bluuebunny/crossref_metadata_2025_split huggingface dataset:
Decommissioning: A Growing but Challenging Market
Authors: Parshall Joel 
Published: February 2015

The potential market for decommissioning offshore oil and gas production facilities, the process of dismantling and removing them at the end of their useful lives, is large and almost inevitably will grow. More than 8,000 offshore platforms are in place somewhere in the world, according to global insurer Munich Re. The vast majority are in production, but every year some produce their final hydrocarbons. Even new facilities being installed each year will reach that point someday. Essentially, they all line up as decommissioning projects, if one takes the long view.
Decommissioning, required by law in an increasing number of countries worldwide, has been going on for years. The premise is simple. Operators who develop off-shore facilities should be responsible for removing them once they have gone into permanent disuse, rather than leaving the facilities to have a continuing impact on the ocean environment and deteriorate—posing a risk of toppling or generating debris in extreme weather conditions.
However, while decommissioning is a market that appears to be inexhaustible, as long as there is an offshore oil industry, creating a business around it carries substantial risks. Merely planning for potential decommissioning projects can be a challenge. Timetables have often been stretched out and extensions granted to operators, particularly when oil markets have been soft, so heavy lift contractors working the decommissioning market are not always able to predict how many removals will materialize over a given period.
“When I started work [in Europe] 20 years ago, there was talk about decommissioning old platforms,” said Jack Spaan, offshore projects manager at Jumbo Offshore. “The execution of decommissioning projects, however, is delayed time and time again. It has partly to do with lifetime extension of fields. It also has to do with the fact that there is no gain from platform removal. It is driven by legislation. So yes, this work will be there, but because there is no benefit, no cash reward at the end of the day, the sense of urgency is low. And therefore the value of the work to be performed is always under pressure.”
Measurement and Modeling of Topographically Trapped Waves Along the Sigsbee Escarpment
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20694, ’Measurements and Modeling of Topographically Trapped Waves Along the Sigsbee Escarpment,’ by Steven L. Morey and Dmitry S. Dukhovskoy, Florida State University, and Cortis Cooper, Chevron Energy Technology Company, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
Observations of strong currents with wave-like behavior have been documented from specific sites near the seafloor along the Sigsbee escarpment (SE) in the northern Gulf of Mexico (GOM). These currents tend to occur when the Loop Current (LC) or its separated eddies are in the vicinity, typically to the east of the SE. Observational and numerical-modeling efforts were funded in 2008 to understand these events and their dynamics better. The full-length paper summarizes the observations, numerical-model hind-casts, and process studies.
Introduction
The SE runs through the Walker Ridge and Atwater Valley blocks where many new discoveries are being made and developed [e.g., Jack/St. Malo, Big Foot (BF), and Atlantis]. While these cover a relatively small number of blocks, pipe-lines of blocks developed farther south can be affected by flow dynamics along the SE. Strong near-bottom currents, with instantaneous speeds exceeding 100 cm/s, have been observed along the SE. Such strong currents can cause costly delays in drilling and present major engineering challenges to the design of production risers and pipelines. Despite their importance, only a few strong (greater than 50 cm/s) events have been measured to date, and no well-validated numerical model has been developed. To help fill this gap, DeepStar (DS) funded two efforts in 2008—deployment off four moorings for 1 year along the SE and development of a numerical model. In addition to the DS measurements, Fig. 1 shows the bathymetry of the GOM-model domain (left) with detail of the SE-model domain (right). Locations of the Minerals Management Service I2 and I1 moorings, the DS moorings, and the BF site are shown on the right.
Observations along the upper portion of the SE beginning in September 1999 showed strong currents with fluctuations resembling those associated with topographic Rossby waves (TRWs), near the 2000-m bottom, with speeds estimated from the low-pass filtered time series at greater than 85 cm/s. It is interesting that each of the documented strong events occurred when a strong LC eddy (LCE) or meander of the LC was in the vicinity, particularly with the SE near its western edge.
During the early months of 2009, the LC had extended far to the northwest and formed the Eddy Darwin. Several events of moderately strong currents were observed near the bottom during this time.
Technology Focus: Intelligent Fields Technology (May 2011)
Authors: Alves Iberê 
Published: February 2015

Technology Focus
Our industry faces the challenges of achieving an actual “digital field” and of using intelligent-well technologies. What is a “smart” or “intelligent” well? One definition is “a well that has measurement and/or control capabilities in the region of its completion(s).” This can be improved to indicate that “a well system could be called intelligent if, and only if, it adds value to the project during its life cycle.”
To add value to a project, reservoir management must improve beyond the reservoir-engineering discipline, thus becoming a multidisciplinary, integrated team effort. Key project decisions must encompass all disciplines.
