bluuebunny/crossref_metadata_2025 huggingface dataset:
Overview: Bit Technology (December 2006)
Authors: Mensa-Wilmot Graham
Published: February 2015

Drilling activity has increased in the last couple of years, with wells being drilled deeper and into harder and more-abrasive formations. These drilling environments present serious challenges for drill bits in terms of rate of penetration (ROP) and bit durability. The high drilling-activity level and increased demand led to increased rig rates. To reduce drilling costs, drilling engineers have had to re-evaluate bottomhole-assembly designs, drilling processes, drilling fluids, and applications.

Drill bits, although insignificant in terms of price, have huge effects on operational costs. To improve drilling performance, considering the challenges, drill bits must drill faster and last longer. These targets are what drilling engineers have come to expect and what bit companies are delivering to the industry.

Several types of drill bits are available for different applications and drilling challenges—polycrystalline-diamond-compact (PDC), impregnated, and roller-cone bits. To reduce drilling costs substantially in the current environment, technology development must expand and permeate into all the different bit types.

For PDC bits, new modeling tools and bit designs are being developed on a continuous basis. Bit-behavior analysis, especially the characterization of the different vibration modes, has become a standard in the bit-design process. New PDC cutters with very high abrasion-resistance properties continue to be developed. These cutters stay sharper for longer periods of time, thus improving ROP and durability.

Substantial ROP and durability improvements are also being seen with impregnated bits. These improvements resulted from detailed evaluations that focused on the effects of drive tools (rotation speed and power regime), down-hole-pressure environment, and depth of cut on impregnated-bit development and performance.

For roller-cone bits, new technologies are improving seal reliability and cutting-structure durability. In addition, new developments in metal-seal-bearing technology have drastically increased the on-bottom drilling time of roller-cone bits, especially in directional wells.

Drill-bit companies have accepted the challenges, and they do not plan on slowing down.

Bit Technology additional reading available at the SPE eLibrary: www.spe.org

SPE 102182 "Coupling of Downhole-Dynamics Recorder Enhances System-Matched Approach to Drill-Bit Design and Application With a Specific Rotary-Steerable System" by S. Barton, SPE, ReedHycalog, et al.

SPE 102134 "Vibration Analysis, Model Prediction, and Avoidance: A Case History" by G. Robello Samuel, Halliburton Drilling, Evaluation, and Digital Solutions, et al.

SPE 99193 "Real-Time Downhole Torsional Vibration Monitor for Improving Tool Performance and Bit Design" by D.C.-K. Chen, Halliburton Sperry Drilling Services, et al.
Improved ROP in Ultrahard Rock
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 99045, "ROP Enhancement in Ultrahard Rock," by M. Roehrlich and K.-U. Belohlavek, ExxonMobil Development Co., prepared for the 2006 IADC/SPE Drilling Conference, Miami, Florida, 21–23 February.

Drilling the hard and very abrasive Bunter formation in northwest Germany has been a challenge for 40 years. Low rates of penetration (ROPs) and high tool wear are common. The full-length paper details the analysis of historical data and the combination of bits, motors, and other bottomhole-assembly (BHA) components to improve ROP. The combination of new impregnated bits, new downhole motors, and improved hydraulics was the basis for the improvement.

Introduction

The Bunter, a hard and very abrasive formation, typically at a depth of 8,000 to 12,500 ft, consists of layers of quartzitic sandstone and silificated claystone with a compressive strength of 30 to 50 ksi. In the past, typical ROPs in 12 1/4-in. sections were 3 to 6 ft/hr. In the 1970s and 1980s, 15 to 20 insert bits were required to drill the section and reaming was necessary as a result of undergauge bits.

In the 1990s, a research project was initiated and funded by the German drilling industry to improve ROP in ultrahard and abrasive formations. In the past, the Bunter was characterized by the lowest ROP, shortest bit life, and highest cost per foot. Increasing the depth of cut (DOC) of impregnated bits in the Middle and Lower Bunter was identified as having potential for improvement. DOC means the length that is drilled with one revolution of the bit. An increase in DOC can be achieved by a decrease in overbalance or an increase in the amount of power available for drilling the rock. To analyze the key parameters, drilloff tests or drilling tests at fixed drilling parameters were conducted and plotted into Bingham diagrams.

Within the German drilling industry, two approaches to increase ROP have been chosen—use of downhole turbines and use of high-speed downhole motors in combination with improved hydraulics made possible by larger-inside-diameter drillpipe.

The full-length paper details results from downhole-motor runs with impregnated bits. All results are from 12 1/4-in. bits because this is the most common bit size used in Germany for the Bunter formation.

