bluuebunny/crossref_metadata_2025 huggingface dataset:
Insight Into Integrated Reservoir Management Using a Top-Down Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 132621, ’New Insight Into Integrated Reservoir Management Using a Top- Down, Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field in the Middle East,’ by Amirmasoud Kalantari- Dahaghi, Shahab D. Mohaghegh, and Yasaman Khazaeni, SPE, West Virginia University, prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed.

Top-down intelligent reservoir modeling (TDIRM) integrates reservoir-engineering analytical techniques with artificial intelligence and data mining to arrive at an empirical, cohesive, and spatiotemporally calibrated full-field model. The model is used to predict reservoir performance to recommend field-development strategies.    

Introduction

TDIRM attempts to provide insight into fluid flow in the reservoir by starting with field measurements such as well-production history and well logs. Other data such as core analysis, well tests, and seismic can be used to increase model accuracy. Although not intended as a substitute for conventional reservoir simulation of large complex fields, this approach to reservoir modeling and management can be used as an alternative to traditional reservoir simulation and modeling for cases in which performing conventional modeling is cost and manpower prohibitive. If a conventional model already exists, TDIRM may complement the conventional technique with an independent assessment of the reservoir/well data to optimize development-strategy and recovery enhancement.

In this study, TDIRM was performed on a giant complex oil field in the Middle East that has produced for a half-century. The reservoir has produced under natural depletion, with a strong waterdrive maintaining reservoir energy. The formation is a complex mix of clastics and carbonates of variable reservoir quality. This prolific reservoir has highly complex flow behavior.

Methodology

TDIRM uses accepted reservoir-engineering techniques such as decline-curve analysis, type-curve matching, (single-well) production-history matching, volumetric-reserves estimation, and calculation of recovery factors. These analyses are performed on individual wells. By use of statistical techniques, multiple production indicators [i.e., first 3-, 6-, and 9-month cumulative production and the 1-, 3-, 5-, and 10-year cumulative oil, gas, and water production and gas/oil ratio (GOR) and water cut] are calculated. To model the behavior of nondeclining-production characteristics such as GOR and water cut, intelligent decline-curve analysis is performed on GOR for which a negative decline is normal behavior. Intelligent decline-curve analysis is specific to TDIRM, and it is performed by use of an adaptive time-series-modeling technique that trains itself with existing data and predicts system behavior for a specific length of time into the future.
The Performance of Mud Motors With Two Different Bent Housings
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 125858, ’The Performance of Mud Motors With Two Different Bent Housing on Drilling a Lateral Section of Horizontal Wells in North Dakota,’ by Andy Syahputra, SPE, Bill Blaschke, and Jerry Hudson, SPE, Halliburton, originally prepared for the 2009 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Manama, Bahrain, 26-28 October. The paper has not been peer reviewed.

Drilling across two sections in a horizontal well in the Middle Bakken formation of North Dakota offers challenges and opportunities for improved well-construction performance. The wells in this area were drilled with three different hole sections after setting the 16-in. conductor at 60 ft. The lesson learned on three offset wells in this area found that a bend setting of 1.15° has contributed to reduce tortuous well paths, controlled dogleg severity, and stayed in a very tight target interval while drilling the lateral section of 10,000 ft along the hole. 

Introduction

Many operators are finding success drilling horizontal wells to develop the Middle Bakken in the Williston basin, which is relatively stable tectonically as compared with other intracratonic sections. The Bakken formation comprises the lower, upper, and middle members. The middle member is the target of the current development and typically consists of silty sand-stone and very-fine-grained sandstone, which is very calcareous and slightly dolomitic in the zones with the best oil and gas shows. The full-length paper focuses on drilling and the performance of mud motors with two different bent housings on three different wells in North Dakota.

Discussion

The bent housing tilts the axis of the bit relative to the axis of the hole. Significant bit side force is achieved for a relatively small bit offset. This allows the bit to build inclination and/or change the hole direction when the rotary-table topdrive is locked and to drill straight ahead when the drillstring is being rotated. The number of round trips thus is reduced dramatically, provided that the correct bit [polycrystalline-diamond-compact (PDC) bit of six-bladed aggressive designs with durable cutting structure] and bottomhole assembly (BHA) are chosen. The BHA is provided with vibration tools with sufficient weight to be run to the shoe and drill to section total depth (TD) in slide or rotating mode of drilling.

The surface-adjustable bent housing allows an incremental adjustment of the bend in the motor from 0 to approximately 3°. This changes the magnitude of the side force generated at the bit while slide drilling and, as such, the achievable build and turn rates. As the bent-housing offset angle is increased, bit side force increases and it becomes more difficult to slide. In the rotary mode, it becomes more difficult to rotate.
Comments: The Prize, Updated
Authors: Donnelly John
Published: February 2015

Editor's column

The history of the energy industry is a study in technical innovation, entrepreneurs, political figures, and how singular decisions changed not only the oil and gas industry, but also the world at large. 

