bluuebunny/crossref_metadata_2025 huggingface dataset:
Cross-Industry Hydrocarbon-Release Analysis
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145449, ’Cross-Industry Hydrocarbon-Release Analysis,’ by Amy Li, Oil & Gas UK, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed.

An analysis was made of hydrocarbon releases (HCRs) occurring on the UK continental shelf (UKCS) during the period of 2008 through October 2010. The analysis included the type of hydrocarbon released, operating mode during which a release occurred, release site, age of installation, type of installation [manned or unmanned; floating production, storage, and offloading vessel (FPSO); floating production facility (FPF); or fixed installation], and the underlying cause of the release. This study aimed to assist the industry in identifying where it can best place its resources to reduce the number of HCRs.

Introduction

HCRs are potential precursors to major accidents, with the 2010 Gulf of Mexico incident being a tragic reminder of that potential. Also, the number of HCRs is a performance indicator of asset-integrity management of the offshore installations. Since the creation of Step Change in Safety (UK offshore-safety initiative) in 1997, there has been a 52% reduction in major and significant HCRs. Industry-wide workshops, sharing of best practices on asset integrity, and development and use of toolkits and guidance documents led to an early period of sustained year-on-year reductions in the number of major and significant HCRs. In spite of sustained efforts in recent years, progress appears to have stalled. The total number of HCRs per year has fluctuated between 155 and 190 in the past 5 years, while major and significant HCRs have remained in the range of 60 to 85 per year during the past 7 years. The offshore oil and gas industry is not complacent, and at the end of 2010, Step Change in Safety published a revised HCR-reduction target. The UK offshore oil and gas industry, as a whole, agreed on a target of 50% reduction of HCRs by the end of March 2013 vs. the 2009–10 total HCRs of 187. The challenge for the UK offshore industry is to decide where to focus its effort to reduce the number of HCRs and to achieve its revised target.

Data Sources

Most of the information was extracted from the HCR root-cause-analysis exercise conducted by the Step Change in Safety Asset Integrity Steering Group at the end of 2010. Twenty duty holders supplied their HCR information for the period of 2008 through October 2010. Information on 474 HCRs was collected, and some duty holders also submitted information on leaks that were below the reportable criteria.
SPE Distinguished Lecturer Program 2012-13
Authors: JPT staff _
Published: February 2015

Program review

Featuring 28 speakers from various disciplines and professions, the 2012–13 Distinguished Lecturer Program emphasizes current industry trends, challenges, and technology through diverse topics. Subject areas and speakers featured in this year’s program are listed here.

Advancement in Sand Control Fluid Technology

The number of reservoirs requiring sand control is growing at a fast pace. Fluids play an important role in successful design, execution, and performance of sand control completions. This presentation will familiarize the audience with key fluid technologies, examine benefits and limitations, review development processes, demonstrate success with the aid of case histories, and identify technology gaps.

Bala Gadiyar is a principal engineer at Schlumberger in Houston. He holds a BS degree from the University of Pune and MS and PhD degrees from the University of Oklahoma, all in petroleum engineering.

Improved Recovery and Reduced Costs With Intelligent Interventions—Make Your Wells Intervention Friendly

This presentation will offer an operational perspective on the state of light intervention technology available in the industry and how it is changing the way some operators design their wells for intelligent interventions by making them more intervention friendly. It will also discuss the merits of integrating more contingency planning into subsea, intelligent, and unconventional wells based on light well intervention experience within the industry.

Brian Schwanitz is a graduate of Michigan Technological University in applied geophysics and has worked in the oilfield service industry for the past 34 years.

Crosswell Seismic: Imaging and Monitoring of the Reservoir

This talk highlights the resolution benefit of crosswell seismic, including recent technology enhancements in crosswell imaging that make the method suitable in real-world reservoirs and a number of examples from a variety of applications where crosswell seismic adds economic value in reservoir development, both in high-resolution reservoir characterization and reservoir monitoring

Bruce Marion is general manager of DeepLook-CS, Schlumberger, in Houston. He has been involved in crosswell seismic technology and operations for more than a decade.
Innovation: Volunteerism in SPE
Authors: Imomoh Egbert
Published: February 2015

President's column

This is the last column I will write before the end of my tenure, and I could not think of a better subject to discuss than volunteerism in our global society. As I visited sections and student chapters in different parts of the world, I have been amazed at the number of our members who give valuable time and talent for the good and growth of SPE. I have also been more acute in my observation of volunteerism in our daily lives. For example, early one morning I noticed an elderly lady at a pedestrian crossing helping young children cross a busy road on their way to school. Instead of being cuddled in bed, she was giving her time selflessly to her community.