Rotary Speed. Until 1997, the standard for high-speed downhole motors was 400 rev/min at 790 gal/min (360 hp). In 1997, a 9 1/2-in. downhole motor was tested in Germany at 780 rev/min at 849 gal/min (515 hp). In 2004, a new 9 1/2-in. downhole motor was developed that delivers 975 rev/min at 1,055 gal/min (1,025 hp).

Weight on Bit (WOB). In 2004, the maximum WOB for high-speed downhole motors was approximately 48,100 lbm. With the 975-rev/min downhole motor, maximum WOB increased to 60,700 lbm because of improvements in bearings.
Guest Editorial: Oil and Gas Industry Leaders Target a Serious Problem That Affects Us All - Driving-Related Events
Authors: Tate Derek
Published: February 2015

The International Association of Oil and Gas Producers (OGP) has taken a strong proactive step to reduce the greatest common cause of death and serious injury plaguing our industry—motor-vehicle crashes (Fig. 1). OGP members formed a task force to study the issue and develop a realistic way to address it. The group selected a process that is elegant in its simplicity, yet remarkably thorough. They reasoned that since the industry was already accustomed to following recommended practice (RP) in nearly every facet of its work, why would it not be willing to develop and apply RP in driving?

The work was encouraged by sobering statistics amassed by the World Health Organization and the World Bank, which jointly estimated that 1.2 million people are killed annually in road crashes, and another 50 million are injured. Trends show that these numbers could increase by 65% over the next 20 years unless there is some intervention. While rates in developed countries are expected to decline, those of low- to middle-income countries will erase the decline, and the trend is expected to be steeply upward. Task-force members reminded themselves that the oil and gas industry field force is very active in these at-risk countries.

The task force took the position that one of the best ways to minimize driving fatalities is to minimize the occurrence of vehicle crashes. The best way to minimize the occurrence of vehicle crashes is to address their causes in a comprehensive way. Accordingly, the RP covers a spectrum of control areas. The team strived to apply experience, common sense, and best practice in determining the content of the document. Measures both proactive and reactive were included—preventative and mitigating, respectively. While the requirement for driver training and skill assessment will help prevent a crash, the requirement for the wearing of seatbelts reduces the potential for injury should a crash happen.

Task-force members sought to create a product that, if applied across the industry, should result in a step change in journey management and a substantial reduction in transport-related incidents. What differentiates an RP from a guideline is that an RP should be formally put into the business and operating practices of the company adopting it, requiring the universe of their enterprise—that is, permanent and temporary employees, partners, contractors, and vendors—to be influenced to adopt the practice as well. It is a powerful and effective incentive. An RP also becomes something by which the industry is recognized by the general public, governments, and regulatory agencies.
Techbits: First Continentwide Latin American HSE Workshop Held
Authors: JPT staff _
Published: February 2015

SPE and the Brazilian Petroleum, Gas and Biofuels Institute (IBP) held the industry's first continent wide Latin American Workshop for Health, Safety, and Environment (HSE) in Exploration and Production (E&P) 23–24 August in Rio de Janeiro. The workshop drew some 170 professionals, which exceeded expectations. Participants came from 14 countries, including France, Malaysia, Russia, and the United Kingdom.

Designed to promote the exchange of knowledge and ideas, especially HSE best practices, the workshop focused on a broad array of topics:Effective HSE managementThe impact of human behavior in safety and on the environmentBest safety practices in the real worldHealth issues in E&PManaging and monitoring environmental resourcesOil-spill response plansE&P in sensitive areasClimate change

The tension between society's increasing demand for energy and its need and desire to reduce emissions was the theme of the workshop's first plenary session. Guilherme Estrella, director of E&P for Petrobras and president of the Administration Council of IBP, was session chairperson, and speakers included Beatriz Nassur Espinosa, Petrobras; Emmanuel Garland, Total; and José Félix García, Regional Association of Oil and Natural Gas Companies in Latin America and the Caribbean (Arpel).

Estrella noted the societal pressure on oil companies to change paradigms and the evidence of some shift in direction already seen as oil companies transform into energy companies. Themes covered by the speakers included the necessity of fulfilling the requirements of the next generation without neglecting the present one, the comprehensive need for effective HSE performance throughout the production chain, the importance of proactive alignment with society on biodiversity and ecosystem sustainability, and the value of strategic planning in the HSE sphere as a means of enhancing the sustainability of the E&P segment.

