bluuebunny/crossref_metadata_2025_split huggingface dataset:
Techbits: Digital Oilfield Developments Addressed in Joint Workshop
Authors: Moon Ted 
Published: February 2015

Techbits
More than 70 petroleum engineers and information technology (IT) professionals converged on Salvador, Brazil last October for the SPE/IBP Joint Workshop on the Digital Oilfield. The workshop's mission: to review the current status of the digital oilfield concept and to understand what remains to be done to allow the industry to meet the demands of the 21st century.
"The E&P industry has led the way in applying leading-edge computing and communications technology," said work-shop Cochair Roger Hite of the Business Fundamental Group. "Seismic processing and imaging, reservoir simulation, and many other areas have provided notable advances to our business. In the 21st century, the fast pace of technology development continues, this time with the goal of automating and optimizing operations in the oil field itself. There is a renaissance under way that promises to yield enormous gains."
The workshop was organized into sessions that surveyed key questions on how well the industry is doing in developing the digital oil field. A mixture of presentations and group working sessions were employed to cover each topic. The first session set the stage by asking "Where are we today?"
"We set out to cover the landscape and to gain a broad view of progress, rather than focus on one aspect," said Hite. "In my opening remarks I said that the concept of the digital oil field is rapidly developing into an important reality in our industry." He also stated that the conclusions drawn about the digital oil field should be framed by business issues, namely, the value gained from the decisions that can be made and implemented and by the efficiencies that can be gained by automation.
"Perhaps the key challenges facing the industry are designing infrastructures to facilitate work processes, integrating across disciplines, learning how to navigate the mountains of data now available, and preparing convincing business cases," Hite continued. These key issues were the subjects of the subsequent sessions.

Infrastructure
"Discussions of infrastructure have moved beyond ways to establish connectivity to concerns about how that connectivity should be designed to facilitate collaboration and to enable improved work processes," said Hite. This session addressed how effectively infrastructure plans fit business needs.
Global Possibilities of Future Methane and Hydrogen Economies
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: February 2015

Management
Jules Verne, the father of science fiction, wrote several books using ideas that eventually became reality. Some examples include: From the Earth to the Moon in 1866, Twenty Thousand Leagues Under the Sea in 1870 where he envisions submarines, Robur the Conqueror in 1886 where he describes the precursor of helicopters, and The Mysterious Island in 1875 where he wrote:
Yes, my friends, I believe that water will one day be employed as fuel, that hydrogen and oxygen which constitute it, used singly or together, will furnish an inexhaustible source of heat and light, of an intensity of which coal is not capable.
Vaitheeswaran (2003) asks, "Could the man who forecast the development of such technological marvels as submarines, helicopters, and space travel have gotten energy right, too?" We believe that the answer is most likely positive.
Hydrogen accounts for approximately 75% of the universe's mass and is the most abundant of all elements. Stars are made mainly of hydrogen. However, hydrogen does not generally exist in a free state in Earth. Consequently, it has to be extracted from different materials including, for example, biomass, fossil fuels, and water. This means that it takes energy to free hydrogen for use, no matter how it is produced. As a result, hydrogen is not strictly an energy source but an energy carrier much in the same way as electricity.
At present, while society is deeply concerned about the environment, hydrogen might emerge as a white knight. There is evidence that, since 1850, the relative hydrogen consumption has been increasing steadily (Fig. 1). Research shows continuous decarbonization from 1850 to 1970. At this point, the hydrogen/carbon (H/C) ratio becomes approximately constant (in the order of 1.8). Hefner (2002) describes this history for the US as follows: "For more than 100 years, free markets and the ingenuity of humankind worked efficiently to decarbonize our energy systems…. It was only starting in the 1950s, when governments began to tinker with price controls and later, reacting to the ‘sky is falling’ cries of shortages by the energy industry, allocated fuels among sectors of consumers, that we once again began to recarbonize the energy system." The recarbonization period described by Hefner occurs between approximately 1970 and 2006. However, the Global Energy Market (GEM) model tends to show a slight improvement in the H/C ratio as we advance toward the year 2030. This suggests an increase in production of natural gas which, we anticipate, will pave the way to an "energy revolution that will transform an industry, change our lives, and maybe even save the planet" (Vaitheeswaran, 2003).
Design Challenges for Wax in a Fast-Track Deepwater Project
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 19160, "Design Challenges Due to Wax on a Fast- Track Deepwater Project," by Amir Alwazzan, SPE, and Mark Utgard, SPE, AMEC Paragon, and Dalmo Barros, Petrobras America, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
Flow-assurance threats, such as hydrates, waxes, and asphaltenes, can be identified and controlled if oil and gas production and transportation systems are designed accordingly and proper operating procedures are implemented. Therefore, prevention of wax deposition is key for good subsea deepwater-system design. Wax deposition can form a blockage and impede flow, causing weeks of lost production and operating difficulties.

