bluuebunny/crossref_metadata_2025 huggingface dataset:
FPSOs Enter The Gulf Of Mexico Operator Tool Box
Authors: Lovie Peter
Published: February 2015

Editor’s note: This is the second of two articles on the technical challenges and regulatory hurdles that were overcome to allow the use of floating production, storage, and offloading vessels (FPSOs) in the US Gulf of Mexico (GOM). The FPSO that will be installed at Petrobras’ Cascade/Chinook development in the deepwater GOM is planned for mid-2010 startup.

As 2006 progressed, teams of operators’ engineers continued deliberations on how to make a start on producing two US Gulf of Mexico (GOM) field developments using a floating production, storage, and offloading (FPSO) vessel as an early production system (EPS). One team decided against it and the other agreed that an FPSO did make good sense for its field. It was an interesting contrast in the philosophies of two operators: one (Chevron) very deliberative and exhaustive, investigating all options before proceeding and only then in a tightly organized project management and planning structure; the other (Petrobras) with a more pragmatic approach, borne of the uncertainties faced in production from these untested formations and their success in Brazil in trying out production for a short period at new fields (Fig. 1).

The use of an FPSO was agreed for the Petrobras-operated Cascade/Chinook development (Devon as a partner on Cascade and Total on Chinook). At multiple standing-room-only technical sessions at the 2007 Offshore Technology Conference in Houston, the offshore industry debated and settled on design-code revisions. Simultaneously, negotiations proceeded on contracting the first FPSO for the GOM, and August 2007 saw the contract signed for chartering the first FPSO in US GOM waters, for the Cascade/Chinook development. Competition had been fierce for this pioneering project.

Within weeks, two new shuttle tankers were chartered to provide export to GOM ports. This was not as simple as it sounds, as these tankers would transport oil from one US port (the FPSO) to another US port (the shore terminal or refinery) and so had to conform to the Jones Act, which stipulated that

Crews had to be US citizens.

The ownership of the tankers had to be at least 75% US.

Tankers for Jones Act trade had to be built in the US.

All of the conditions translate to high capital expenditure and day rates, approximately 2–3 times that of a non-Jones Act tanker. The Merchant Marine Act of 1920 (The “Jones Act”) does apply to shuttle tankers, but does not apply to FPSOs.

By standards elsewhere in the world, the shuttle tankers used in the US GOM are not particularly efficient—they are small (approximately 330,000 bbl capacity) to enable entry into US GOM ports with 40 ft draft restrictions, and must have alternate use in products service in US waters if the shuttle-tanker business does not continue.
Technology Focus: Multilateral/Extended Reach (May 2010)
Authors: Negrao Alvaro
Published: February 2015

Technology Focus

Exploration and development projects suffered from uncertainties caused by downsizing of the worldwide economy last year. Wide variation in value of our main commodities caused delays in several offshore oil- and gas-asset projects.

Our industry must ask if it has done enough to deal with these variations in commodity values and what would be the best way to mitigate their influence in the current market. Current statistics show that there is a long way to go. The cost of nonproductive time (NPT) is very high and needs to be mitigated. The importance of improvement performance in a critical economic environment is crucial to maintain our business. The main question is how to keep the interest of investments in this scenario.

Fundamental to evaluating techniques, equipment, and design is understanding the risk variability. Professionals must respond to a more-fluid, less-certain business environment than did their predecessors. Assessing data and planning and executing a well involve a complex interaction of data, regional knowledge, and field experience. Different subjects not considered before such as communication skills, adding value, team building, and networking have a major role in mitigating the risks and in improving the performance and financial return of a project. These dynamics, along with increased globalization, require a broader set of skills.

We are succeeding in drilling and producing wells in water depths and measured depths greater than 10,000 and 35,000 ft, respectively. However, decreasing NPT to acceptable ranges has not happened. Although innovative technologies have been implemented over the last 10 years that enable exploration and development in environments with difficult tectonic stress and subsalt or presalt wells, we still lack efficiency. In offshore operations that cost our industry more than USD 1.3 million/D, the current NPT between 20 and 30% in several areas of the world is not acceptable.

For the sake of future business, operators and service companies should work together not only in development of new technologies but in aligning common goals such as a consistent NPT less than 5% in operations, which would guarantee several projects. This target requires a common goal of operators and service companies who, unfortunately, to date, have not been brought together, but in the current environment it is essential for our future.

Multilateral/Extended Reach additional reading available at OnePetro: www.onepetro.org

SPE 128314 • “Multilateral Wells Reduce CAPEX of Offshore, Subsea Development in Australia’s Northwest Shelf” by Brett Lawrence, Apache Energy, et al.