That history is captured particularly well in the writings of Daniel Yergin, chairman of IHS Cambridge Energy Research Associates. He recently published a sequel to The Prize: The Epic Quest for Oil, Money, and Power, which is titled The Quest: Energy, Security, and the Remaking of the Modern World. Published in 1991, The Prize told the story of the history of oil—the technologies, people, and politics that changed the modern world. The new book tells how the current modern energy world came to be and how it might look different in the future.

Much has happened since the first book was written—the conclusion of the Gulf War, the collapse of the Soviet Union, the wave of oil industry consolidation in the late 1990s, and the sharp growth in Chinese and other developing countries’ energy demand. Energy was greatly affected by or central to all of these events and will continue to play a leading role on the world stage, writes Yergin, who addresses several significant contemporary issues in the book:

Peak oil theory is nothing new and this is the fifth time in modern history that there has been widespread fear that the world is running out of oil. The first time was in the 1880s when oil production was primarily concentrated in the US state of Pennsylvania. But the theory greatly discounts the industry’s ability to innovate and invest as it finds new and better ways to develop resources.

The growth in shale gas production, and the use of technologies such as hydraulic fracturing and horizontal drilling, are one of the industry’s most significant advances and have permanently changed the global gas landscape in a remarkably short time. He believes the industry will continue to innovate and make progress to try to satisfy some of the public concerns about hydraulic fracturing.

One natural or geopolitical event can change the energy industry overnight. An example is the nuclear power accident at Fukushima in Japan earlier this year after a tsunami hit the country. That may have ended thoughts of a nuclear power renaissance meeting the needs of a growing global demand for electricity.

Concerns about energy supply, and energy demand, will continue to drive geopolitical discussion, including how nations can become energy secure from natural disasters and cyber security threats. And political discussion of climate change could significantly affect the world’s future energy mix.

Sometimes overlooked, he writes, is the promise of energy efficiency, which he believes “has the potential to have the biggest impact of all” in satisfying future energy demand. Both the industry and environmental groups agree that the issue is critical and it may become the “first fuel” in any future discussion of balancing global demand with climate change.
Cathodic Protection Custom Retrofit Ensures Integrity of Subsea Manifold
Authors: McKinnell Gordon
Published: February 2015

Technology Update

Preventing corrosion on subsea architecture is critical for operators in their effort to maintain an asset’s integrity and extend field life. Failure to do so can lead to unscheduled maintenance, deferred production, and possible punitive costs should environmental damage occur.

Cathodic protection (CP) can be a cost-effective means of preventing corrosion and should be considered as part of any long-term integrity management strategy. With accurate datasets, it is possible to predict the most likely future state of a structure’s integrity, which aids in planning preventive measures.

When a CP system reaches the end of its design life, a retrofit system is often required to ensure that an asset’s integrity is not compromised. A recent example was a custom retrofit system designed, engineered, and supplied by Stork Technical Services to Marathon Oil for the cathodic protection of its West Brae field subsea manifold in the UK North Sea. The system needed repair and the measures had to be carried out without causing a major disruption to oil and gas production.

Developing a CP System

A CP system comprises an anticorrosion coating and either sacrificial anodes, the most commonly used subsea, or impressed current anodes with a power unit to drive them. A system is designed to operate for a fixed period, usually between 10 and 30 years. However, the extension of field life and addition of facilities to an asset can compromise the original design by increasing the surface area and members, which may reduce the effectiveness of the anodes installed as part of the original design.

The aim of a CP system is to polarize a structure as quickly as possible and maintain the optimum protection for the design life. When depolarization begins, the system has reached the end of its design life. Either a retrofit system is installed or the structure is allowed to operate in an underprotected state. Underprotection may be allowed because installing a new system may overprotect another connected component, and that could create other failure risks with a higher impact.

Overprotection and the materials used must be evaluated in the CP system design. Hydrogen blistering, cracking, and embrittlement can occur when a system is overprotected. Susceptibility to such damage depends on the structure and hardness of the metal in question. For example, super duplex steels are the metals most commonly affected by overprotection hazards in subsea oil and gas applications. As the supply of a high current at low voltage is central to CP, a proper consideration of the equipment and its use is essential to ensure that repeatability, historical traceability, and accurate measurement in the range of <10 mV are achieved.
Ranking Production Potential From Key Geological Drivers - Bakken Case Study
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14733, ’Ranking Production Potential Based on Key Geological Drivers - Bakken Case Study,’ by Robin S. Pilcher, Jessica McDonough Ciosek, Kelsey McArthur, John Hohman, and Peter J. Schmitz, SPE, Hess Corporation, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November 2011. The paper has not been peer reviewed. Conference rescheduled to 7-9 February 2012.