Introduction
Flow assurance in subsea systems is an issue in the design of deepwater-field developments. Flow-assurance efforts focus on preventing solid deposits from blocking or restricting the rate of flow from the well. The principal solids of concern are wax and hydrates. For a given reservoir fluid, these solids precipitate at certain combinations of pressure and temperature. Precipitated solids often are carried downstream, slurried in the fluid, but precipitated solids also can deposit on the walls of the production equipment, which ultimately causes high pressure drops, plugging, and flow stoppage. Control of this deposition by prevention and/or mitigation is the essence of flow assurance.
Wax in hydrocarbons is primarily paraffin, which is a white, odorless, tasteless, chemically inert compound composed of saturated hydrocarbons. The linear paraffins are easily measured by high-temperature gas chromatograph (HTGC).
Two critical issues require special attention: gel formation (precipitation) and deposition. A hydrocarbon gel forms when wax precipitates from the oil and forms a 3D structure spanning the pipe. This condition does not occur while the fluid is flowing because the intermolecular structure is destroyed by shear forces as soon it is able to form. However, when the fluid stops flowing, wax particles will interact and join together, potentially forming a network resulting in a gel structure if enough wax comes out of solution. In a pipe, wax deposition results in flow restrictions. Slow buildup of wax layers in pipelines and flowlines is caused by the solidification of the paraffinic fractions on the cold inner surface of the pipe wall. Wax deposition is expected during steady-state operation in the flowline where the production-stream temperature is below the wax-appearance temperature (WAT). The deposition rate depends mainly on the fluid characteristics, flowing and pipe-wall temperatures, heat flux through the pipeline, and the shear stress at the wall.
Solving Excessive Water Production in a Long Horizontal Open Hole
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 113700, "Solving Excessive Water Production in a Prolific Long Horizontal Open Hole Drilled in a Naturally Fractured Carbonate Reservoir," by Stephen Lightford, SPE, Halliburton, and Enzo Pitoni, Giovanni Burrafato, and Claudia Porretta Serapiglia, Eni E&P, originally prepared for the 2008 SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands, Texas, 1-2 April. The paper has not been peer reviewed.
A case history is presented of a successful operation to reduce excessive water production in a horizontal well drilled through a naturally fractured carbonate reservoir. Because the well was completed with a 940-m horizontal openhole section, there was no practical means of selectively isolating sections of the open hole. A treatment was performed using a sealant that would set up only in the presence of water. The full-length paper describes the philosophy behind the treatment design, the testing of the sealant, the placement procedure, and subsequent well performance.

Introduction
The case study is taken from a field in southern Italy that lies within a mountainous national-park area and is classified currently as the largest producing onshore field in continental Europe. Wells in the field are very-high-producing wells from a naturally fractured carbonate reservoir at approximately 3500 m true vertical depth (TVD). Permeability is difficult to predict because it is dependent on natural fracturing, which results in a wide range of production rates from individual wells. Because the field is in a national park, development is strictly controlled and wellsites are limited to fit in with the environment. Very strict governmental controls on the operations in the field help ensure that work is minimized to what is absolutely necessary. Planning to move a rig onto the wellsite normally is a long process to obtain the required authorizations and is particularly expensive because of the mountainous terrain. Rigless interventions and use of coiled tubing (CT) in the field have become widespread.
When a naturally flowing well suddenly starts producing excess water, and oil production is lost because the well is killed by increased hydrostatic pressure; there is an intense commercial driver to attempt to resolve the problem with a rigless intervention. This situation offers an opportunity to use newer techniques because the commercial benefits of a successful job make the amount of risk acceptable to an operator willing to resolve the problem. This scenario provides a rare opportunity to use untried methods, as was the case in the job described in the full-length paper.
SAGD Gas Lift Completions and Optimization: Surmont Field Study
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 117489, "SAGD Gas Lift Completions and Optimization: A Field Case Study at Surmont," by T.C. Handfield, T. Nations, SPE, and S.G. Noonan, SPE, ConocoPhillips, prepared for the 2008 SPE International Thermal Operations and Heavy Oil Symposium, Calgary, 20-23 October. The paper has not been peer reviewed.
Gas lift completions for steam-assisted-gravity-drainage (SAGD) producers are unique. Conventional gas lift valves and mandrels with a packer completion cannot be used because of the extreme temperatures of the downhole environment. Most lift gas enters the production stream downhole through open-ended tubing or nozzles, which, if not properly sized, can result in operational issues that negatively affect the overall lift efficiency. Data were collected and analyzed to determine the efficiency of two types of gas lift nozzles used in the completions. The method for optimizing SAGD gas lift systems is presented, and recommendations are made for future improvement.