SPE 128461 • “Successful Application of Dual-Lateral Junction Technology To Develop a Marginal Gas Field in the Carboniferous Area of the UKCS Southern North Sea” by A.J. Hatch, E.ON Ruhrgas,  et al.

SPE 128915 • “An Experimental Study To Define Operational Parameters Governing Hole Enlargement While Drilling Offshore Heavy-Oil Reservoirs” by F.G. da Costa, Petrobras, et al.
Technology Focus: Well Construction (May 2010)
Authors: Carpenter Bob
Published: February 2015

Technology Focus

In 2009, the focus of well-construction technology was primarily in two areas: our ability to drill and reliably complete deepwater and high-pressure/high-temperature projects and exploration of the reliability of carbon-capture and -sequestration (CCS) storage wells. Outside these big focus areas, some papers relating construction practices specific to the shale plays are beginning to come forth.

Lost circulation is still one of our biggest obstacles to getting deepwater wells to target depth. Unfortunately, lost-circulation issues are expected to become even more difficult in these fields as pore pressure drops because of production and depletion. In one paper, details are presented of higher-risk squeeze techniques used to shut off high-rate losses, enabling completion of two potentially lost wells. The full paper may be a good read the next time you find yourself in such a situation.

As we discussed here last year, CCS is our next big area of activity. Progress and acceptance of CCS depend upon very-long-term isolation of the injected CO2. One of the big questions with CCS-well construction is whether special non-Portland or lean-Portland cements are required to ensure the long-term integrity of CO2-injection wells. If so, what does that imply for all the pre-existing wells in the storage area? Much of the early work on this subject has been contradictory. Another paper here describes the industry’s efforts to establish the potential leak paths and to prescribe appropriate construction techniques.

Using simple, tubing-sized monobore completions has proved an effective and efficient development strategy for complex multilayer reservoirs. The simplicity and reliability of the wireline tools we run in these small monobores are critical. John Lofton, one of Chevron’s drilling-engineering advisors, was intrigued by the novel, field-tested design evident in the retrievable lock mandrel described in another paper highlighted here. Retrievable tools embodying such features may provide improved reliability for slim monobore completions in hostile environments.

Well Construction additional reading available at OnePetro: www.onepetro.org

SPE 125642 • “Optimizing Openhole-Completion Techniques for Horizontal Foam-Drilled Wells” by Dave Allison, SPE, Halliburton, et al.

SPE 128226 • “Self-Healing Cement System—A Step Forward in Reducing Long-Term Environmental Impact” by S. Le Roy-Delage, SPE, Schlumberger, et al.

SPE 126226 • “Effective Zonal Isolation for CO2-Sequestration Wells” by R.E. Sweatman, SPE, Halliburton, et al.
Comments: Looking Ahead (May 2011)
Authors: Donnelly John
Published: February 2015

Editor's column

Top executives from an operator, service company, drilling contractor, and financial services firm spoke recently in Houston about the short- and mid-term outlook for the oil and gas industry. They agreed that the industry is undergoing significant changes as it transitions to new market structures amid increased advanced technology demand. 

Oil and natural gas prices should continue their current trend, with oil prices rising and gas prices under pressure from ample supply, said Marshall Adkins, director of energy research and managing director of equity research at Raymond James & Associates. He spoke at the Decision Strategies’ industry forum, a widely attended occasional gathering in Houston. Several factors will continue to contribute to higher oil prices over the next five years, he said, such as Middle East instability, a leveling off of non-OPEC production growth, the impact of the US Gulf of Mexico drilling moratorium, rising demand in China, and questions about the extent of OPEC’s production capacity.

The shale boom in the US is weighing on gas prices and, despite those low prices, the economics of gas drilling remain solid, Adkins said. US well productivity is up five to 10 times over the past several years, as advanced technology in shale formations has led to efficiencies. The US gas supply is projected to rise 7.5% this year and another 6% in 2012.

Robert Parker, executive chairman of Parker Drilling, agreed that the drilling moratorium in the US Gulf of Mexico along with the emergence of shale production has greatly altered the short-term supply outlook, and contributed to the divergence in oil and natural gas prices. A real wild card in any future global supply/demand outlook is the growing political instability in some of the larger producing countries, he said.

Notable will be how the US shale boom translates to other countries—infrastructure hurdles may limit production in some countries and shale oil production may eventually prove more prolific than shale gas. China and Argentina have strong shale potential and, in the Middle East, Saudi Arabia is a good bet.

