bluuebunny/crossref_metadata_2025_split huggingface dataset:
ESPs Successfully Meet Challenges of CO2 Use in Tertiary Oil Recovery
Authors: Burleigh Lawrence H. 
Published: February 2015

Technology Update
Numerous operators are using CO2 injection as a means of significantly extending the oil life of a reservoir. Most oil fields initially produce without artificial lift (AL). Then as the reservoir pressure depletes some form of AL is employed. In many cases, secondary-recovery techniques, such as drilling horizontal producers or initiating water injection, are employed. Tertiary-recovery methods, which include thermal recovery and gas injection, can further expand recoverable reserves and extend field life. Each of these new tactics has presented learning curves for the operator and electrical submersible pump (ESP) provider.
The CO2 learning curves are shrinking as the knowledge base grows. Success stories are growing as well. A major producer in Saskatchewan, Canada, has applied and refined miscible CO2 injection within a program of water-alternating-gas (WAG) injection that has added 155 million bbl of oil reserves and 25 years of life to the field. This operator has also implemented a program of CO2 sequestration. At the Rangely field in northwestern Colorado, CO2 injection has been incorporated into the WAG process. The injection program has added 114 million bbl of oil to recoverable reserves.
Because of the high produced-fluid volumes resulting from enhanced-recovery methods involving water and gas injection, AL by means of electrical submersible pumps (ESPs) is often applied.
ESP-System Challenges Posed By CO2 Injection
Several potential problems affecting pump run life and performance can occur when an ESP is installed in a producing well where CO2 is present (Fig. 1).
Carbonic acid attacks
Asphaltene buildup
Aromatic attacks on elastomers
Gas impedance of pump performance
Carbonate scaling
Carbonic acid. The injected CO2 when mixed with water can form carbonic acid. This acid will attack the iron present in carbon-steel materials in the pump, tubing, and casing. If the fluid speed is low enough, the newly formed iron carbonate (siderite) will remain, creating a protective layer. The mechanical integrity of the component will not be degraded. If the fluid speed is great enough, the iron carbonate layer will be removed. This uncovers a new layer containing iron for the carbonic acid to attack. This mechanism will degrade the mechanical integrity of a carbon-steel component. CO2 corrosion exhibits itself uniquely from H2S, dissolved oxygen, chloride, or galvanic corrosion. Aggressive CO2 corrosion will create deep pits. These pits generally have sharp edges and rounded bottoms. As these pits deepen they will expose internal components to the well fluid. The corrosion pits commonly occur on the outside diameter of the housing material, but occasionally occur on the inside diameter of the pump housings (Fig. 2).
Techbits: Australian Workshop Reviews State of High-Rate Gas Wells
Authors: JPT staff _ 
Published: February 2015

Techbits
Perth, Australia played host earlier this year to an SPE Applied Technology Workshop (ATW) aimed at examining the state of the art in developing and producing high-rate gas wells. Titled “High-Rate Gas Wells,” the ATW brought together 71 participants from 33 different organizations and 14 countries to uncover what the industry has learned, both in terms of best practices and pitfalls, while operating the growing number of these wells around the world.
For the purpose of this workshop, a high-rate gas well was defined as being capable of producing more than 200 MMscf/D of gas. The workshop organizers, led by Cochairs Daniel Teng of Woodside Energy and Raymond Tibbles of Schlumberger, pointed out that many wells around the world, including in Australia, Trinidad, Brazil, Qatar, and the North Sea increasingly fit that criterion.
Case studies and practical applications were presented on reservoir drainage and management; carbonate, sandface, and upper completions; subsea and surface facilities; well integrity and reliability; and intervention strategies. There was also a poster session that gave delegates the opportunity to have in-depth discussions in a relaxed environment.
Highlights of the sessions are presented below.
Reservoir Drainage
The first technical session, chaired by Azhar Al Kindi of Shell Upstream International and Carl Stockmeyer of Baker Hughes, focused on building an understanding of reservoir drainage for high-rate gas wells that links to well design and the infrastructure required for field development. An important challenge highlighted in this session is successfully balancing the drainage scheme and well architecture with the capacity allowance for individual wells. Presenters and audience members also discussed the complexities of some of these reservoirs and the importance of constantly re-evaluating available information, as well as how multiple sensors could be used in long intervals to evaluate production across a lateral. Inflow-control device technology was also discussed, with particular emphasis on how applicable the current technology is to high-rate gas wells.
Reservoir Management
Al Kindi and Kamel Bennaceur of Schlumberger cochaired this session on the critical aspects of managing reservoirs that are being drained by high-rate gas wells. Most of the focus was paid to the necessary tools required for effective reservoir management, and the need for good surveillance data was stressed to facilitate robust management, performance simulation, and forecasting. The session opened with a discussion on dynamic simulation to ensure deliverability from the entire completion/surface system. A discussion on the limitations of production logging followed, and the session closed with a review of how distributed temperature sensors can be used as a reservoir-monitoring tool.
The Spinning Globe Inside a Crystal Ball: A Dual Perspective on the Changing Leadership Demands of Oil and Gas
Authors: Lloyd Frank 
Published: February 2015