Introduction
Surmont, an oil-sands project, is approximately 37 miles southeast of Fort McMurray in the Athabasca oil sands in Canada. The Surmont pilot began steam injection in 1997, comprising three SAGD-well pairs that use a variety of artificial-lift methods. These wells were tested to determine the preferred method of artificial lift for the first commercial phase.
Main steam injection was initiated in mid-2007, and conversion to full SAGD production followed in late 2007. Phase 1A comprises 20 well pairs in which all the producers were completed to produce by use of gas lift for the initial life of the well. Phases 1A, 1B, and 1C have a capacity of 25,000 B/D and are expected to reach peak production in 2012. A second phase is slated for commercial startup before the middle of the next decade, which, upon completion and full ramp-up, is estimated to bring peak production from both phases to 100,000 B/D. Additional phases at Surmont are under study.

Historical Perspective
The Surmont gas lift experience began with trials in two of the three pilot wells. The completions consisted of a single production string varying in size from 3.5 to 5.5 in. with a 1-in. coiled tubing (CT) run concentrically for gas lift and landed at the heel of the well. The bottom 2 m of the gas lift string was constructed similar to a perforated stinger with ten 11-mm orifices. These gas lifted wells operated with reservoir pressure as low as 334 psi, producing fluid rates between 1,047 and 3,352 B/D, with gas lift rates ranging from 211 to 339 Mscf/D for a total combined operating time between the two wells of 35 months.
The conclusion from testing at the pilot was that gas lift at the higher reservoir pressures was effective. However, before making additional designs and sensitivity studies, the gas lift assemblies were removed to allow for testing and validation of other forms of artificial lift for Surmont SAGD.
Q&A with Andrew Gould
Authors: Gould Andrew , Donnelly John 
Published: February 2015

As Chairman of the OE 2005 conference in Aberdeen, what issues do you think will attract particular interest at this year’s conference?
I think that general interest will be focused on how the industry can build and maintain production. There will obviously be a focus on the North Sea and the changes that will occur in the region as it becomes a mature basin. Therefore, I believe that there will be a lot of discussion about the technology needed to increase recovery factors. And there will undoubtedly be some spillover of the debate into where new production will come from and who is going to develop it. So I’m also expecting to hear discussion about the Middle East and Russia as well as on the roles of the national oil companies, the major integrated companies, and the independents.

One issue facing the North Sea region is how to manage a maturing production business. What new opportunities exist here for the service sector?
The main opportunity is to innovate to enhance recovery. North America and Canada already provide many opportunities for specialized services and specialized service companies. If you look at the Canadian market in particular, there are lots of companies that focus on one particular aspect of the business. So I think you will begin to see a service industry fragmented into specialists in particular aspects of managing and enhancing production from mature basins rather than a service industry organized around large development projects. Technology in the North Sea will become more and more fit for purpose if companies can justify the enhanced recovery process at a reasonable cost. So there will be many opportunities for both the big service companies as well as the smaller, local service operations.
OTC Sessions Confront Technical, Human Challenges Facing Industry
Authors: Donnelly John , Denney Dennis , Langley Diane 
Published: February 2015

A healthy oil and gas industry fueled by high commodity prices provided the backdrop to a record-setting Offshore Technology Conference (OTC) in Houston.
The annual event posted a 20-year high in attendance at 51,320 and attracted more than 2,000 exhibiting companies (Fig. 1).
Amid the upbeat mood of an industry enjoying profitable times, speakers at the conference offered a clear-eyed view of the challenges confronting an industry that needs to produce more hydrocarbons to satisfy thirsty global demand. Peter J. Robertson, Vice Chairman of Chevron Corp., laid out those challenges in his keynote address at the OTC Awards Luncheon, including surging demand Robertson growth, geopolitical instability, increasingly complex projects, and consumer demand for cleaner fuels with minimal environmental impact. “To me the interesting part is that none of these items are particularly new, but the volume on all of them has been turned up and the combined effects of all of them operating in unison is putting a strain on our collective capabilities,” he said.
Those challenges will require huge financial investments. Robertson said that Chevron’s “big 5” upstream projects include three technically challenging deepwater developments in the Gulf of Mexico (GOM), Nigeria, and Angola; the expansion of the Tengiz field in Kazakhstan; and the Greater Gorgon project in Australia that includes two 5-million-ton liquefied natural gas (LNG) trains and a carbon sequestration project.
But the real test for the industry may not be in locating and developing hydrocarbons, but in finding and developing highly skilled technical people “to carry out all of this work,” he said. The average age of Chevron’s U.S. work force is 47, he said. “Just as more and more of our hydrocarbon resources are being sourced outside of the U.S. and Europe, in the future more and more of our people requirements will be sourced in other parts of the world where there are large numbers of talented, energetic, and interested young work forces—in Southeast Asia, the Former Soviet Union, Latin America, the Middle East, and in Africa,” he said.
At the awards banquet, 2005 Distinguished Achievement Awards were presented to J. Kim Vandiver, to Kerr-McGee Oil and Gas Corp., and to Technip. The award recognizes individuals, companies, and projects that have made outstanding contributions to the offshore industry. Vandiver, a professor of mechanical and ocean engineering at the Massachusetts Inst. of Technology, was honored for numerous technical breakthroughs in the dynamics of vortex-induced vibrations that have enhanced the design of structures to withstand high ocean currents. Kerr-McGee and Technip were cited for their successful global relationship that has pioneered and delivered three generations of spar floating production systems in the past decade.
A Modern Approach to E&P Asset Valuation, Development, and Decision Making
Authors: Evans Scot 
Published: February 2015