The role of intelligent technology, in this scenario, is to gather data from sensors and transform those data into valuable information. Taking advantage of the “digital era,” the oil and gas industry uses more-reliable and more-cost-effective sensors. These sensors significantly increase the amount of collected data, the number of points for the same variable, and even the number of variables measured.
To deal with the enormous amount of data properly, a useful technique is “data validation and reconciliation” of an industrial process. In essence, this technology couples two different worlds: the data (reality) with the model (desire) of a system. Although one may think that data are the real and unique representation of a system, raw data are never fully reliable for reasons such as sensor accuracy and systematic errors. Sometimes data redundancy occurs, and a simple mass balance cannot be satisfied. So, it is nearly mandatory to construct a mathematical model that wraps up all the information into a harmonic and consistent balance of mass, momentum, and energy to represent an entire process for an operating system effectively.
In the years to come, one must seek to incorporate most processes in a modern simulator for reservoir management.
Intelligent Fields Technology additional reading available at OnePetro: www.onepetro.org
SPE 136634 • “How a Smart Completion Can Maximize Oil Production and Recovery Factor in a Stacked Marginal Reservoir” by Gangsar Naroso, ADCO, et al.
SPE 129042 • “Digital-Oilfield Workflows for Increased Automation” by Anil Pande, Infosys Consulting.
SPE 128837 • “Mega I-Field Application in the World’s Largest Oil Increment Development” by Waleed A. Al-Mulhim, Saudi Aramco, et al.
Indonesian Fieldwide Application of Intelligent-Well Technology - A Case History
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21063, ’Indonesian Operator's First Fieldwide Application of Intelligent-Well Technology - A Case History,’ by Kim Sam Youl, and Harkomoyo, SPE, Kodeco Energy Company and Doug Finley, SPE, Halliburton, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.
A fieldwide application of intelligent-well-completion technology was used in Indonesia to commingle “free energy” from an overlying gas cap to support production from underlying oil reservoirs that typically have a high water cut. Previously, wells in this offshore field were developed with conventional gas lift completions that used gas supplied from outside the platform. The application of an “auto-gas-lift” (AGL) concept, an intelligent-well technology, eliminated the capital equipment associated with conventional gas lift completions along with the conventional downhole gas lift equipment.
Introduction
The KE-38 field is in the East Java basin, approximately 30 miles off the northern coast of Madura Island, Indonesia (Fig. 1). Water depth averages approximately 190 ft in this block. The oil columns are between 60 and 300 ft thick, with a 500-ft-thick gas cap (on average) and an underlying water zone. True vertical depth of the gas/oil contact is 4,500 to 5,000 ft subsea.
Porosity of the oil rim ranges from 18 to 26%, and permeability ranges from 20 to 100 md. The reservoir is normally pressured, and productivity ranges from 5 to 20 bbl/(psi-D). Maximum bottomhole pressure and temperature are 2,200 psi and 195°F, respectively. The oil is a slightly waxy, 35°API crude. Given that the reservoir fluid is nearly saturated, initial production from the wells was with natural flow. However, because the flowline pressure is high (approximately 900 psi), these wells would require artificial lift during the initial stage of operation to begin flow and maintain the gas/liquid ratio to optimize the produced-oil rate.
Conventional gas lift completions have a setting-depth limitation relating to the gas lift mandrel. The maximum setting angle is less than 60°. However, an AGL interval-control valve (ICV) is capable of being set in any trajectory angle and can be set at the deepest point in the wellbore to optimize oil production. The AGL completion enables altering the flow characteristics of a zone without mechanical intervention.
Use of a Mechanistic Model To Forecast Cement-Sheath Integrity for CO2 Storage
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 139668, ’Use of a Mechanistic Model To Forecast Cement- Sheath Integrity for CO2 Storage,’ by A-P. Bois, SPE, CurisTec, and A. Garnier, SPE, G. Galdiolo, and J-B. Laudet, SPE, Total, originally prepared for the 2010 SPE International Conference on CO2 Capture, Storage, and Utilization, New Orleans, 10-12 November. The paper has not been peer reviewed.
Implementation of CO2 storage in geological media requires a proper assessment of the risk of CO2 leakage from the storage sites. In particular, it is necessary to evaluate the risk that cement sheaths represent as leakage pathways because leakage could occur if cement becomes damaged or debonded at one of the interfaces of the cement sheaths. Therefore, it is of paramount importance to understand, before CO2 storage, the mechanisms that could lead to cement-sheath loss of integrity.