There are of course many heroic examples, but in most cases volunteers do not go that far. Typically, volunteers give part of themselves for the good and growth of the group they belong to.

The issue of volunteerism was brought to sharp focus when I had the pleasure of a 7-hour drive with a regional director whilst traveling between sections. Our discussion was about why people volunteer. We spent quite some time discussing what drives people to give up their valuable time for activities that don’t result in overt rewards. I have routinely asked members, “Why do you volunteer?”

As to be expected, the responses are varied. Some have joined this corps of volunteers because someone invited them to do so; others have done so to be able to give back some of the benefits they derived from the work of other volunteers; some see the need to ensure that future leaders are exposed to the vast knowledge that SPE has gathered over the years; and others were grateful for the social interaction across the various strata of SPE members and the opportunities to occupy a leadership role out-side their work environment. Whatever the reasons are, the fact remains that a sacrifice has to be made, ranging from adding extra-long hours in the work day to giving up time with family in order to carve out time for SPE activities.
New Methods Developed to Manage Subsea Vibration-Induced Fatigue
Authors: Swindell Rob
Published: February 2015

Technology Update

The vibration assessment of subsea systems has largely been limited to vortex-induced vibration of riser systems and unsupported pipeline spans (i.e., environmental loading) caused by flow past the outside of a riser or conductor. But now, piping vibration caused by process excitation is becoming an issue on manifolds and jumpers, in part associated with increasing production rates. Though the likelihood of a failure is low, the consequences can be high, resulting in an unacceptable level of risk. As well as piping integrity issues, additional vibration-related problems have also been experienced with valves and instrumentation.

Process Excitation Mechanisms

There are a number of different sources of excitation and these generally depend on the type of process fluid within the system. The following three mechanisms are the most common.

Flow-Induced Turbulence. This is caused by broad band, low-frequency energy, generated by “single phase” turbulent flow through valves, expansions and bends—essentially anything that disturbs the flow. This can lead to excitation of the low-frequency modes of the piping system by energy transfer from fluid momentum to the pipe, resulting in low-frequency vibration (up to possibly 50 Hz). This is widespread in most processes and depends heavily on the velocity and density of the fluid.

Multiphase Flow. This encompasses slug, bubble, annular, and churn flow. The frequency range of the resulting excitation is heavily dependent on void fraction and flow regime.

Flow-Induced Pulsation. This is linked to gas flow through a flexible riser or jumper, sometimes known as the “singing riser.” This is where gas across the internal corrugated geometry within the flexible piping causes vortex generation. This can cause a pressure fluctuation, or pulsation, with a frequency and amplitude that are dependent on the gas velocity. This pulsation can drive the flexible piping at either end at very high frequencies—in some situations as high as 1,000 Hz—causing fatigue damage to accrue very quickly. The phenomenon is typically only experienced on dry gas systems, so it can be an issue on gas export, gas injection, and gas lift systems.

The Hidden Threat

Pipe design and construction can present a number of unique challenges in subsea developments, given their remoteness and complexity to access. A vibration issue may occur subsea without any obvious sign topsides.
Finding Pathways to Produce Heavy Oil From Canadian Carbonates
Authors: Rassenfoss Stephen
Published: February 2015

Alberta Heavy Oil

Nearly 2 million bbl of ultraheavy crude are produced each day from Canadian oil sands, but the notion of also producing bitumen from reservoirs made of carbonate rock can spark skeptical remarks.

They are likely to say something like: “Carbonates are very different. In carbonates, it is just different,” said Daniel Yang, director of reservoir engineering at Laricina Energy, who has a different reading of the exploration history of formations that hold more than 400 billion bbl of the crude.

Laricina has partnered with a second Calgary independent, Osum Oil Sands, to try to prove that bitumen can be commercially produced from the Grosmont formation, which holds 75% of the heavy crude known as bitumen in Alberta’s carbonates.

The reality is the Grosmont is different. A pilot project by Laricina and Osum showed that the well design commonly used for oil sands is not a good fit in carbonates. But a mix of methods used for bitumen production worked well enough to convince the partners to plan a commercial test. that they plan to use for the first commercial development in the formation.

