that the fluid contact is halfway between ODT and WUT, which is a completely arbitrary approach.
In these digital days, almost everything needed to carry out petrophysical due diligence can be downloaded for off-site analysis. However, there are places where it is illegal to take data out of the country, so physical-data-room attendance is compulsory. In these instances, as in the past, the petrophysicist’s briefcase might hold color pencils, a ruler, tracing paper, chart books, and maybe a planimeter, a strange device for measuring areas within mapped contours. Yet painful memories suggest that the most important piece of equipment one should take along to a data room is probably a bottle of aspirin. JPT
Technology Focus: Health, Safety, Environment, and Social Responsibility (August 2014)
Authors: Garland Emmanuel 
Published: February 2015

Technology Focus
Stakeholders—especially those who do not like the oil and gas industry—have great expectations and are creative. We need to be more creative than they are. Does that mean that we need to do more? Certainly. But, more importantly, we need to do it better. And better sometimes means simpler. Complexity is a poison, a smoke screen that prevents us from seeing the picture correctly and making the right decision.
The journey continues. That was the motto of the last SPE International Conference on Health, Safety, and Environment (HSE), which took place in Long Beach, California, 5 months ago. It underlines that HSE is not perceived anymore simply as a priority (as it was 10 years ago) but as both an asset and a value, and that we are on that road for years. HSE will disappear from our radar screen only when we have integrated it fully into our culture, when it becomes as natural as swimming or cycling, something that may not be instinctive but, once we have learned it, once a coach and practice have instilled it in us, it is in each of us, once and for all. Will it be definitively incorporated? Not really. If we do not practice, we will forget it, as happens with foreign languages. And that is because HSE culture is not a natural language. Not only do we have to learn it, but, on top of that, it evolves. New techniques and new challenges emerge every year.
The HSE conference in Long Beach was attended by more than a thousand professionals. Many high-quality technical sessions were presented, and plenary and panel sessions addressed the current status and shaped the future. Nongovernmental organizations attended, challenged us, and had a chance to see what the industry really does. I encourage you to look at OnePetro, the SPE online library, and download papers. You will not waste your time. Some are really good. You will find updates on best practices, case studies, new technologies, and much more. Competency is the cornerstone of good HSE performance, and we must strive at being up to date. JPT
Water-Resource-Management Guide Offers Method for Identifying, Managing Risk
Authors: Wilson Adam 
Published: February 2015

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 168520, ’One Company's Upstream Water-Resources-Management Guide,’ by Stuart R.D. Lunn, SPE, Imperial Oil, and Mark R. Decatur, Michael L. Allen, and Rick A. Mire, ExxonMobil, prepared for the 2014 SPE International Conference on Health, Safety, and Environment, Long Beach, California, USA, 17-19 March. The paper has not been peer reviewed.
While water issues are often location- and situation-dependent, a standardized guide to water-resource management has been developed for upstream oil- and gas-production projects and operations. The guide provides environmental, regulatory, and socioeconomic practitioners with a consistent and effective method to identify, assess, and manage water-resource-related risks and opportunities. The guide has four steps, each with embedded and scalable tools—data acquisition, data analysis, risk assessment, and risk management.
Introduction
The availability and quality of freshwater resources, coupled with increasingly stringent regulatory requirements in many locations, continue to challenge the oil and gas industry. Accordingly, the industry recognizes its responsibility to surrounding communities and to the environment regarding its management of fresh water. One company’s water- resource-management program is built upon a framework of principles designed to help manage interactions with water in order to
Protect human health and the environment
Consider local water needs when addressing operation requirements
Continuously improve technologies, practice, and performance
Engage stakeholders in development of sustainable water solutions
In order to provide environmental, regulatory, and socioeconomic practitioners with the knowledge and methods to implement these principles, an upstream water-resource-management guide was developed. The guide does not contain any new requirements but rather is intended to function as a road map for practitioners to help them manage water resources more effectively within the context of existing internal requirements and external considerations, constraints, and requirements.
The objectives of the guide are to
Enhance the quality of data gathered regarding the use of water resources
Identify and manage water-related risks
Assist in the application of appropriate technology and operational practices to improve water-use efficiency and safeguard water quality
Interview with 2011 SPE President Alain Labastie
Authors: Labastie Alain , Donnelly John 
Published: February 2015