The development of an oil and gas asset can be one of the most capital-intensive endeavors in the modern business world. The largest energy industry projects may require more than U.S. $15 billion in capital spending. While oil and gas assets normally have long economic lives, they have been characterized historically by low rates of return in comparison with endeavors in other industries. According to a recent report by Goldman Sachs, major oil company properties have an average life span of 21 years, but pay only 10% cash return on capital invested.
This level of performance can be attributed to two major challenges faced by nearly all recent E&P projects. First, most include substantial elements of risk and uncertainty, in terms both of commodity prices and estimates of subsurface hydrocarbon reserves and performance. Highly publicized write-downs of booked reserves illustrate the difficulties E&P companies face in this area.
The second major challenge is that conventional tools and techniques are unable to model all components of the production system simultaneously—from the subsurface upward through the wells, pipelines, and other surface facilities—across the entire productive life of an asset. Hence, engineers can create and evaluate no more than a handful of potential development scenarios, thus often resulting in suboptimal decisions. Traditionally, E&P companies resort to modeling each component of an asset—the subsurface, surface facilities, and economic outcomes—individually. At the end of this long, tedious process, they combine all the results, hoping they will represent the behavior of a fully integrated asset, which is rather questionable. Alternatively, they may simplify an integrated asset model to a point at which it can be evaluated as a single entity, which makes an accurate representation of predicted vs. actual returns somewhat risky. Both of these approaches evolved 30 to 40 years ago within major oil companies. They were strongly influenced by the hierarchical corporate structures of those days, as well as the limited computational and storage capabilities available at the time.
Because most oil and gas companies have been evolving rapidly toward asset-centered organizations, and because dramatic advancements have been made in cost-effective computational power and storage, the methodologies and tools for E&P asset valuation and decision making must be revolutionized to keep pace. Otherwise, the energy industry could squander its most precious resources at a time when global demand is going nowhere but up.
A Novel Technique To Acidize Horizontal Extended-Reach Wells
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90385, "A Novel Technique To Acidize Horizontal Wells With Extended Reach," by H.A. Nasr-El-Din, SPE, and N.S. Al-Habib, SPE, Saudi Aramco, and M. Jemmali, SPE, A. Lahmadi, SPE, and M. Samuel, SPE, Schlumberger, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September.
Extended-reach horizontal wells are drilled to maximize reservoir drainage and minimize water production from coning. A problem with these wells is poor acid distribution during matrix acidizing. The full-length paper discusses a new technique that uses mechanical diversion in the wellbore and chemical diversion in the carbonate formation. A hydraulic tractor was used to pull coiled tubing (CT) to the total depth of the well, and a viscoelastic surfactant-based acid system was used to remove formation damage created by drilling fluids.

Introduction
It is common practice to drill horizontal and multilateral wells to maximize oil recovery in carbonate and sandstone reservoirs. Extended-reach wells are defined as those with a measured-depth (MD) to true-vertical-depth (TVD) ratio greater than 2. Most oil and gas reservoirs are heterogeneous, with significant variations in reservoir permeability. Significant variations in rock permeability in wells with long target zones will cause poor fluid distribution during any chemical treatment. In matrix acidizing treatments, poor fluid placement will adversely affect the outcome of the treatment.
Mechanical and chemical means that can enhance fluid placement are available. Mechanical means, including CT, are used to distribute the fluid across the target zone. Chemical means enhance fluid distribution inside the formation. Several chemical diverters have been used in matrix acid treatments including foam and gelled and in-situ gelled acids. Several authors have raised concerns regarding use of polymer-based fluids in tight formations, especially in sour environments. To overcome some of the problems encountered with polymer-based fluids, viscoelastic surfactant-based acid systems have been used successfully in matrix stimulation. Positive field results were reported when viscoelastic surfactant-based acids were used to stimulate oil producers, water injectors, and water-disposal wells.