The Laricina-Osum joint venture has filed for a permit to produce as much as 10,700 B/D from up to 32 wells, with first oil in 2015. Husky and Shell have also filed for permission to do pilot projects with the Alberta Energy Regulator, the agency formerly known as the Energy Resources Conservation Board (ERCB).

“It is going like early development in major oil sands basins such as the Athabasca, where there were many field pilots,” said Eddy Isaacs, chief executive officer of Energy and Environment Solutions at Alberta Innovates, a provincial agency that funds research, including past carbonates work.

But moving from wells producing oil in situ in the relatively consistent sandstones and unconsolidated sands to carbonates will require significant advances in production methods and simulation software. The Grosmont was born complicated. It was formed hundreds of millions of years ago from the hap-hazard deposition of marine life off a long shoreline, was chemically transformed into dolomite, followed by water flows that carved it up, widening the fractures and carving out so many holes in the rock that it created weak spots in a formation that has been lifted and crushed and filled with oil that degraded into some of the world’s heaviest crude.
New Challenges Demand New Energy Leadership Skills
Authors: Lloyd Frank
Published: February 2015

Talent & Technology

New technologies have enabled the energy industry to access a bounty of oil and gas so large that worries about running out have melted away. Some journalists have even turned their attention from “peak oil” to “peak car,” as the number of miles driven by many urban dwellers declines and as teenagers who prefer to connect using social media delay the age at which they acquire driver’s licenses. “Suddenly, out of nowhere, the world seems to be awash in hydrocarbons,” said Michael Greenstone, an environmental economics professor at the Massachusetts Institute of Technology. And yet, abundant and growing supplies that can easily meet the world’s energy demands have not eliminated the industry’s complexities and challenges. Three new challenges that demand new leadership skills stand out.

Consolidation. According to financial analysts, the financial markets understate the value of many energy company stocks, paving the way for continued consolidation that will require more sophisticated levels of financial and organizational leadership. Yet firms are reluctant to take new risks and invest in human capital to develop a higher level of leadership when they may be acquiring or acquired in the foreseeable future.

Changing Roles. The service sector is gaining increased importance within the industry. Service firms represent the bulk of research and development spending, more than twice what exploration and production (E&P) firms now spend. They are increasingly taking risk positions in oilfield drilling and development. This provides E&P firms opportunities to outsource technical development. In addition, supermajors are outsourcing E&P operations to mid-majors and buying back the rights to develop newfound plays. Service firms also represent the bulk of industry hiring, adding jobs at three times the rate of E&P firms. And they are forming direct relationships with national oil companies. All this means that leaders in service sector and mid-major firms are being forced to increase their ability to assess risk, form alliances, and navigate the global industry.
Design-Guideline Strategies for High-Pressure/High-Temperature Equipment
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 23943, ’Design-Guideline Strategies for High-Pressure/High-Temperature Equipment,’ by H. Brian Skeels, Kwok Lun Lee, and Anand Venkatesh, FMC Technologies, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.

As the need for oil and gas equipment working in hotter and higher-pressure environments continues to mount, the effort to develop an adequate set of design, material, and validation practices continues to be challenging. More-rigorous stress analysis and design methods that more closely model fast-fracture burst conditions are needed to achieve safe, reliable, and cost-effective equipment designs. 

Introduction

As oilfield equipment is subjected to more-severe and longer periods of cyclic forces (internally from irregular wellbore flowing conditions or externally from metocean conditions), many agree that fatigue life and monitoring for these conditions has to be a part of the design equation. This fact is mentioned in the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, recognizing the two failure modes of a pressure vessel: leak before burst or a fast-fracture burst. Many oilfield design guidelines negated a need for fatigue analysis because of the long-standing practice of keeping maximum design loads and stresses well below two-thirds material yield strength, a practice that also keeps cyclic-loading issues well inside the “infinite” region on S/N curves in most cases. Unfortunately, this quasi-static design philosophy grows less accurate as the pressure vessel’s wall thicknesses grow or geometries become more complex when addressing high-pressure/high-temperature (HP/HT) conditions. As a result, many have turned to the ASME Boiler and Pressure Vessel Code for guidance. Divisions 2 and 3 of the ASME Code present alternative design methodologies to be considered as internal pressure and temperature increase. However, the designer, using the code, is still free to select which division to follow for his application.