A second plenary session dealt with global warming, focusing on the Intergovernmental Panel on Climate Change (IPCC) reports and the coming challenges for the oil industry. Luiz Igrejas, Petrobras, chaired the session, and the speakers were Garland; Suzana Kahn, State Government of Rio de Janeiro; and Philip Hauser, Ecosecurities. Discussion encompassed the IPCC commitment to effect major change and also dealt with the technological and commercial responses under way in the attempt to meet this need for change, including various CO2 technologies and the development of a trading market for capped carbon emissions. All agreed that work has a long way to go simply to meet existing targets.

A panel session on effective HSE management systems was chaired by Don Salmond, Battelle Memorial Institute, and featured as panel lists Juan Ramon Candia, Fundación Chile; Hubmaier Andrade, El Paso-Brazil; and Tatiana Botelho, consultant. Session proceedings focused on the importance of management systems as essential tools for identifying and managing risk. Management systems and risk mapping are now considered fundamental inputs to company decision making.
Heavy-Crude-Oil Upgrading With Transition Metals
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 107837, "Heavy-Crude-Oil Upgrading With Transition Metals," by H.R. Nares, P. Schacht-Hernandez, M.A. Ramirez-Garnica, and M.C. Cabrera-Reyes, Inst. Mexicano del Petroleo, and L. Noe-Valencia, U. La Salle, Mexico, prepared for the 2007 SPE Latin American and Caribbean Petroleum Engineering Conference, Buenos Aires, 15–18 April.

The full-length paper discusses the effects of some metallic oxides used to upgrade heavy-crude-oil properties. The objective is to increase oil mobility in the reservoir by reducing viscosity and improving oil quality by use of alumina-supported transition metals and liquid-phase transition-metals catalysts derived from acetylacetonate or alkylhexanoate compounds. Heavy crude oil from the Gulf of Mexico (GOM) was studied. Oil gravity was increased from 12.5 to 21 to 26°API, asphaltene content was reduced from 26 to 7 wt%, and distillable fraction was increased by 20 to 30 wt%.

Introduction

Some of the main problems that heavy crude oil presents are:low mobility through the reservoir because of its high viscosity, which affects the wells productivity index (PI);difficult transportation to the refineries and the high cost of that transportation; andthe low processing capacity in the refineries. For these reasons, it is necessary to enhance the heavy crude oil, both above ground and underground. Some of the main processes used are carbon rejection, hydrogen addition, and physical separation. All these processes are focused on converting oil residues into more-valuable products such as gasoline, middle distillate, and fluid-cracking catalytic feedstock.

An interesting alternative to recover the heavy and extra heavy crude oil is downhole catalytic upgrading. This alternative presents several advantages compared with its above ground counterpart such as an increase in the well PI, a reduction in the lifting and transportation costs to the refining center, the production of more-valuable products as a result of the decreases in viscosity values, resins, asphaltenes, sulfur, and metal contents.

Some of the most important processes that have been studied to enhance heavy and extra heavy crude oil are steam-drive, cyclic steam injection, steam-assisted gravity drainage, fireflood, and downhole catalytic processes. The main objective of these processes is to decrease the viscosity of the heavy crude oil to improve its flow from the reservoir to the producer well. This viscosity reduction can be achieved by increasing the reservoir temperature or by injecting hydrogen-donor compounds. Two ways to improve the quality of heavy crude oil are hydrocracking and hydrotreating such as aromatic hydrogenation and desulfurization. This removal can be achieved by injection of a catalytic solution [organic metallic compounds of molybdenum (Mo), iron (Fe), cobalt (Co), and nickel (Ni)].
Decision Environments: Lessons Learned From Implementation and Future Direction
Authors: Denney Dennis
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 112215, "Evolution of Decision Environments: Lessons Learned From Global Implementations and Future Direction of Decision Environments," by Michael Hauser, SPE, Chevron, and Helen Gilman, SAIC, prepared for the 2008 SPE Intelligent Energy Conference and Exhibition, Amsterdam, 25-27 February. The paper has not been peer reviewed.

Chevron and Science Applications International Corporation (SAIC) are implementing asset-decision environments (ADEs) across business units as part of Chevron's i-field initiative. Decision and collaboration environments address challenges associated with response to real-time data, scarcity of experienced resources, and integration of and collaboration between disciplines and locations. Practical lessons learned on how to design an ADE are presented to address problems and deliver value, and still remain flexible to developments in the future.

Introduction

This digital-oilfield initiative was launched in late 2002 with a vision of transforming the way assets are managed and operated by integrating new technologies, new work processes, and new ways of working. The integrated field is an operational transformation philosophy that drives enhanced and optimized operating processes with these common attributes.Manage by exception (focus on highest value)Improve collaboration across distance and functionRemove people from harm's wayStandardize and centralize analysis and decision makingUse real- or right-time data in decision making

An assessment process to engage assets and business units was developed that identifies an asset's key issues and makes recommendations on how to resolve those issues and add value. Early assessments, carried out in 2003 and 2004, recognized some common issues associated with different groups not able to access the same data at the same time, the need to collaborate across disciplines and locations, and how to make best use of scarce expert resources. The concept of the ADE was developed in 2004 in response to these needs.

