bluuebunny/crossref_metadata_2025 huggingface dataset:
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.
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.
High-Density Acid Used in a Deep HP/HT Well
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142033, ’Study and Application of High-Density Acid in a Deep HP/HT Well,’ by Xingsheng Cheng, Yongping Li, Yunhong Ding, SPE, and Mingguang Che, Langfang Branch, Research Institute of Petroleum E&D, PetroChina, and Fuxiang Zhang, SPE, and Jianxin Peng, Tarim Oilfield Company, PetroChina, prepared for the 2011 SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7-10 June. The paper has not been peer reviewed.

The KKY reservoir in the Tarim oil field in western China is a deep high-pressure/high-temperature (HP/HT) dolomite reservoir. The formation was damaged with heavy mud during drilling, and matrix acidizing could not clean the skin effectively. To decrease the surface treating pressure to a safe level, a new high-density-acid system was developed. Extensive laboratory testing was conducted to evaluate its corrosion-inhibition and friction-reduction capacities, rheological properties, and stability. The new weighted acid ensured successful acid fracturing of the KKY reservoir. 

Introduction

The KKY is a deep dolomite condensate/gas reservoir at a depth greater than 6000 m with reservoir temperature and pressure of approximately 150°C and 110 MPa, respectively. The formation suffered extreme damage because of the use of heavy mud and the existence of natural fractures. At first, matrix acidizing was used to eliminate the skin, but treatments were limited by the high pressure required. Production increased somewhat, but dropped quickly and could not be sustained. Analysis showed that matrix acidizing could not remove the damage completely; therefore, acid fracturing was investigated. It was determined that an acid-fracturing treatment could not be implemented with conventional acid because the surface pressure exceeds the working-pressure capability of conventional 103.4-MPa fracturing equipment. A high-density-acid proposal was developed to reduce the wellhead pressure.

High-Density Acid

Weighting Agent. Generally, high-density acids are blended by adding acid into high-density concentrated halide brines, such as sodium chloride, calcium chloride, sodium bromide, calcium bromide, or a combination of zinc bromide and calcium bromide, among others. Because the reservoir is dolomite, the main processing acid is hydrochloric acid (HCl), and all the salts and brines mentioned above can be used. The selection of salts or brines is based primarily on the required properties of weighted acids and on cost effectiveness. Considering the need of density in the reservoir and the density of different brines, calcium chloride and some bromide were selected as weighting agent according to the properties of individual wells. The density of weighted acid can be adjusted between 1.25 and 1.55 g/cm3 by regulating the type and quantity of brine.
Rigorous Drilling-Nonproductive-Time Determination and Eliminating Invisible Lost Time
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 138804, ’Rigorous Drilling- Nonproductive-Time Determination and Elimination of Invisible Lost Time: Theory and Case Histories,’ by Eric Maidla, SPE, and William Maidla, SPE, TDE Petroleum Data Solutions, prepared for the 2010 SPE Latin American & Caribbean Petroleum Engineering Conference, Lima, Peru, 1-3 December. The paper has not been peer reviewed.

Measuring techniques that involve data-quality control (QC) and automatic detection of routine drilling operations are available in modern drilling programs. Implementation was carried out in an onshore area in which a series of similar wells was drilled. Measurement accuracy, training, and development of new work processes that were implemented successfully and these led to major key-performance-indicator (KPI) time savings of 31 to 43%.     

Introduction

Past performance of drilling and completing wells was analyzed to capture learnings, which then were applied on the next well or well campaign. The process relied on running rigorous QC on the drilling morning-report data and correlating those events with other well data from electric logs, geology, and recorded drilling data.

Leadership is critical, whether through internal management or through specialized consultants who understand how to motivate groups to excel. Even when implemented properly, many approaches tend to be cyclic, and keeping the processes in effect has proved to be difficult with the processes breaking down when certain elements of the group leave. In most cases, improvements of the drilling performance of routine drilling operations were very limited until a change occurred on the rig, regardless of how many meetings and workshops were carried out away from the rig, and even if some rig personnel were involved. Only when the driller was engaged did the final results improve.

The process presented by the authors focuses on the driller. The proposal is to provide this individual or group with all the information and support necessary to allow the drilling-rig group to achieve the required safety practices that come from understanding how to perform the job properly and in a consistent manner.

Automatic Operations Detection

The work used automatic operations detection of the routine drilling operations and was the basis of collecting real-time (or near-real-time) data to determine the rig status. The key was to have an independent data-QC process performed by a company other than the data provider, thus ensuring no conflict of goals or interests. Following the QC process, the data were classified and processed and a rig state was assigned to each time interval (e.g., drilling—rotary, drilling—sliding, and reaming and washing upward). These rig states were the building blocks for all classifications and reports per-formed throughout this study.
Digital Standards Collaboration: Key To Unlocking Intelligent Energy's Potential
Authors: Beckwith Robin
Published: February 2015

Digital standards

Late June in Houston, Texas, senior executives from the Standards Leadership Council’s (SLC) nine member organizations hosted a forum, whose goal was to encourage collaboration on open digital standards for the benefit of the upstream oil and gas industry. More than 125 industry representatives attended the all-day event. Formed in February 2012, the SLC’s mission is to avoid duplication in oil and gas industry electronic standards development projects and to address mutual challenges, such as determining business value metrics for standards adoption, enhancing the benefits members receive from the various oil and gas digital standards, and maintaining financial sustainability of standards organizations.

Derek Mathieson, president of western hemisphere operations at Baker Hughes, delivered the keynote address. He became involved with the digital oil field in the mid-’90s. The problems then, according to Mathieson, were the result of having to deal with 50 years’ worth of infrastructure. “You would have thought almost all of that would have gone away by now,” he said. “But the same challenges exist today.”