The American Petroleum Institute (API) has long followed a subset of Division 2 of the ASME Code, but it now recognizes many shortcomings as one considers HP/HT conditions. The published technical report only cites the current state of the art and discusses the issues to be tackled. Many observers agree that leaving the issue to so-called “sound engineering judgment” would result in many variations of opinion between operators and manufacturers, likely resulting in inefficiency and repeated tasks. Current efforts address two options: extending current API design practices to higher pressure ratings or establishing a demarcation when different design practices are needed.
HP/HT Pipelines Designed for Lateral Buckling in the South China Sea
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17181, ’HP/HT Pipelines Designed for Lateral Buckling in the South China Sea,’ by H. Brian Skeels, Kwok Lun Lee, and Anand Venkatesh, FMC Technologies, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed.

Gas production in the South China Sea has seen an increasing trend of pipelines operating in high-pressure, high-temperature (HP/HT) conditions. This has led operators to look beyond the conventional stress-based design and move into strain-based design using the lateral-buckling-design approach. This paper presents both construction challenges and operational works post-startup, aiming to provide operators with cost-effective construction solutions and a risk-based maintenance philosophy when considering lateral-buckling design.

Introduction

Lateral-buckling design is a strain-based design that allows the pipeline to expand laterally at   locations in a controlled manner. This allows the pipeline to relieve its thermal expansion by lateral movement rather than being axially restrained (i.e., through trenching and burial).

As with any unconventional methodology, such design has certain limit states that require careful consideration. These limit states include local buckling, low cycle fatigue, fracture, and pipeline walking. These limit states are addressed during the design phase, except for fracture, which is addressed during the construction phase. During operation, these limit states are also monitored periodically to ensure that design thresholds are not exceeded.

Construction Challenges and Solutions

Initiation Method. Lateral-buckling design requires suitable initiation methods to ensure that the planned lateral buckles for a pipeline are initiated at the designated locations during startup. The initiation methods are typically executed during the pipeline installation itself rather than before or after the installation. It is therefore important that the initiation method be as practicable as possible for construction, and also effective, to guarantee the success of the lateral-buckling design.

The purpose of an initiation method is to provide a low critical buckling force at the designated location, thus providing a higher probability that the planned buckle will initiate at the location intended. This can be achieved by creating an artificial imperfection either vertically or laterally on the seabed. One of the most frequently used methods, which combines both vertical and lateral imperfections, is the zero-radius-bend (ZRB) with buckle-trigger method.
Extensive Environmental-Monitoring Project Relies on Integration of Several Networks
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156294, ’Innovative Environmental Monitoring for Upstream Onshore Installation,’ by Paolo Carnevale, SPE, and Silvia Di Croce, Eni, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11-13 September. The paper has not been peer reviewed.

A comprehensive environmental-monitoring project in the Agri Valley in southern Italy has been developed to ensure continuous management of the environmental effects of Eni’s oil treatment center there. This project is able to control the environmental effects of exploration and production in a large area around the plant (100 km2). It is characterized by a complete integration of several networks, stations, and systems used to monitor simultaneously air quality, noise, odorous emissions in terms of olfactory nuisance, groundwater and soil quality, ecosystems status, and ecological biodiversity.

Introduction

The area where the environmental-monitoring project was developed is characterized by sites that have community-level protection, especially areas protected because of national parks, widespread woods, rivers and streams of high quality, and springs and ground water of great regional and national importance for the production of safe drinking water.

Eni’s oil treatment center in this territory collects the production from 24 oil wells, amounting to approximately 104,000 BOPD (Fig. 1).

The environmental-monitoring plan consists of environmental-monitoring networks on more than 100 km2 at altitudes between 600 and 900 m. The system includes monitoring networks relevant to the following environmental variables:

Air quality

Biosystems

Bad odors

Noise

Microseismicity

Ecosystem

Air Quality

The network consists of four monitoring units placed 2.3–4.8 km from the oil center. The sites were chosen according to a model that predicted the spread of emissions from the oil center. The air-quality-monitoring stations were installed outside the plant to continuously identify the effects that production activities have on the quality of the air and to provide operational warnings to avoid any negative effect on the surrounding territory.

Each unit is provided with computerized instruments, allowing continuous monitoring of the levels of carbon mon-oxide, hydrogen sulfide, sulfur dioxide, ozone, nitrogen oxides, benzene, toluene, xylene, methane, nonmethane gases, volatile organic compounds, polycyclic aromatic hydrocarbons, and radon, and monitoring of meteorological standards (e.g., wind speed and direction, rainfall levels, humidity, temperature).