ADEs at Chevron.

The definition of an ADE is intentionally general, allowing several types of decision environments to be included. An ADE is a real-time operating environment in which people can manage and execute business processes by use of collaborative decision making across part or all of an asset or business unit. Fig. 1 shows how an ADE, or collaborative environment, spans the office and field, and may include experts from other locations or other organizations. It may be a physical operation room, a virtual environment, or a hybrid of both. An ADE is not defined by its physical properties; rather, it is thought of in terms of the activities and processes that it enables and facilitates.
Drilling-Vibrations Modeling and Field Validation
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112650, "Drilling- Vibrations Modeling and Field Validation," by J.R. Bailey, SPE, E.A.O. Biediger, SPE, V. Gupta, SPE, D. Ertas, SPE, W.C. Elks, SPE, and F.E. Dupriest, SPE, ExxonMobil, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.

A modeling tool has been developed that enables drilling engineers to design vibration-resistant bottomhole assemblies (BHAs), given tool-placement constraints and desired directional objectives. This model can be applied to configurations with the majority of common drilling components. Modeling results have been validated in large, intermediate, and small hole sizes. Redesign has resulted in improved drilling results, including increased on-bottom drilling time, longer tool life, higher rate of penetration (ROP), reduced nonproductive time associated with tripping, and better hole quality.

Introduction

Vibration of drillstrings and BHAs has contributed to operational problems since rotary drilling was first invented. Failure of drillstring components, such as rotary-steerable (RS) BHAs or logging-while-drilling (LWD) tools, may result in nonproductive time while tripping to replace the failed equipment. Downhole components may eventually part so that fishing or sidetracking operations are required. In some situations, equipment failure also can result in well abandonment. In addition to these unplanned events, whirl or lateral vibration causes the cutting action of the bit to be inefficient, and ROP may decline significantly. The operator drills approximately four million ft of hole each year, and mechanical-specific-energy (MSE) analysis suggests that the performance in more than 40% of this footage is affected adversely by whirl.

At various times in the past, investigators have focused on certain elements of the drillstring-dynamics problem and have made some progress, to be succeeded by new theories using generally more-complicated models. The current activity is marked by an emphasis on digital-data collection using both surface and downhole instruments, and the use of time-domain modeling to take advantage of increasing computing power. The full-length paper represents an attempt by the operator to strike a forward path by maximizing the benefits of both worlds: using digital systems to take measurements only recently made possible and developing and using sophisticated frequency-domain dynamic-modeling tools to characterize the dynamic performance of BHAs.
Zonal-Isolation Barriers Meet Valhall Waterflooding, Fracturing Demands
Authors: Nijhof Jeroen , Blane David
Published: February 2015

Technology Update

The Valhall field, operated by BP Norge in the Norwegian North Sea, is undergoing a massive redevelopment that will allow the field to keep producing until approximately 2050. With the field undergoing waterflooding, the operator is investigating strategies to prevent formation damage that could result from a waterflood and to minimize costs as the redevelopment program progresses.

The reservoir-management plan relies on multiple-zone water injection, with management of offset water in the producing wells controlled by heavy-duty sliding sleeves. Proppant fracture stimulation of the production wells requires high-differential-pressure isolation between zones. Cementing of the reservoir liner normally provides this isolation between the producing zones, but the presence of cement can render the sliding sleeves inoperable.

The use of zonal-isolation-barrier (ZIB) devices that were developed by READ Well Services was identified as a potential solution for meeting the isolation requirements of the producing wells and was implemented, marking the industry's first use of this, specific ZIB technology (Fig. 1). This alternative approach was deemed necessary to limit the risk of damaging the sliding sleeves and reduce other operating risks, when compared with the established practice of running and cementing the reservoir liner.

ZIB devices possess the advantages of both cement and mechanical barriers, such as packers, in executing zonal isolations, but without the operational risks associated with these traditional technologies. The basic principle of the ZIB technology is that when pressure is applied to the inside of the liner, the metal outer sleeve will inflate and conform to the profile of the formation. If required, the ZIB can also be expanded in the future—for example, should a washout or water breakthrough occur.