Talent & Technology
The stakes in the leadership-development game are increasing. Current trends in the oil and gas industry demand an expanded set of leadership competencies to handle the complexities of the immediate. And, at the same time, industry leaders are called on to prepare for broader macroeconomic trends that will reshape the landscape over the next century. Think of it as a split perspective on the future—one eye on the spinning globe of today and the other on a crystal ball within which it is spinning. This dual perspective suggests that the future demands of industry leadership will bear little resemblance to those of today. The newest trends in management development help firms prepare for the demands of the long term as well as the immediate.
Oil and gas executives well know the evolving challenges of the industry and their leadership implications. Significant among these are:
Intensifying globalization—strategy must be crafted and implemented in a global context that accounts for new players and new markets in developing nations, national oil companies and multinational corporations, multiple world hubs, and a complex web of customer and supplier relationships.
Business complexity—sourcing capital, valuing complex projects, maximizing the value of alliances, creating operational efficiencies by applying information technology and adapting lean manufacturing, clean energy.
Multicultural and multigenerational workforce—aligning business goals with a broad spectrum of cultural norms that may clash with organizational norms while maintaining one’s own cultural authenticity, transferring knowledge from one generation to the next.
Expanded risk—assessing financial and operational risk, using new energy risk-management tools, dealing with regulatory and social risks, everything from safety to accounting standards imposed by a wide variety of governments at local, national, international levels, and maintaining energy security.
These complex industry challenges require success-oriented firms to develop leaders who can lead innovation and change, make critical decisions quickly that align with overall strategy, achieve operational efficiency and economy, and inspire and motivate others.
As one chief executive officer put it, his biggest challenge is developing leaders who can lead people, make money, and grow strategically. Today’s leader layers strategic thinking on top of business acumen on top of organizational and interpersonal savvy. This is the human capital equivalent of using multiple—even redundant—tools to maintain safe and secure levels of financial liquidity.
Comments: Companies that Innovate
Authors: Donnelly John 
Published: February 2015

Editor's column
The oil and gas industry is a leader in high-tech innovation, whether adapting older technologies and techniques or creating and applying new ones. JPT has been highlighting many of these technical advances over the past several months, from hydraulic fracturing improvements, to advances in subsea processing, automated drilling, and other technologies.
SPE along with JPT is also putting a special focus this year on companies and individuals who believe they have come up with promising advances in technology and that deserve attention from the industry at large. JPT is currently soliciting these ideas for future publication (see www.jptonline.org to find out more about submitting new technology ideas for publication in JPT).
Now a new book, The Innovator’s DNA, shines a light on innovative companies and the people who run them and why some companies do better than others in this regards. The book is based on an eight-year study by Clayton Christensen, a Harvard Business School professor; Jeff Dyer, a professor at Brigham Young University; and Hal Gregersen, a professor of leadership at INSEAD, an international graduate business school and research institution. They conclude that there are particular skills that define those who run innovative companies, skills that can be learned or adapted. They summarized their findings in a recent issue of Forbes and helped create a list of the most innovative companies operating in the world today. Here are the skills they say define “disruptive innovators”:
Questioning allows innovators to challenge the status quo and consider new possibilities.
Observing helps innovators detect small details in the activities of their customers, suppliers, and other companies that suggest new ways of doing things
Networking allows innovators to gain radically different perspectives from individuals with diverse backgrounds
Experimenting prompts innovators to try out new experiences, take things apart, and test new ideas
Associated thinking—drawing connections among questions, problems, or ideas from unrelated fields—is triggered by questioning, observing, networking, and experimenting and is the catalyst for creative ideas.
Several oil and gas firms made the list of the top 100 innovative companies, including FMC Technologies, Schlumberger, China Oilfield Services, Cameron, Tenaris, and Halliburton. Others on the list are linked to the energy industry through the products they offer, including Praxair and Infosys. FMC scored highest among oil and gas firms, ranking 18th, while Schlumberger was second at 27. The authors tried to define those companies that have an “innovation premium,” a metric defined as the proportion of a company’s market value that cannot be accounted for from cash flows from its current products. The list was limited to companies with large market caps and those that are publicly listed, but the authors maintain that these organizations have innovation embedded in their company philosophies and in their people, and that that sets them apart from competitors.
Drilling Automation: A Catalyst for Change
Authors: Rassenfoss Stephen 
Published: February 2015