The data received continuously from the monitoring units are reported in real time on the Web and in the control room of the plant and are compared continuously with information on pollution standards taken from the chimneys of the oil center.
Emerging Frontiers: Frontiers in Technology Dissemination
Authors: Spath Jeff
Published: February 2015

President's column

I must write my final column, before next month’s recap, on the most fundamental mission of SPE, our core purpose, our raison d’etre: the dissemination of technology. More precisely, I am talking about the part SPE plays in the dissemination of independent, unbiased, trusted, and reliable technical information and knowledge. SPE is recognized worldwide for its role in this area and it is the topic that makes up the heart of our mission statement, which incidentally has not changed in 35 years.

The rationale for quality technical information dissemination and knowledge sharing is at least twofold. Firstly, for individual members to progress in their career and take on more challenging roles of increasing responsibility, they must develop, maintain, and improve their skills and expertise through knowledge sharing and by having access to quality, reliable technical information. Secondly, the value proposition of most companies in our industry hinges on the technical expertise of its people, so it is necessary to continually develop employee expertise as a competitive advantage. A large part of this development comes from SPE-provided literature, training, and knowledge gained from conferences, workshops, and forums.

Many of our knowledge domains are undergoing rapid change, which elevates the importance of SPE’s ability to share technical information and knowledge in a timely manner. Deepwater exploration, shale gas and shale oil production, subsea development, and heavy oil recovery are a few examples of subjects for which yesterday’s technical information is inadequate. The globalization and remoteness of our industry’s workforce is another reason we must continually advance the ways in which we distribute technical information. Finally, the retirement of many of our longest-tenured experts requires that we accelerate the learning of the younger professionals and the efficient dissemination of quality technical information is the key.

Technical Quality

If your mission and livelihood is to disseminate technical information, the quality of the information is paramount and must override any measure of timeliness, affordability, accessibility, or availability. If you do not have the utmost confidence in the quality of the technical information or the knowledge being shared, it does not matter the user-friendliness of getting the information. There is no doubt that the number of technical presentations and papers being written has grown rapidly over the last decade, tied to the significant growth in the number of conferences and workshops.
Comments: Reader Survey
Authors: Donnelly John
Published: February 2015

Editor's column

Last month, JPT concluded its annual readership survey to assess SPE members’ opinions of this magazine’s content, coverage, relevance, strengths, and weaknesses. The information will be used to improve JPT’s quality and to help plan content for the coming year. An invitation to participate in the survey was sent to a random sample of 30,000 professional (non-student) members, representative of the demo-graphics of SPE. Of the respondents, 44% reside outside the US, 82% of them have more than 10 years of experience in the oil and gas industry, 40% are engineers, and 24% are managers. Responses came from members who work for operators, national oil companies, service companies, and consultancies.

The most widely read features in JPT are Technology Update, the summaries of technical papers, and Technology Applications, highlighting our readers’ interests in emerging technology, practical deployment of technology, and case studies. This also confirms results from previous readership surveys. Regarding specific technical topics, respondents expressed the most interest in field development projects, mature fields and well revitalization, and horizontal and complex trajectory wells.

Looking at some other findings, the overall ranking of JPT rose compared with previous surveys. In this year’s survey, 95% of respondents rated JPT as excellent, very good, or good and 77% rated JPT better or significantly better than other upstream publications, up from 65–70% in previous surveys over the past decade. Just under 90% of readers said JPT was useful to them in their daily job.

The summaries of SPE technical papers in JPT have always ranked near the top in readers surveys. JPT’s 42-person Editorial Committee—made up of volunteer members representing all facets of the upstream oil and gas industry—survey scores of technical papers every year for possible publication. Last year, the committee pored over 3,138 technical papers before selecting the final ones for publication in JPT. Their work results in the publication of approximately 130 papers over the course of the year in 42 different upstream technical topics, the best papers representing the state of the art in a particular technology. The summaries of those papers appear in each issue, while the full-length papers are available free to members for 2 months at JPT Online.