The ZIB can be activated by applying pressure from the surface to the entire completion or by deploying a hydraulic-expandable-tubular-system tool by means of wireline, coiled tubing, or drillpipe (Fig. 2). Nine ZIB devices have now been deployed at Valhall with 65/8-in. liners, providing open-hole zonal isolation during fracturing and production operations.
Australia Outback Could Be Next World-Class Unconventional Play
Authors: Redden Jim
Published: February 2015

A small Colorado independent believes the 7 million acres it has under license in the heart of the Australian Outback could very well be the world's next gargantuan unconventional oil and gas play.

"This is a huge resource," consultant Chris Moyes said of the Falcon Oil & Gas holdings in the vast Beetaloo Basin of the Northern Territory. "It is the biggest unconventional resource we know outside of North America. It certainly is of the same class as Gorgon and potentially bigger."

That, indeed, is saying something considering the Chevron Gorgon liquefied-natural-gas (LNG) project at Barrow Island on the Northwest Shelf is widely touted as one of the world's largest-ever production ventures. When combined with existing developments and some 11 proposed greenfield projects, Gorgon will play a key role in Australia's objective of overtaking Qatar as the world's top LNG exporter and possibly help reverse its declining oil production.

As Gorgon dominates most of the news coming out of Australia of late, Falcon is quietly going about seeking strategic partners for a prospect that Moyes said will be a "100-year project." "It will take a long time to fully exploit a resource of this size and type," he said.

Falcon is very optimistic about the project's potential, particularly because it may hold almost 20 billion bbl of oil and 64 Tcf of recoverable gas and is located within a ready-made infrastructure and on the doorstep of one of the world's biggest markets (Fig. 1). "We are very excited about the activity that is going on in the Beetaloo Basin," said Falcon board member Steve Shultz. "We think it has the potential to be a very big part of the Falcon portfolio."

Reservoir evaluation consultancy Ryder Scott conducted an independent analysis of the Falcon Beetaloo holdings and determined the prospect could contain 19.1 billion bbl of oil and 63.9 Tcf of gas. Those estimates were classified as "unrisked prospective resource best estimates," which for undrilled prospects typically is generated by integrating seismic interpretation with regional geologic data and taking into account a number of geological risk factors. Those include the trap risk, source risk, and reservoir risk, which Ryder Scott defines as "the probability that a lithology exists with sufficient porosity, permeability, and continuity to contain moveable hydrocarbons." Moyes said as much as 80% of the Beetaloo resource base is unconventional tight gas and oil.

More Seismic Needed

The Beetaloo, however, has not been entirely undrilled. Between 1989 and 1998, Pacific Oil and Gas drilled 11 wells, all of which showed the presence of oil and gas. Most of those earlier wells were drilled as part of a mining program. "They were looking for minerals, but of course, they got oil and gas shows and began to think of it as an oil and gas play," said Moyes, president of Moyes and Company, upstream technical and transaction advisers assisting Falcon in securing prospective partners.
Digital Oil Field 2.0: Maturity and Paradigms
Authors: Holland Dutch
Published: February 2015

Management

Globally, the digital oil field (DOF) in its relatively brief lifespan has strikingly transformed how the oil and gas industry works. What may not be quite so obvious, however, is that the curtain is coming down on DOF's "overnight" introduction of dazzling new technology and the simultaneous integration challenge. From 3D visualization to revolutionary sensors it has been quite a ride.

In a new industrywide phase coined "DOF 2.0" by Bart Stafford of Science Applications International Corporation, a Fortune 500 scientific, engineering, and technology applications company, the science-fiction DOF concept is maturing. Instead of primarily showcasing ever-newer technological "bells and whistles," now management can actually plan and execute the entire DOF solutions life cycle. With much at stake as to increasing production and maximizing recoverable reserves, it is worth examining this new direction, including the obstacles to its maturity.

Maturity for DOF

Companies reach the watershed point of DOF maturity through a process of "getting all the juice possible out of the orange." Although flashy technology will still emerge from R&D, companies’ DOF initiatives have fulfilled their organic growth and achieved some kind of finality, continuing at a generally even growth rate. In other words, for years DOF innovations have spewed out of R&D with minimal attention directed toward managing the new technology. The next wave will not be marked by exotic development but rather about how to manage solutions into operations.