The Bakken play is a complex, low-porosity/-permeability system with variable source maturity, reservoir pressure and temperature, and fluid type. Target reservoirs are thin and variably affected by subtle structure, faults, or natural fractures. Many horizontal wells with multistage completions will be required to develop the Bakken play. A method is presented to assess the underlying production potential of the reservoirs on the basis of key geological drivers. With an extensive well-log database, petrophysical uncertainty can be addressed and stock-tank oil originally in place (STOOIP) can be calculated and mapped.   

Bakken Play

The Williston basin oil province was discovered in 1951, and the Bakken formation was formally described in 1953. First oil was produced from the play in the same year. However, most of the early vertical wells, with the exception of those in the heavily fractured Antelope field, proved uneconomical to produce. The Bakken play is a hybrid of conventional (although tight) reservoirs and continuous resource plays that require development by use of closely spaced horizontal wells and multistage-hydraulic-fracture completions.

Production Potential and Ranking Goals

Regional ranking of future drilling locations is inherently challenging because of the many geological factors involved, and is complicated further by the influence of drilling, completion, and production operations. Traditional ranking schemes try to describe the relative potential of acreage and provide empirical support for the ranking by correlating the resulting rank to some measure of production performance. The production measure may be either a cumulative volume over a certain time frame (e.g., 90-day cumulative production) or a modeled estimated ultimate recovery (EUR) for the life of the well. Horizontal wells and multistage completions are a relatively new technology in the basin, with short production histories. As a result, use of actual production or actual production normalized per hydraulic-fracture stage is preferred because EUR introduces more assumptions and unknowns. A minimum period of 90 days of production was used in this study. Calibrating the regional-ranking predictions to actual production data will, inevitably, prove impossible to match past performance because the producing wells are subject to rapidly evolving technology and to variations in drilling, completion, production history, and operatorship.
Twelve Steps To Engineering Safe Oil and Gas Facilities
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 141974, ’Twelve Steps To Engineering Safe Oil and Gas Facilities,’ by J.E. Johnstone, SPE, and J.V. Curfew, SPE, Contek Solutions, prepared for the 2011 SPE Americas E&P Health, Safety, Security, and Environmental Conference, Houston, 21-23 March 2011. The paper has not been peer reviewed.

The safety of an onshore facility is a function of how safely the facility was designed. People are injured, and sometimes killed, when explosions, fires, and toxic-gas releases occur at oil- and gas-producing facilities that were designed without including measures that could have prevented such incidents. The safety of people and equipment must be considered and included along every step in the engineering and design of oil and gas facilities.   

Introduction

Many wellsites, tank batteries, and production facilities are at risk because of design or installation errors. These errors may have occurred when the facility was built or because the facility had been enlarged or upgraded through the years. Lack of proper engineering design can lead to equipment failure, lost production, human injury, or harm to the environment. Design and equipment selection will affect the safety and health of perhaps generations of workers who will be working on and near the equipment.

Safe Facilities

When designing a facility for a discovery, companies may choose to make sure that all facilities are designed and operated in accordance with standards and good engineering practices and with regulatory requirements. The other choice is to make decisions that inevitably lead to equipment failure, personnel injuries, and environmental damage.

The full-length paper details 12 key areas for facility designers and engineers to include when designing facilities for safe operation. The following is a short summary of these areas that should enable designing and building safe facilities that reduce the risk of major incidents. See the full-length paper for citing of applicable recommended practices, codes, and standards.

Design-Standards Policy. Each producing company, no matter how small, must implement a policy regarding the use of industry design standards that can be articulated to the production and operations groups regarding how surface facilities should be built. Setting a design policy to use industry standards will reduce the risk of injury to personnel or the occurrence of an environmental event at the facility. Most industry standards and regulations were developed in response to safety-related events and continually evolve to incorporate lessons learned from other safety-related events. Building a facility to industry standards provides the user with industry-accepted safety criteria.
Performance Standards for Safety-Critical Elements - Are We Doing Enough?
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140727, ’Performance Standards for Safety-Critical Elements - Are We Doing Enough?,’ by Rahul Dhar, SPE, Abbott Risk Consulting, prepared for the 2011 SPE European Conference on Health, Safety, and Environmental in Oil and Gas Exploration and Production, Vienna, Austria, 22-24 February. The paper has not been peer reviewed.