Seabed Rig is a small company named after its audacious vision: creating a device able to drill a well on the bottom of the ocean. The company, 20% owned by Statoil, is using what it learned from a prototype to build a rig capable of drilling on land, or an offshore platform, with no workers on site.
“You command it, you don’t control it,” said Kenneth Søndervik, vice president of sales and marketing at Seabed. Rather than a person controlling machines putting together pipes, an automated system will respond to a command, such as “pick up 3,000 meters of pipe,” from the computer program controlling drilling. The ability of these machines to work together on their own is essential for Seabed because Statoil needs a rig capable of drilling in the Arctic, and other environments that would put workers in harm’s way.
This semantic distinction points to a fundamental change in the drilling business, and the people who work on the rigs. Seabed is building a rig like no other, using components supplied by oil and automation companies. “The big thing is we are not an inventing company. We are an engineering company taking all that’s out there,” said Søndervik.
Seabed is working on creating a confined rig floor—the footprint is 9 m by 9 m—with robots programmed using software developed for NASA by Energid Technologies. The US company’s software is also being used to control the next generation of lunar rovers. For the drilling, Seabed will be choosing from a growing number of major oil and service companies developing software that does the job.
Statoil, ExxonMobil, Petrobras, Schlumberger, National Oilwell Varco (NOV), and Baker Hughes, represent a sample of the technology leaders seeking ways to program all or parts of the drilling process.
Shell appears to have taken it the furthest, with an automated program that has drilled multilateral wells. “It is not science fiction, it is what we have done,” said Peter Sharpe, executive vice president of wells at Shell. Its SCADAdrill System has been demonstrated in Canada and the Netherlands, with testing in progress in two US shale plays, the Marcellus and Haynesville.
Automated Drilling Raises Control Issues
Authors: Rassenfoss Stephen 
Published: February 2015

Anadarko averaged 12.6 days to drill 59 Eagle Ford Shale wells during the second quarter of this year. Its best took 8.5 days from the day drilling began to when the rig was released.
Mark Sundland, drilling engineering manager of Anadarko’s Southern Region, credits the rapid pace of the 10 rigs—with times less than half of some competitors in the South Texas play—to consistent use of modern rigs and long-standing ties with top directional drillers and consulting company men. Some of those hands learned their trade working on the first big horizontal drilling play in the Austin Chalk play back in the 1990s.
The rigs are equipped with automatic drillers and equipment that replicates the skill of skilled directional drillers. Sundland said he sometimes questions the high cost of those options, which are built to do what Anadarko’s experienced drillers can do. But with so many veteran hands nearing retirement, and drillers hard to find in some places, he admitted there is a clear and growing need.
The people developing automated drilling equipment are thinking along the same lines.
“What we are trying to automate are the best practices across directional drillers so you can take one with two years’ experience and they can drill as well as someone who has done it for 20 years,” said Clinton Chapman, drilling automation program architect at Schlumberger.
The oilwell service company has developed a pair of programs. One speeds the drilling penetration rate, and the second controls the trajectory of drilling. The benefits come in the form of faster drilling, which lowers costs, and more predictable results, which is critical in satisfying the terms in drilling contracts. Both are aimed at performance that exceeds what is now available elsewhere. Shell has gone a step further with a device capable of managing the entire drilling process.
Many companies in the industry are seeking to turn what was once an art based on the experience and feel of a person, and turn it into a science using computer programs based on mathematical formulas. “We can do this much more predictably with a series of algorithms,” said Peter Sharpe, executive vice president of wells at Shell. He pointed out that a machine’s ability to instantly react to downhole data allows it to do a better job than a person at keeping a drill bit steadily engaged on the rock face.
Shell To Build World's First Floating LNG Facility
Authors: Parshall Joel 
Published: February 2015