Speaking of JPT Online, our website has a new look and a new address (www.jptonline.org). The website was redesigned based on the results of reader surveys, a focus group, and industry trends. The revitalized site contains more news and more in-depth coverage of emerging technologies and the latest technology applications, with articles organized by discipline and region, and has a new search engine. Members can continue to download the free technical papers summarized in JPT as well as view the print archives at the site. Please let us know what you think of the changes.
Eni Makes Its Mark
Authors: Donnelly John
Published: February 2015

Editor’s note: This is the third in a series of profiles of leading operators, including key international and national oil companies, around the globe. The focus is on the company’s strategic direction, relationship to its government, major upstream activity, and significant technology challenges and applications.

Italian energy giant Eni plans to meet ambitious future growth targets with a strategy focused on conventional reserves, quick time to production, and continued success in Africa.

Eni is a major integrated energy company, involved in oil and gas, electricity generation, oilfield services construction, and engineering, but its future lies largely in E&P. It has bulked up its reserve base this decade and hopes an upstream strategy based on speeding up production time will pay off over the next several years as new fields come on line.

Total oil and gas production for Eni is flat so far this year and fell last year, putting pressure on the company to fast-track output. For the first half of 2010, total oil and natural-gas production amounted to 1.77 mil-lion BOEPD, a decrease of 28,000 BOEPD from 2008, although much of that can be attributed to OPEC cuts that affected its operations in those countries. Weak European gas demand, security issues in Nigeria, and mature-field declines also hurt production, but that was partly offset by production increases and field startups.

Leveraging organic growth in Africa and Central Asia, the company plans to deliver more than a 2.5% average growth rate over the next 4 years, targeting total production levels of more than 2 million BOEPD by 2013. A total of 41 projects worldwide are scheduled to come on line by 2013, some in countries with a recent past of political risk.

Eni claims a total of 30 billion BOE in total resources, a base built in recent years through exploration, access to giant fields, and a few acquisitions. Most of those reserves are in legacy areas, where Eni is a leading operator, and are considered conventional, low-cost plays. The firm says its priority in the short to medium term is to expedite the development of this potential through a new organization model focused on bringing production on line as quickly as possible. It aims to increase its recovery factor, which currently is 34% for oil and 65% for gas.
Technology Focus: Completions Today (September 2010)
Authors: Horvat Damir
Published: February 2015

Technology Focus

Making the Good Completion Better

The ability of operating and service companies to optimize completion results from standard completion configurations through better reservoir-fluid management has been enhanced greatly by the development of advanced completion hardware [i.e., inflow-control devices (ICDs)]. These devices enable us to “fine tune” flow from individual pay zones that are over- or underpressured. Field performance of wells equipped with ICDs and multisegment-well modeling, including ICDs, have indicated measurable advantages over conventional completion systems. Industry also developed perforating-gun modules that can be configured to perforate the formation in any desired orientation. As each gun module is fired, a flapper valve is actuated to isolate the newly created perforations from the lower, previously stimulated zones. This process ensures accurate and efficient proppant placement.

An operator’s goal is to reach production faster, with the widest assortment of specialty tools and hardware, which have been improved continuously over the past decade. Today, many operators use multilaterals, which enable maximum reservoir contact with minimum surface requirements and can accommodate a wide range of completion options. Whether the play is a conventional shallow-gas or deep-gas reservoir or an unconventional-oil/-gas reservoir, use of these technologies can increase production while improving project economics. Reliable and field-proven completion solutions enable creating the ideal conduit from pay zone to surface, regardless of well type or operating environment. This is the key to getting the greatest return on field-development investment and to minimizing life-of-well cost.

This overview will not attempt to refer to all new well-completion technologies, but only to highlight a few important recent developments and concepts. Nevertheless, as one searches the literature, the importance of JPT’s role becomes obvious from the large number of references and papers cited with relevance to significant technical achievements in the upstream petroleum industry. There are many papers about technological advances, and I congratulate respective authors in bringing their papers to fruition.

Finally, I hope you enjoy reading the selected papers as much as I did during review and selection for the feature.

Completions Today additional reading available at OnePetro: www.onepetro.org

SPE 125508 • “New Approach to Drilling and Completing Horizontal Wells in Extremely Shallow and Unconsolidated Reservoirs” by Shahryar Saebi, SPE, Schlumberger, et al.

SPE 122765 • “World’s First Reverse-Port Uphill Openhole Gravel Pack With Swellable Packers” by Rene Jansen, Brunei Shell Petroleum, et al.