Keys to effectively making the transition into DOF 2.0 are the sevenfold Dimensions of Maturity. First, and particularly noteworthy in discussing maturation, is the codifying aspect. DOF 2.0 usage and the accompanying transformation of daily operations are now getting written down as a legitimate part of a company's business strategy. This contrasts sharply with the previous corporate thinking that DOF cannot be considered as a strong enough business factor to be formalized into how business is planned and conducted. Therefore, more executive key performance indicators (KPIs) and compensation structures now include specifically using DOF as a means to increase production and maximize recoverable reserves. The three key DOF roles are (1) senior management, (2) asset management, and (3) DOF technologies (i.e., R&D or information technology [IT]). Each of these roles now has more specific KPIs that directly relate to the use of DOF. For example, asset managers must be responsible for two KPIs: "reliable production" as well as the "incorporation of new DOF technology," and R&D must be responsible for two KPIs: both "DOF innovation" and "full implementation" of DOF innovations (Fig. 1).
Technology Focus: Bit Technology and Bottomhole Assemblies (December 2009)
Authors: Mensa-Wilmot Graham
Published: February 2015

Performance Drilling—Moving Beyond the Basics

The industry's continuous push into harsher and more-challenging drilling environments, in terms of formation types, depths, and well profiles, presents several performance challenges. Performance drilling is accepted widely as one of the enablers that will help reverse the high-cost implications of this trend. Consequently, the drive to understand the basics, as it relates to this realization, has preoccupied the industry for some time now.

This effort, which has focused primarily on elements such as rock mechanics and failure mechanisms, bottomhole-assembly (BHA) design, drilling mechanics and hydraulics, and the operational environment, has proved highly beneficial. Extensive amounts of data have been collected as a result of this focus. Additionally, several performance-enhancing tools and processes have been developed.

Having deepened our understanding of the basics, we now must question data to reveal how and why events occur—successes as well as failures. Through this process, we must identify trends, behaviors, and relationships. These observations must be explained because we have the basics. We cannot expect to improve, and effectively confront our looming challenges, when we merely recycle the basics. Performance-improvement objectives will be met only if we turn data into action-able information.

There are tools to help design and understand BHA performance. In addition, there is agreement on the different vibration modes. Field data clearly establish the need for different bit technologies and for different drive mechanisms [e.g., positive-displacement motor, rotary-steerable-system (RSS) "push the bit," or RSS "point the bit"]. Contrary to what computer programs and models sometimes tell us, reality must always be considered as an option. We have the data and the understanding—now we need to move beyond the basics.

Bit Technology and Bottomhole Assemblies additional reading available at OnePetro: www.onepetro.org

IPTC 11945 • "State-of-the-Art BHA Program Produces Unprecedented Results" by David C-K Chen, SPE, Halliburton, et al.

SPE 119375 • "Roller Reamers Improve Drilling Performance in Wells Limited by Bit and Bottomhole-Assembly Vibrations" by Steven F. Sowers, SPE, ExxonMobil, et al.

SPE 119302 • "Experimental Study of MSE of a Single PDC Cutter Under Simulated Pressurized Conditions" by Navid Rafatian, SPE, Schlumberger, et al.
MWD Vibration Measurements: A Time for Standardization
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 119877, "MWD Vibration Measure ments: A Time for Standardisation," by Svein Magne Osnes, SPE, StatoilHydro ASA; Per Amund Amundsen, SPE, University of Stavanger; and Tore Weltzin, SPE, Erik Nyrnes, SPE, Brita Lucie Hundstad, SPE, and Gaute Grindhaug, SPE, StatoilHydro ASA, originally prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.

Since downhole vibration measurements were introduced in the early 1990s, these measurements have become extremely useful for improving drilling efficiency. Most operators will specify a vibration sensor of some sort to be run with most measurement-while-drilling (MWD) and logging-while-drilling (LWD) applications. Unlike most other downhole measurements, there is no industrial standard for how to sample, process, and present the vibration data. This raises a few issues that the full-length paper attempts to address.

Introduction

The lack of standardization of vibration measurements and vibration-data methodology recently has become apparent from several different points of view:Vibration readings cannot be correlated easily and compared from well to well, making it difficult to learn from experiences with different drill bits and drilling tools.It is difficult to use a fair and consistent policy to handle charges from service companies for tools that allegedly have been damaged or scrapped as a result of severe vibrations.Tool specifications from different service companies cannot be compared easily during tender evaluations.It is difficult to perform any form of quality control of contractor's vibration data, including calibration of vibration sensors.It is difficult for drilling engineers or drilling-contractor personnel to develop any universal skills in real-time drilling optimization on the basis of vibration data because the data are not comparable.

Unlike vibration measurements, most other MWD and LWD data have been subjected to strict standardization.

Similar standards exist for other formation measurements such as neutron porosity logging, density logging, and sonic logging, but no industry procedure or standards exist for the calibration, measurement range, or measurement principle of downhole vibration tools.