Introduction
The isolation defect may be the result of improper cement placement. It may be the result of cement slurry contaminated by fluid from the surrounding formations while the cement sets. It also may be the result of inappropriate set-cement properties. Tests performed in the laboratory have shown that there exist two types of mechanisms that could lead to cement-sheath loss of integrity: (1) mechanical degradation when cement is submitted to compressive or tensile loadings that are too high and (2) chemical degradation when cement comes in contact with CO2-enriched water. However field data and degradation-kinetics data show that chemical degradation may not be very fast unless leakage pathways already exist. The worst case is when both degradation mechanisms occur at the same time or one after the other.
A mechanistic model was developed that accounts for the various modes of cement-sheath loss of integrity after cement has been placed was developed. The full-length paper presents the mechanistic model and uses this model to show that cement-sheath loss of integrity depends not only on cement properties but also on well architecture and history.
Cement-Slurry Behavior
Good rheological models are mathematical expressions for the shear stress or the viscosity that give accurate fit of experimental data over a wide range of shear rates and involve a minimum number of independent constants. Those for which the shear stress is independent of the history of deformation are time-independent models. They can be divided into linear, pseudoplastic, and viscoplastic models. Among these models, viscoplastic models, which are characterized by a viscosity that tends to infinity when shear rate tends to zero (plug flow), are at the core of cement-placement modeling. Unfortunately, they lead to experimental and mathematical problems.
Spectrum: A Look at How the SPE Board Works
Authors: Thakur Ganesh 
Published: February 2015

President's column
In my April column, I talked about how SPE’s Board of Directors uses a Strategic Plan to better prepare for change and the need for responsiveness. While the Strategic Plan is formally reviewed once a year, the board uses it to guide its discussions and decisions throughout the year.
The full board meets three times annually following an early-year meeting of the Board Committee on Finance and Administration. One of the three meetings is held in conjunction with the Annual Technical Conference and Exhibition. The other two meetings are held in various locations around the world where SPE has members. The board held its first meeting of 2012 in Perth, Australia, 2–4 March.
At the Perth meeting, the board approved the budget for Fiscal Year 2013 (which runs from 1 April 2012 to 31 March 2013). The budget’s operating plan calls for completing a number of important activities, including the following:
Develop the pilot for the PetroWiki, an industry-knowledge website using SPE’s Petroleum Engineering Handbook as a base to which SPE’s global membership can contribute information
Expand the use of mobile technology to meet the needs of our members, including mobile applications for such things as the Member Directory and events calendar, and SPE’s online communities
Organize more than 140 events globally, with a combined budget of more than USD 40 million
Continue to grow our professional and student memberships
Deliver more than 500 in-person Distinguished Lecturer presentations and extend the Distinguished Lecturer program through use of webinars
Hold several technical section webinars
Award USD 560,000 in scholarships and fellowships
Publish more articles about global issues and technologies in JPT
Hold 120 training courses in SPE’s Houston and Calgary training centers and in conjunction with SPE events and as stand-alone courses around the world
Further globalize SPE’s energy education program
Organize summits on key industry issues
Fully implement a new system to improve submission of paper proposals and manuscripts for meetings
Holding our board meetings in different places all over the world gives us an opportunity to meet with local sections, student chapters, and industry leaders in the region. In Perth, we took the opportunity to meet students and faculty at the University of Western Australia. The board also had a very productive meeting with executives from the region.
Fifteen executives from Australia and Southeast Asia met with the board in a 2-hour session in which they gave their views on the issues facing the industry over the next 10 to 20 years and offered some ideas on ways SPE could help.
Comments: Are Prices Too High?
Authors: Donnelly John 
Published: February 2015

Editor's column
Representatives from the world’s largest oil consuming and producing countries met recently in Kuwait to discuss and debate issues of future energy supply and energy security. The question that dominated the meeting was: Are oil prices too high?
Neither side advocated trying to set a fixed price for a barrel of oil, or even a price range, but both sides expressed concern that current prices might not adequately represent the state of supply and demand, and that high oil prices could cause a recession, hurting oil producers in the long run even though they would reap short-term gain.
The 13th International Energy Forum brought together member nations of OPEC and the International Energy Agency as well as other oil producing and consuming countries. The gathering is the largest forum for energy consuming and producing nations around the globe, and the 88 member nations account for approximately 90% of worldwide oil and gas consumption and production. The group was formed in the wake of the Gulf War in 1991 as a mechanism to foster greater cooperation and energy stability. The forum has been under a brighter spotlight recently because of the oil price volatility of the past several years and because of concerns about whether the world will have adequate energy supplies in the future.
At the meeting, both producers and consumers acknowledged that oil prices are largely beyond their control. Several oil ministers claimed that oil was currently about USD 20/bbl higher than the global supply/demand balance warrants, driven by geopolitical events in the Middle East and “speculation.” Major producers said oil prices had risen about 17% since the beginning of the year and that the OPEC basket, a weighted average of OPEC members’ crude, was USD 16/bbl short of its all-time high reached in 2008.