Over the next several years, service companies, international oil companies (IOCs), and national oil companies (NOCs) will continue to adapt to a changing industry landscape. Several market forces are combining to change expectations for service companies, said Chad Deaton, chairman and chief executive officer of Baker Hughes. Growing hydrocarbon demand, the increasing importance of NOCs, the need for advancements in technology, and the increased importance of deepwater production and in maximizing recovery factors have broadened the scope for the service sector in operations projects. “The oil and gas industry is one place where technology really drives economics,” he said.
Can the Oil and Gas Industry Live Up to Today's Dynamics?
Authors: Al-Khalifa Abdul-Jaleel
Published: February 2015

Guest editorial

The continual change in Middle Eastern dynamics will have a profound impact on the oil and gas industry. Brent crude spiked when events escalated in Libya. The panic is about security of supply rather than space capacity, considering its abundance in the current oil markets. In other words, the market doubts that the current pro-customer oil policy in terms of pricing and production can be maintained going forward.

Changes in the 1960s brought OPEC into existence and changes in the 1970s delivered higher oil prices. Most importantly, these changes shifted global oil leadership from international oil companies (IOCs) to national oil companies (NOCs). So, how will the oil and gas industry adjust and reshape under today’s dynamics?

Historically, the oil and gas industry has had a narrow focus on the bottom line of creating value for shareholders. The shareholder is the government for NOCs while it is public investors for IOCs. Both strive to maximize financial earnings while delivering cost-effective performance applying state-of-the art technologies. While NOCs consider government’s responsibility to meet community needs such as job creation and sustainable growth, IOCs have focused on corporate social responsibility aimed at improving their public image. This “profit-only” business model, however, has started to fail, especially in the Middle East.

One can argue that one of the catalysts of recent Middle Eastern change is the poor standard of living in large local communities, while billions of dollars accumulate in the hands of business dealers. Many held the wrong belief that such business pockets could ensure stability and a secure supply of energy at the expense of the community at large. It was further exacerbated by companies focusing on their core business while outsourcing utilities, food catering, medical, IT, and other services. As such, companies have laid off or retired thousands of national employees, leaving room to employ nonlocal employees at cheaper rates. This has severely shrunk the value of the oil and gas industry in the eyes of some local communities.

The industry has also failed, most of the time, to build a complete chain of industrial and services support that provide job opportunities and circulate liquidity into the local economy. It is devastating in some cases when operations have to be halted to wait for a service hand to fly overseas to service tools and facilities. Billions of dollars worth of contracts to build new oil and gas facilities are also being awarded to international contractors. Both detailed engineering and procurement are sourced abroad. Furthermore, at the construction stage, the contractors normally fly in thousands of cheap nonlocal labor. While Houston is the oil capital in the Western Hemisphere, the Middle East, home to two-thirds of global reserves, does not have an energy capital yet. This only speaks for the industry’s narrow focus and failure to stimulate local industrial support.
Oil and Gas: Into the Cloud?
Authors: Feblowitz Jill
Published: February 2015

Management

Anyone who has watched television lately has seen commercials about amazing things being accomplished in the “cloud.” Advertisements are focused on what the typical consumer can do, such as sharing and editing photos, but benefits of the cloud—lower information technology (IT) costs, less complexity, and speed to launch—have been touted for business as well. The oil and gas industry has been on the forefront of adopting emerging technologies such as high-performance computing. The industry is knowledge intensive and is even experimenting with social networking. The question is whether the industry, given its global nature, need for security, and existing legacy infrastructure, will take to the cloud.

IDC Energy Insights defines cloud services as business and consumer products, services, and solutions delivered and consumed in real time over the Internet. The public cloud is a deployment model where the cloud is open to a largely unrestricted universe of potential users. In fact, the public cloud has been a part of the IT landscape for several years, mainly in the form of software as a service. A good example is salesforce. com, which is designed for specific purposes, but not for a single enterprise. Public cloud includes but goes beyond software as a service to IT infrastructure or platform as a service. The private cloud is designed for restricted access to a single enterprise (or extended enterprise). A hybrid cloud combines a private cloud with the use of public cloud, especially when internal private cloud resources are strained. Fig. 1 displays the key attributes of the cloud.

The cloud services model, by leveraging all eight of these attributes together, makes business and consumer cloud services easier and cheaper—and often better—to consume than through traditional delivery modes. These attributes are lower costs (for customers and suppliers), speed and simplification of access, speed and fine-tuning provisioning (in line with true demand/usage), greatly increasing the number and variety of available services (thanks to lower development and deployment costs and standards), and improving the potential to integrate.