Background

During drilling, bottomhole equipment is subject to severe accelerations in the form of single or repetitive shocks and as sustained vibrations of the drillstring, both in the drilling direction and transverse to it. Such accelerations can interfere with the drilling operation and can cause equipment failures and destruction of downhole tools, which again has an undesirable effect on the operational costs as a result of time lost for tripping and charges for damaged equipment.
Technology Focus: Reserves/Asset Management (December 2009)
Authors: Hinkle Delores
Published: February 2015

Technology Focus

While selecting the papers for this feature, I noticed two things. First, the topic is wide and varied. It includes everything from simulation models for new-field development to case histories of mature operations. In between, there were discussions of numerous types of sophisticated assessment tools presented for consideration and there was a consistent theme of the need for optimization. My second observation was that this group of papers provided fascinating reading and offers a wealth of diversified knowledge from a representative cross section of our industry. I never cease to be impressed by the intelligence and innovation of the members of our global oil and gas industry. I am honored to be part of a group with such capable and committed individuals.

I also noticed the difference between the two components of this feature. Reserves have been a dynamic component of our industry over the last few years, with the adoption of the SPE/World Petroleum Council/American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers Petroleum Resources Management System (SPE-PRMS) in 2007 and changes to reporting regulations in Canada, the USA, and other countries. In many cases, these new systems and regulations have resulted in step changes in the way reserves and resources are categorized and reported. Asset management, on the other hand, has exhibited a more continual growth toward identifying and capturing more-sophisticated processes and more-complex procedures in search of maximizing recovery while minimizing costs.

Because of the recent changes, the papers selected this year focus on reserves categorization and reporting, while the papers recommended for additional reading focus more heavily on asset management. As the industry becomes more familiar with SPE-PRMS and the new regulatory requirements, it is likely that future editions of the Reserves/Asset Management feature will focus more heavily on the asset-management component of our industry.

Reserves/Asset Management additional reading available at OnePetro: www.onepetro.org

SPE 123931 • "Managing a Giant—50 Years of Groningen Gas" by Niels Dijksman, Royal Dutch Shell, et al.

OTC 20125 • "I-Field Implementation Enables Real-Time Reservoir Management of Newly Developed Saudi Fields" by Said S. Al-Malki, SPE, Saudi Aramco, et al.

SPE 121426 • "Real-Options Analysis in Petroleum Exploration and Production: A New Paradigm in Investment Analysis" by B. Jafarizadeh, SPE, University of Stavanger, et al.
Multistage Plunger-Lift Systems Can Provide Economical Alternative to Pumping Units
Authors: Wienen Julie
Published: February 2015

Technology Update

Plunger lift is a simple and economical artificial-lift (AL) system for wells that primarily produce gas. It is a widespread method of deliquefying wells with high gas-to-liquid ratios (GLRs), for lifting production from wells in which natural depletion has reduced flow rates below critical levels, or for producing from wells with high accumulations of solids, such as sand, salt, coal fines, paraffin, and scale.

However, for some wells, plunger lift by itself may not add enough energy to the wellbore to produce gas in economic volumes. Deep gas and low-GLR wells, with ratios 1:1, may have lift requirements exceeding the capabilities of conventional plunger AL systems. Gassy oil wells often fall into the latter category. Frequently, pump jacks are installed on wells where conventional plunger lift is considered inadequate. Foaming methods to reduce the density of flowstream liquids may also be employed, but these are typically most effective in wells producing primarily water. A more effective strategy for increasing production from gassy oil wells and other wells where conventional plunger lift may be insufficient can be to install a multistage plunger-lift system.

In these systems, a downhole tool is used to create multiple plunger-lift systems in one well. This multistage tool allows the liquid load to be lifted in sequences, a process that uses the well’s own energy to remove even large accumulations of liquids, or heavy liquids, efficiently.

Multistage Plunger-Lift Tool

The multistage tool (Fig. 1) is placed by wireline roughly 40–70% of the way down the tubing above an installed plunger-lift system, typically composed of a bottomhole bumper spring and a plunger above it. Then a second plunger is set on top of the tool.

The system is operated like a conventional plunger-lift system. During the first sales cycle, the lower plunger carries fluids up the tubing and delivers them to the tool. They flow through the tool and are held above it by gas flow. Upon shut-in, the ball check in the tool engages, retaining the fluids until the upper plunger falls from the surface, settles through the liquids and lands at the tool. Simultaneously, the lower plunger falls back to the bottom.

During the next sales cycle, the upper plunger delivers its fluids to the surface, while the lower plunger delivers more fluids to the tool. Both plungers work in tandem in subsequent cycles. In this way, the multistage tool acts like an intermediary standing valve. This process lifts smaller and more frequent liquid loads in stages, allowing the well to more efficiently use its own energy to remove liquids and increase productivity.