Shell will build and deploy the world’s first floating liquefied natural gas (FLNG) facility, a milestone in industry efforts to commercialize gas supplies that have been stranded for economic reasons stemming from logistical, technical, business, and marketing challenges. The Prelude FLNG project, which Shell will operate with a 100% interest, received its final investment decision in late May.
The facility will produce an estimated 3 Tcf of gas and equivalent resources from the Prelude field, discovered by Shell in 2007 approximately 125 miles offshore northwest Australia. First production is anticipated in 2017. On the facility, field gas will be produced, processed, liquefied, stored, and offloaded to oceangoing LNG carriers that will transport cargoes to multiple markets. The facility will also handle field liquefied petroleum gas (LPG) and condensate for ship-borne transport to market. “Our decision to go ahead with this project is a true breakthrough for the LNG industry, giving it a significant boost to help meet the world’s growing demand for the cleanest-burning fossil fuel,” said Malcolm Brinded, executive director of upstream international at Shell. The FLNG technology, he said, “is an exciting innovation, complementary to onshore LNG, which can help accelerate the development of gas resources.”
A consortium composed of Technip and Samsung Heavy Industries (SHI) has been contracted by Shell to provide engineering and procurement and perform construction and installation of the Prelude FLNG facility.
The facility will be the largest floating structure ever built, measuring 1,602 ft (488 m) long by 243 ft (74 m) wide. Its length is slightly less than the height of the Willis Tower in Chicago and greater than the height of the Petronas Towers in Kuala Lumpur. With a weight of more than 600,000 tons when fully ballasted, the facility has a displacement approximately six times that of the world’s largest aircraft carriers.
Construction will take place at SHI’s Geoje Shipyard in South Korea, one of the few locations in the world with a dry dock big enough to accommodate a facility of this size. Once constructed, it will be towed to location—a six-week journey—where it will be fully moored and commissioning of the facility will begin. Once operational, it will produce 4 million tons/yr of LNG, 1.4 million tons/yr of condensate, and 0.4 mil-lion tons/yr of LPG. On a composite basis, the production is equivalent to 110,000 bbl of oil.
Magnesium Peroxide Breaker for Filter-Cake Removal
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142832, ’Magnesium Peroxide Breaker for Filter-Cake Removal,’ by Shrikant K. Mahapatra, SPE, ADMA-OPCO and Bela Kosztin, SPE, PDO, prepared for the 2011 SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 23-26 May. The paper has not been peer reviewed.
Commonly used drill-in fluids (DIFs) typically contain starch, xanthan, and sized calcium carbonate. Although DIF is inherently less damaging than conventional drilling mud, relatively impermeable filter cakes are deposited on the borehole wall. A common practice to minimize such damage is applying acid (i.e., external breaker) or a strong oxidative breaker (i.e., internal breaker) system to dissolve filter-cake solids and biopolymers. Magnesium peroxide is an internal breaker and is classified as an oxidizer, which decomposes slowly to release oxygen. The magnesium peroxide, when exposed to an acidic solution, releases hydrogen peroxide that degrades the polysaccharide-type polymers and removes the external filter cake.
Introduction
To realize the full potential of openhole horizontal completions, formation damage caused by residual filter cake must be removed. A common approach to mitigate such damage is application of strong organic acids, ester-generated organic acids, chelates, enzymes, and combinations of these or different oxidative breaker systems to dissolve/destroy filter-cake solids and biopolymers. Two basic methods are applied to deteriorate filter cake that contains polymers.
External breaker placed in contact with the surface of the filter cake.
Internal breaker deposited as an integral component of the filter cake.
Peroxide Chemistry
Magnesium peroxide is a very stable strong oxidizer and can be used as an internal breaker. At medium or low temperatures, it remains inactive when added to polymer and sized-solids DIF, and thus becomes an integral part of the filter cake as it is deposited. According to the particle-size distribution and active-material content, there are many types of magnesium peroxide available. It is best if the selected type matches with the pore-size distribution of the drilled reservoir section and with the drilling rig’s solids-control system. The particle-size distribution is affected by the volume and particle-size composition of the other bridging materials also.
Because of the extremely low solubility of magnesium peroxide, it remains stable for extended periods of time while in an alkaline environment and within the filter cake. Upon contact with hydrochloric acid (HCl), the solid peroxide decomposes to form hydrogen peroxide. Hydrogen peroxide generates in-situ oxygen, which attacks starch and xanthan polymers. Autoxidation occurs as the polymer is exposed to the oxygen.