SPE 128569 • “Integrated Approach: Perforation-System Optimization for Sand Prevention” by Mohd Zahirin B. Ruslan, SPE, Schlumberger, et al.
Monobore Completion System Provides Low-Cost Completion Option
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124797, ’Monobore Completion System Provides Low-Cost Completion Option,’ by Don Ingvardsen, SPE, and Jim Kritzler, SPE, Baker Hughes, originally prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. The paper has not been peer reviewed.

Many wells completed today could be classified as short-life or harvest wells. Some of these would not be economically feasible using high-end completion components and methods. Monobore wells can be a solution to this problem. The full-length paper discusses several methods in which monobore well design can save considerable time while lowering the overall completion cost.

Introduction

When a well has a single produc-tion-tubing size from the pay zone to the surface of the completion, it is categorized as a “monobore” comple-tion. Although there are certain limita-tions to this type of completion, there are many advantages that make it a very attractive alternative to conven-tional completions. Drilling cost and reduced equipment list are the great-est motivators to pursue a monobore well because they directly affect the cost to complete. Most of these wells would not have been feasible if the only option was to complete them in a more traditional manner. However, if there were a system that reduced rig time and decreased the equipment list (e.g., packers and sliding sleeves), while still safely completing the well, these wells would move from the category of unfeasible or marginal to profitable or, in some cases, highly profitable. One of the early methods was simply cementing the completion in the well-bore. Later options include staging the cement process to include equipment that would increase the life of the well and ensure its safe operation.

Significant time and effort have been expended to develop a more reliable system for completing these wells and increasing their productivity, making them even more attractive. Specially designed cement-through components, including safety valves and gas lift (GL) equipment, can be credited with mov-ing these monobore completions to the next level. The inclusion of a reli-able safety valve speaks for itself with regard to producing these wells safely, but introducing the GL alternative at the beginning has increased the over-all production significantly. Wells that were estimated to produce 500 to 600 B/D were improved to 1,200 to1,400 B/D. The majority of these completions have been completed in the Gulf of Thailand, but there are other fields in the world that are candidates for this system, and equipment has been mobi-lized to some of those areas.
Increasing Drilling Efficiencies Through Analysis of Real-Time and Historic Drilling Data
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 128722, ’Increasing Drilling Efficiencies Through Improved Collaboration and Analysis of Real-Time and Historical Drilling Data,’ by Catheryn Staveley, SPE, and Paul Thow, SPE, Schlumberger, originally prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, The Netherlands, 23-25 March. The paper has not been peer reviewed.

Estimated spending on drilling and completions was more than USD 250 billion in 2008. With rig costs estimated to consume 37% (or USD 92.5 billion) of that spending, every effort to reduce drilling time has a direct effect on the bottom line. Estimates of nonproductive time (NPT) ran from 15 to 40%, or USD 14 to 37 billion, depending on well type and operator. The causes were varied and included technical and nontechnical challenges. Obviously, any effort made to reduce NPT will affect bottom-line spending. 

Introduction

The oil and gas industry spends millions of dollars each year collecting vast amounts of drilling data, yet has not made effective use of these data to improve drilling performance. Drilling analysis is a proven technique for improving the return on investment of drilling operations, but comprehensive drilling analysis has not been a regular part of well planning and operations.

So why is it that comprehensive drilling analysis is not a consistent part of drilling best practices? In part, perhaps, because of the culture. One author suggested that 95% of drilling activities are operationally focused, placing emphasis on doing, rather than planning or analyzing. Many people in drilling operations thrive on operating by “gut instincts” and succeeding through heroic efforts. While experience dealing with unexpected events is crucial for success in an environment where uncertainty exists, surely it would make more sense to be taking pride in telling stories about the well where everything went according to plan. Furthermore, while most companies have health, safety, and environmental policies that are “zero-tolerance,” an acceptance of waste and inefficiency as being inevitable in drilling operations continues. It is difficult to imagine another industry that would accept 60% waste when it is widely known that something as simple as better planning can improve drilling results.

Two other key obstacles to integrated drilling analysis are the inability to manage the volumes of data that potentially could be used in drilling analysis and the historical limitations of traditional well-planning software. The vision for integrated drilling analysis includes the ability to:

Visualize and correlate low- and high-density data.

Allow effective sharing of cross-discipline expertise.

Provide continuous real-time updates.