The “nodding donkeys” visible at many wellsites demonstrate the popularity of using pump jacks as an AL method. Pump jacks (also known as sucker-rod pumps or beam-pumping units) are typically powered by fossil fuels or an electric motor. They require a significant upfront investment in equipment and installation, and maintenance costs can be considerable.
Beyond Macondo: SPE's Continuing Role in Offshore Drilling Operations
Authors: Beckwith Robin
Published: February 2015

Post-Macondo response

SPE has responded to the Macondo disaster by forming a task force whose ongoing mission is to examine how the Society can best use its resources to tackle the myriad issues that are arising in the disaster’s wake. In addition, the Society developed guidelines to aid in complying with a new Bureau of Ocean Energy Management (formerly the US Minerals Management Service) requirement that companies requesting permits to drill offshore in the US estimate worst-case discharge.

Within a few weeks of the 20 April disaster, SPE 2010 President Behrooz Fattahi appointed a task force (see sidebar), drawn from the SPE Board of Directors, to clarify the Society’s role in addressing technical issues related to the blowout. After meeting several times, the Gulf of Mexico (GOM) Incident Response Task Force drew up a report, which member Paul Jones, global technology center manager at Chevron, presented at the SPE Annual Technical Conference & Exhibition to the board of directors and to SPE’s Industry Advisory Council (a 14-member body representing top management at major and independent oil and gas operators and service companies worldwide).

The report spelled out several efforts being conducted by industry, governmental, and academic bodies (see sidebar), differentiating these from SPE’s mission, which is to “collect, disseminate, and exchange technical knowledge concerning the exploration, development and production of oil and gas resources, and related technologies, for the public benefit.”

Future SPE events, workshops, training, and publications will be devoted to discussing results of the various forensic analyses now under way, and to dissecting and interpreting new standards compliance and best practices. These are dependent on results, standards, and best practices yet to be issued by governmental bodies and such organizations as the American Petroleum Institute, Det Norske Veritas (DNV), and the International Association of Drilling Contractors.

In the meantime, the task force recommended that SPE develop mini-forums to address key issues, such as robust deepwater well design, deepwater well control, and spill mitigation and cleanup. The intent of a mini-forum on robust deepwater well construction, for example, would be to connect deepwater well construction personnel to create a common vision of all the factors that combine to create a robust well design. The objective is to remain focused not on what went wrong with Macondo, but on how a well can be designed such that a blowout will never happen again. A 3- to 5-day mini-forum would cover all aspects of well design—such as hole program and casing design, cementing and zonal isolation, well control, and human factors—from a cross-section of operators, drilling contractors, and service companies. The suggested format would be presentations along with focused discussion, without notes or publication of a report.
Improving Reserves Systems With Continual Reserves Management
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130174, ’Improving Reserves Systems Through Continuous Reserves Management,’ by Tim Loser, Energy Navigator, prepared for the 2010 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 8-9 March. The paper has not been peer reviewed.

Traditionally, “reserves season” begins in the fall and occupies many man-weeks of effort for most oil and gas companies worldwide. With the new US Security and Exchange Commission (SEC) guidelines for reporting reserves, this activity will become more complicated in the absence of new processes. The concept of continual reserves management is presented, in which reserves are reviewed continually and updated during the year.   

Introduction

Companies track production volumes with varying intervals. However, reserves typically are handled as an end-of-year endeavor. This activity is dictated largely by governmental- and financial-reporting requirements and may reflect the business process and tools in place at these companies. As a result, the process of monitoring reserves is reactive, adding little value to the company and providing only compliance.

The full-length paper details the concept of continual reserves management, in which reserves are reviewed and updated regularly throughout the year. Engineers closest to the operations can capture reserves revisions as they occur rather than defer this important task to the end of the year and perhaps delegate it to a reserves coordinator. With continual and proactive management of the reserves and their revisions, the business will have greater insight before the end-of-year roll-up, enabling better intrayear and year-end decisions. This type of system will also result in more-accurate accounting of the reserves revisions and will reduce the resources needed to complete the year-end process.

Continual Reserves Management

Reserves necessarily change with production and market fluctuations. Continual reserves management is a collection of business rules, strong corporate philosophy, improved technology, and business workflows. The most important component is corporate commitment to accurate and timely updates to the system. As with any system, there will be many differences between companies, but any continual-reserves-management system will need some basic building blocks.

Business rules—To ensure smooth operation, these rules must include management and control provisions for regulatory compliance and the rules must define roles and timing for all updates.

Regular reporting—In accordance with the business rules, regular reports to interested parties must be created. Reports to those updating reserves need to be generated automatically to indicate entities showing deviation from plan and other items that need updates. Other regular reports must be available to management throughout the year.

Flexible and simple reserves-update tools.

Open data structures.

Vigorous training.

Visible and strong corporate commitment.