Looking ahead, Mathieson observed that fascinating things are going on in relation to learning and connectivity—what he referred to as “the ‘wikification’ of our business” to facilitate learning. Heavily influenced by social media and reliance on collaboration, the new generation of professionals in the petroleum industry appears to learn in ways that are different from “traditional” ways of learning. He said he believes, therefore, the challenge now is how to “take away the pain of major project implementation.” This leads to the need for increased industry collaboration for electronic standards, said Mathieson, who encouraged forum attendees to participate in the development process.

Duncan Junor, vice president for Halliburton and the Energistics’ board chair, formally closed the forum. “It was a sold-out event,” he said, “which speaks volumes to the dedication and passion of this industry to work together to adopt and implement standards.”

“Just to have all nine standards organizations in the same room,” he continued, “is a huge accomplishment.”
Alternative Oil Spill Response Technology: Results from the Deepwater Horizon Response
Authors: Cortez Michael J. , Rowe Hunter G.
Published: February 2015

Management

Oil spill response technology progressed significantly as a result of innovations and experience gained during the Deepwater Horizon response in the Gulf of Mexico in 2010, particularly in areas related to surveillance, controlled in-situ burning, booming, skimming, mechanical oil/water separation, and sand cleaning. During the response, the Alternative Response Technology (ART) team, under the direction of the Unified Area Command, screened approximately 43,000 spill response technology ideas submitted by the public. The ART team’s work was done alongside, and consistent with, the US federally directed Interagency Alternative Technology Assessment Program.

The ART team field tested or evaluated in detail about 100 of the 43,000 ideas, resulting in at least 45 ideas being recommended for use in response operations. The successful ideas are listed in Table 1.

Of significance was the number of ideas that came from other industries and were adapted to spill response needs. For instance, the team field-tested at least 10 sand cleaners for beach cleanup, and the most notable was the Sand Shark (Fig. 1), a technology that was adapted from the road maintenance industry (material loader). The Sand Shark could clean a mile of beach per day, using its sifting process, down to a depth of approximately 12 in.

Another successful sand-cleaning technology was the Gravely Rapid E Sand Cleaner. The Chicago-area Gravely Co., which makes industrial lawn mowers, had adapted its technology into a one-person sand-cleaning machine that could get in and out of hard-to-access beach areas for cleanup. Its use was proposed by a distributor in Illinois, who saw the larger sand-cleaning machines on a newscast and reasoned that the smaller machine would be useful to responders.

The Boom Blaster (Fig. 2) was a technology adapted from the car wash industry and was able to clean 600 ft of boom per hour, which far exceeded what could be cleaned manually. During the response, more than 13 million ft of boom was deployed, thus saving considerable time and manpower in cleaning boom for storage.

These and other technologies adapted from other industries—including the Parachute Surf Skimmer (a pool and pond cleaner proposed for tar ball capture), Yates Boom Cleaner (another automated process with dishwasherlike water jetting), and the M-I Swaco sand cleaning plant (adapted from tar sands production operations)—have been added to the industry’s toolbox. One key lesson learned to aid in future spill clean-ups is to open the search for technology outside of industry and to be willing to think creatively.
Radio-Frequency-Identification Technique Opens and Closes Sliding Sleeves Remotely
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 153834, ’Interventionless Completions for Unconventional Shale Plays,’ by Jane Mason, SPE, John Tough, Paul Day, SPE, and Shirley Hatton, Petrowell, prepared for the 2012 SPE Middle East Unconventional Gas Conference and Exhibition, Abu Dhabi, 23-25 January. The paper has not been peer reviewed.

To simplify the process of multiple fracturing operations, a new approach has been designed that uses radio-frequency-identification (RFID) techniques to operate sliding sleeves remotely. The number of sleeves that can be run in a well using this technology is essentially unlimited, each having the same identification and a unique electronic address that allows it to be operated remotely at will. This approach makes considerably more zones available for treatment without coiled-tubing or wireline physical intervention and, thereby, speeds the operations.

RFID-Technology Overview

RFID technology will be familiar as the basis of toll-road tags for identification of one’s car—the tag in one’s vehicle contains a microchip that positively identifies it and triggers a toll charge. This same microchip system (Fig. 1) can be used to trigger a downhole tool that has an embedded antenna that picks up the coded signal in the chip as it is pumped down the hole. RFID’s method of data transfer and adaptability permit widespread application in a downhole environment. It is a close-proximity means of transferring data; no direct line of sight is required, and it works by using at least two devices—a reader and tag. The devices are paired and able to recognize each other through the transmission of radio waves; a tag is coded with relevant information that can be read as it passes an RFID reader. The term “close proximity” is relative. Tags are read from 100 m in the airline industry, where readers are able to use vast amounts of power. In contrast, the distance would be reduced to 6–12 in. in the oil industry, demanding far less power downhole. The tag, which contains an electronic circuit (transponder), is programmed with specific information, and, when it approaches the reader, the radio-frequency field generated by the reader powers up the tag, causing it to transmit its data continuously by pulsing the radio frequency. The data are then captured by the reader and processed.

Because the tag is so small, it allows great freedom of movement, and there is no need for direct contact for both devices, which results in a high level of convenience and flexibility. Some of the other advantages of RFID are

Tags can be hidden or embedded in nonmetallic materials.

No line of sight is required.

Its contactless nature limits wear and tear.

Tags can be read even if they are covered with dirt or submerged.

Unalterable permanent serial code prevents tampering.