This integrated approach includes technologies to overcome data-management challenges and well-planning limitations, and to implement multi-disciplinary work flows to help facilitate planning and analysis across an asset team.
Evolution From Casing Running to Assurance of Total Depth
Authors: Cummins Tracy
Published: February 2015

Technology Update

Well construction, hazard mitigation, and drilling equipment have evolved significantly over the past 10 to 15 years. One of the most critical aspects of well construction is assuring that casing strings are installed to the planned depth with gas-tight connections and sound mechanical barriers between them. The widespread acceptance of top drive casing running and drilling with casing have played a key role in recent developments to the delivery of high-integrity casing strings.

Top drive casing running tools attach to the rig’s top drive and combine many conventional casing tools into one sys-tem. They extend the functionality of the rig’s top drive from drill pipe to casing, thus enabling simultaneous rotation, reciprocation/push down, and circulation of the casing string. Adding a reaming shoe or drillable casing bit to the casing string makes it possible to ream in a pre-drilled section, extend through problem zones or drill complete hole sections with the casing string. This addition opens a broad range of options to increase drilling efficiency and reduce nonproductive time.

Technology Expands Top Drive Applications

Top drive casing running systems first came into use in the 1990s. Initially, these systems were used primarily on purpose-built casing drilling (land) rigs. Soon after early deployments, the technology became an accepted way to run casing. However, its use was still limited to land rigs and running API threaded tubulars.

By 2005, further development of the technology portfolio included equipment designed to accommodate a broad range of applications such as:

Offshore rigs—casing sizes up to 22 in., torque up to 80,000 lbf-ft

Premium connections—independent torque monitoring and active weight compensation

Heavier casing strings—hoisting capacity up to 750 tons

Running casing in stands—interfacing with pipe handling and rig control systems

High-angle and ultraextended-reach wells—pushing, rotating, and floating casing strings

Chrome tubing completions—minimal marking systems and torque control interface

During this time, the equipment for drilling with casing and casing connections also evolved, with the development of a number of drillable polycrystalline diamond compact casing bits and higher torque- and fatigue-resistant connections to cope with various formation strengths and geology.

Today, these technologies are field proven in a number of applications and readily available across the globe. Thousands of casing strings have been run or reamed by means of the top drive system, and more than 2,000 problem zones or well sections have been successfully drilled with the casing string.
Joint Venture Challenges Drilling's Status Quo
Authors: Rassenfoss Stephen
Published: February 2015

Shell is facing up to fast-rising future drilling costs by taking control, with a venture that will build, own, and operate drilling rigs. The company has created a joint venture with China National Petroleum Corporation (CNPC) to build a new generation of special-purpose automated drilling equipment.

There is a back-to-the-future quality about the strategy. Oil companies once owned many of the rigs used to drill their wells, but largely got out of the business in the 1970s and 1980s as they pared back to focus on the more profitable business of finding oil and gas.

Shell is changing its strategy as the number of wells it drills soars to take advantage of unconventional reserves. For example, rather than drilling 10 highly productive wells to develop an offshore field, Shell expects to drill about 10,000 wells to produce natural gas from a single coalbed methane project

“The well manufacturing joint venture is an opportunity to redefine our costs in an area where we spend a significant amount of money,” said Peter Sharpe, executive vice president of wells at Shell.

Shape declined to say how much Shell expects to invest or benefit from the venture. The agreement was signed between the companies in late June. As of late July the two sides were working on a detailed business Sharpe plan and negotiating details, such as what intellectual property each would contribute. The operation, which has not yet begun design work, expects to begin production in 2013.

The venture is not going to become the driller of choice on all Shell projects. It is aimed at fields requiring high-density drilling, with thousands of wells drill over decades. Fields that do not fit into that category include Shell’s US shale holdings, where the drilling is not on the scale needed for its high-density field approach.

The business plan for Shell’s manufactured drilling program goes after costs in a variety of ways. It combines new technology—drilling automation—with long established cost-cutting strategies: partnering with a low-cost provider, economies of scale, specialization, and cutting out the middleman.

Shell’s partner in China, CNPC, is a major maker of drilling rigs in one of the world’s largest and most efficient manufacturing economies. While Shell is far better known, Sharpe said CNPC’s budget for drilling and completing wells is comparable to its own.

The automated drilling program is expected to lower costs by drilling wells faster with fewer people on site, which should make it safer as well. It reduces the number of rig workers, who are hard to find in some territories. Sharpe said there are countries where “we can’t train the people we need at the rate we need them.”