Despite the popularity of the cloud in some applications, cloud computing has still not aggressively penetrated the oil and gas industry relative to the pace of adoption in other industries. According to IDC’s 2010 Vertical Group Survey, 10.3% of oil and gas companies are currently using or implementing cloud computing and 7% have cloud computing on their technology road map (Fig. 2). Forty-two percent of the companies that said they would use the cloud in 2010 were spending less than 5% of their IT budget on cloud.
Carbon Capture and Storage: A Mixed Review
Authors: Beckwith Robin
Published: February 2015

The overall tone of the report, titled “The Global Status of Carbon Capture and Storage (CCS): 2010,” released in March by the Global CCS Institute, is cautiously optimistic. “The global commitment to CCS remains strong,” according to the findings of the Australia-based institute, whose 287 members include major businesses, research organizations, and governments of top emitters, led by China, the US, Russia, and India.

The report states that well over 200 CCS projects were active or planned worldwide at the end of 2010, a net rise of 26 from 2009. Of these, 77 are large-scale integrated projects at various stages of development. North America, Europe, and Australia are home to 87% of all projects, despite the largest global growth in energy usage—a major driver of human-generated CO2 release—expected outside these continents over the next few decades.

The report cautions that “governments and industry are still in the early stages of implementing international programs to shorten the time-frame for the commercial deployment of CCS.” The current phase, likely to last more than a decade, focuses on demonstration programs that develop and improve capture applications and that prove safe and secure long-term CO2 storage.

Despite major efforts like the EU Emissions Trading System, controlling or curtailing the release of CO2 remains a relatively low priority on a global basis. Nonetheless, CCS project development is currently largely being driven by government incentives across the globe. According to George J. Koperna Jr., vice president, Advanced Energy Resources, “The role of government in energizing the industry is terribly important.” The report cites as much as USD 40 billion in government funding that could be available to support the development of CCS demonstration projects over this decade.

The Goal and Today’s Progress

The Intergovernmental Panel on Climate Change estimates the world’s average surface temperature will increase between 1.8°C and 4.0°C in the coming century. According to the International Energy Agency (IEA), around 20% of the total greenhouse gas emission reductions necessary to help mitigate this increase by 2050 can be achieved through CCS.
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.
New Approach to Deepwater-Drilling-Data Analysis Enhances Real-Time Capabilities
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 146624, ’A New Approach to Deepwater Drilling Data Analysis Offers Enhanced Real Time Capabilities in a Post Macondo World,’ by John F. Greve, SPE, Chevron Deepwater Gulf of Mexico Business Unit, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed.

Deepwater drilling activity in the Gulf of Mexico is no longer a given in the aftermath of the BP Macondo blowout. The new and ever-evolving process to apply for drilling permits and operate now greatly depends on thorough real-time monitoring of pertinent surface and downhole data. A new method for loading and analyzing live time and depth data showed merit during 2010 trials on two deepwater wells, one offshore eastern Canada and the other offshore west of the Shetland Islands. Rapid data access and standardized visualization of high-resolution time, depth, and survey data are vital to ensure that the occasional well-control event does not become today’s worldwide news headline.

Background—Real-Time Data Collection

The Wellbore Information Transfer Standard Markup Language (WITSML) well-data exchange protocol introduced in the mid-1990s continues to gain popularity as a standardized means to deliver drilling and logging data to the client operator. An increasing number of software programs are offering WITSML links to load depth-based data into programs for petrophysical analysis, pore-pressure estimation, and 3D visualization of well logs vs. seismic data. For roughly a decade, large service companies have offered Web-based viewing of drilling-gauge displays and real-time depth-based data. Even though Internet access to WITSML data has been available to client operators, little benefit has been derived from the time-based data because of inherent limitations of depth-focused Web-based viewers. A new vendor-neutral WITSML-based data viewer capable of easily connecting to multiple WITSML vendors combines real-time synchronous depth and time viewing of drilling, logging-while-drilling (LWD), and mud-logging data in a variety of graphical displays.

Historical Perspective on Collection of Time-Based Drilling Data

For many decades, time-based drilling data have been recorded with mechanical devices. Special 24-hour multiscale paper forms were loaded on a cylindrical drum every day. Because the chart was under a protective lid and sometimes covered by dirt and mud, it was considered more of a midnight chart-replacement chore for a roughneck than a useful tool. The charts rarely made it to the operator’s office and were often lost or thrown out.