President's interview
Alain Labastie is engineering adviser, EOR Technologies, for Total and is based in Pau, France. He began his career in 1976 at Elf and has held numerous positions in reservoir engineering, primarily in R&D and technology development. His positions have included R&D Program manager, head of R&D Operations, and head of Advanced Reservoir Techniques. Labastie also served on committees awarding public research funding for the French administration and the European Union.
Labastie served on the SPE Board as director for the South, Central, and East Europe region and is a former chairperson of the JPT Editorial Committee. He has been involved in numerous SPE committees, including the Distinguished Lecturer, Annual Technical Conference and Exhibition, International Petroleum Technology Conference and Exhibition, Europec Technical, and Forum Series committees. Labastie also chaired the SPE France Section and has been an SPE representative for the Offshore Technology Conference. He earned an engineering degree from Ecole des Arts et Métiers and a petroleum engineering degree from Institut Français du Pétrole.
How did you get involved with the oil and gas industry?
After graduating as a mechanical engineer, I decided to also earn a degree as a petroleum engineer. I was taken by what is sometimes called the romance of the petroleum industry. I wanted a wide diversity in my activities and in my career, with the possibility of discovering different countries and cultures around the world. And I have never been disappointed. I have always had fun in my career, and enjoyed many opportunities to discover new things and new people.
How did you get involved in SPE?
I started out as a young engineer in the headquarters of my company in France, and at that time SPE was not well known there and had no local section. But I had a position in R&D and used SPE literature as a reference, and I found it extremely valuable and it made a real difference in my everyday work. After a few years and some conclusive work, I submitted an SPE paper, which was accepted for the 1980 SPE Annual Technical Conference and Exhibition. It made a big impression on me and I made my first trip to the US to deliver the paper.
Then my company transferred me to Houston, and I naturally joined SPE and the Gulf Coast Section. I enjoyed attending the section meetings, where I had opportunities to discuss with colleagues almost everything in a neutral place: the start of the SPE networking experience! My interest in SPE then grew rapidly, and I volunteered for several tasks with SPE. One of my SPE mentors was Jacques Bosio, who later became the first non-US SPE president.
Nanotechnology: Coming of Age or Heralding a New Age?
Authors: Mathieson Derek 
Published: February 2015

Guest editorial
In his seminal lecture, “There’s Plenty of Room at the Bottom,” given at the 1959 annual meeting of the American Physical Society, American physicist Richard Feynman posed the possibility of direct manipulation of single atoms as a form of synthetic chemistry more powerful than the methods in use at the time. His revolutionary ideas were an invitation to enter a new field of physics, describing a set of challenges and possible solutions that would later be realized in the fields of microelectronics, microelectromechanical systems, microbiology, and be stretched even further by nanotechnology (a term introduced much later by Norio Taniguchi of the Tokyo Science University in 1974).
Carbon nanotechnology, made famous by the discovery of the buckyball (carbon sphere) in 1985, moved apace through the 1990s with the development of carbon nanotubes and, in the last few years, has experienced an exponential increase in research activities with graphene-based structures. Graphene, extracted from graphite, is a one-atom-thick sheet of carbon atoms, arranged in a honeycomb-style lattice pattern. Because of its unique electrical, magnetic, and other properties, graphene has grown central to much of the research into nanotechnology.
Today, there are some ambitious programs under way in the E&P sector exploring nanosensors and even nanorobots, but I would like to focus on carbon nanotechnology research as it relates to commercially available products and its near-term impact across many product lines.
At first glance, it might not seem obvious why nanotechnology is relevant to our industry. But the challenges in frontier areas such as deep water, unconventional hydrocarbons, and high-pressure/high-temperature applications nearly all have complex material and chemistry gaps that must be addressed to provide reliable technology solutions for these environments. In some cases, no solutions exist with the standard tool kit—so we enter the domain of the molecular designer or nanotechnologist.
So what are the basics of nanotechnology research? A nanometer (nm) is one-billionth (10−9) of a meter. A working definition of nano is “the purposeful engineering of matter at scales of less than 100 nanometers to achieve size-dependent properties and functions.” The enormous potential for carbon nanotechnology in the oil field lies largely in the design or modification of materials using the combination of the unique physical properties of the building blocks with the added chemical flexibility of benzyne-type systems (highly reactive organic species). For example, a carbon nanotube has: (1) a mechanical strength 100 times stronger than steel; (2) a mechanical modulus 100,000 times stiffer than steel; (3) an electrical conductivity similar to copper; and (4) a thermal conductivity approximately 2.5 times greater than diamond. Not a bad initial specification list.