Although the US and other major consuming nations advocated bringing more supply to the market to dampen prices and avoid the risk of recession, Saudi Arabia’s Oil Minister Ali Al-Naimi said the current market was “reasonably balanced.” He pledged that Saudi Arabia could make up for any shortfalls in production if geopolitical events took some supply out of the market.
In the end, both sides acknowledged that price volatility was bad for everyone and would hurt long-term planning. They also called for more investment in technology to enhance production and reduce carbon emissions. Cooperation and technology development will define how well the industry is able to meet the world’s growing energy demand.
One of the key initiatives of the group has been to create a database—the Joint Organizations Data Initiative—that enhances transparency for both oil consumers and producers. The database includes the collection of monthly oil statistics from member countries, including production, demand, and stock levels. That type of transparency can only reduce perceived supply shortfalls that could lead to price swings.
Choices, Changes, and Challenges for the Digital Oil Field
Authors: Roberts Steve 
Published: February 2015

Guest editorial
It has been 10 years since the Field of the Future program was established at BP to further the digital oilfield concept, and we are now significantly ahead of our initial target timing for delivery. At the end of 2011, the documented production increase resulting from the application of proprietary solutions across many assets was assessed as at least 73,000 bbl of BP net oil equivalent a day—2 years ahead of the plan set internally to reach a target of 100,000 BOPD by 2017. Having achieved this level of progress and successful delivery, the company has been taking some time to consider what it and the industry have learned during this time, and what the future might hold for the digital oilfield concept. By seeking to improve the efficiency and robustness of decision making through real-time data-to-decision capabilities in production, operations, and reservoir management, many challenges have been overcome and many lessons learned since the initiative was launched. The key question now is where do we go from here?
Consider the global situation in which we work. The upstream petroleum industry is focused on providing energy safely, reliably, and efficiently in a world where demand is growing. We are increasingly challenged to meet demand sustainably, with a relentless pursuit of improved safety and environmental performance. The world’s resource base is limited; therefore, companies are moving their attention to more challenging areas, both technically and geographically. Moreover, the industry is also undergoing a significant demographic change in at least two aspects. First, keen competition for scarce technical resources and, second, a switchover from process-orientated, mature geoscientists and engineers toward the next generation of digitally savvy, intuitively motivated intake. The digital oil field has become a key element of the tool kit across the industry to meet these challenges.
Similar to that experienced by the automotive and aerospace industries, the upstream industry is on a 20- to 30-year journey toward ubiquitous, real-time advisory and automated systems. We believe that the upstream is about half way through this journey with at least 10 years to go before reaching a similar level of digital maturity.
Since the inception of the Field of the Future program, one key observation is that typically within the industry, the development of digital oilfield programs appears to roughly follow 5-year phases. Looking back at the industry’s achievements of the past 10 years, it is clear that there has been a huge step forward in the way assets can be managed as a result of this activity.
Drillers Find Themselves in a Tricky Spot at the Human/Machine Interface
Authors: Rassenfoss Stephen 
Published: February 2015

Drilling simulation
When describing his company’s drilling simulator, Lars Namork of Axon Energy Products said experienced rig workers have ended a session drilling a virtual well with shirts soaked in sweat. The story told at a trade show booth at the IADC/SPE Drilling Conference, held 6–8 March 2012, was one of the indications that being at the controls in the driller’s chair is an increasingly complex place to be.
It has never been a simple job. Drillers must balance conflicting demands that can affect everything from the cost of the well to the lives of the crew. They are the critical link between drilling contractors and oil companies, a relationship described as “cooperative antagonism” by management consultant John deWardt, of deWardt and Company, during a presentation on why it is so hard to change how wells are produced.
The growing use of computerized controls led to some unflattering comparisons. Field tests of Schlumberger’s Drilling Advisor system reported at the conference found that drilling with computerized controls easily outperformed human control.
When the computer was in control, the drill bit penetrated the formation 53% faster than it did with a human operator making the drilling decisions. When an operator was inputting settings suggested by a program based on the same algorithm, the rate of penetration exceeded the average for unassisted operators by 39%. An unexpected benefit of the shift to machine control was a sharp decline in equipment breakdowns. There were no failures in the motors or rotary steerable systems (RSS) during the first 11 months of 2011 when there was machine control, compared to four failures over the previous 12 months when operators made the decisions on their own.
Clinton Chapman, drilling automation architect at Schlumberger, explained that computers outperformed humans because the machine is able to consistently apply data on 15 factors affecting drilling performance while a driller can only follow about five. Drillers working with the automation system do not have a fixed role. The system can control drilling based on the well plan, offer recommendations for the driller to enter, or allow full control by the operator. Issues, such as technical problems, can require the driller take charge.