Safety-critical-element (SCE) life-cycle management involves identifying major accident hazards (MAHs); selecting SCEs by identifying structures and plants that can cause, contribute to, prevent, or help recover from a major accident event; and developing the performance standards (PSs) for the identified SCEs. It also involves alignment of maintenance routines, inspection and testing, performance history, and other tasks required to maintain the SCE in a suitable condition. Continual monitoring of the status of the hardware barriers and performance-assurance tasks enables the operating staff and management to analyze the ongoing conformance of the SCEs by use of their PSs.

Introduction

Although much has been achieved by the oil and gas industry in terms of reducing risk to personnel, the environment, and assets by use of SCEs and PSs, major accidents continue to happen. The concepts of SCEs and PSs have been presented to prevent or reduce the number of major accidents. MAHs or major events are defined differently in different parts of the world, but have a common underlying theme in that they can cause harm to multiple people, cause substantial environmental damage, or cause expensive damage to the assets. The author highlighted three headline events in the full-length paper to promote thought on the topic: the Montara wellhead-platform blowout in 2009, the Deepwater Horizon accident in 2010, and the Ocean Ranger semisubmersible sinking in 1982. These events suggest that, perhaps, not enough is being done and, therefore, more effort must be made to reduce the number of major accident events or possibly prevent them.

Need for SCEs

Reliable Design and Engineering (Good Practices). SCEs and their PSs ensure that new installations or designs con-form to current good practice and reliable engineering. For new installations, it is extremely important that their design be robust and that they be able to perform their intended functions throughout their design life.

Aging Installations. As current oil and gas installations get older, it is important to ensure that they remain capable of performing intended functions in the safest manner possible to avoid harm to personnel or to the environment. SCEs and their life-cycle-management processes help achieve these goals and reduce or prevent the major accidents.
Innovation: Well Evaluation Innovation
Authors: Imomoh Egbert
Published: February 2015

President's column

From the earliest drilling operations, the need for operators to see the penetrated formation was paramount, in their minds. They needed to distinguish not only the rock properties but also their content and deliverability. The first electrical well-logging operation took place in 1927 after many years of successful experiments with surface resistivity measurements by Conrad and Marcel Schlumberger. The operation, in France, took more than 5 hours to record the resistivity over an interval of 140 m from a depth of 279 m. Henri Doll, one of the three wellsite engineers at the operation, wrote “We began making our measurements. Someone had to unplug the connector, someone else turned the winch. Someone had to run to the rig floor to look at the counter on the sleeve. I wrote down the measurements on a pad together with the depth... Then it was unplugged, rolled up one meter at a time.” (Schlumberger 2007)

Four years later the spontaneous potential of a formation could be measured, thus allowing permeable rock to be distinguished from nonpermeable rock. These measurements are far from the sophistication of today, but for me this demonstrates how seemingly simple innovations have made such a tremendous impact on our industry. The equipment currently used for logging wells and capturing and transmitting data is a far departure from the rudimentary operation that took place 85 years ago. The point is that the industry saw the need for the nascent technology, and its use all over the world allowed not only the measurements around a wellbore, but also provided results with which the geologists could match well correlations, map a field, and obtain the structure of the horizons.

Innovative ideas emerging in other industries began to have an impact on our well evaluation operations. The development of electronics in the 1930s led to a number of new developments in logging operations. The miniaturization of rugged circuit boards and components led to new tools that suffered less damage, which in turn reduced lost time during rig operations. The introduction of computers permitted the capture and interpretation of data. Transmission of data from wellsite to office has been enhanced by innovation in the telecommunications world, and remote logging operations have been enhanced by the use of satellite and other forms of telecommunication. Modern technology now permits multilocation access to live data from rig sites, thus permitting real-time management of situations that leads to speedy interpretation. When I worked on a wellsite in the late 1960s, logs were developed on site and physically moved by road, boat, or helicopter to the office-based engineers for evaluation; subsequently, further instruction was transmitted back to the wellsite by unreliable high-frequency radio. I can still recall the smell of ammonia used for printing those logs. I recently mentioned this to a few young engineers and the blank look on their face made me feel as if I was from the Stone Age, but that is what innovation has done in our industry.
UK's Gas Heritage May Become Its Legacy
Authors: Pickering Tom
Published: February 2015

Guest editorial

The United Kingdom is attempting to emulate the unconventional gas bonanza that has transformed the United States from having an energy industry that was in its “sunset” era to a nation rich in energy resources. The UK, which sits on significant shale reserves, wants to become part of this game-changing industry, viewing it as an exciting opportunity as it looks to revolutionize the energy landscape for the next generation.

By its very nature, the country has a dense population with a rural and agricultural countryside and, though it boasts a huge offshore infrastructure, lacks onshore support and infrastructure. Add the obstacles of environmental concerns, a need to build awareness, and a cautious political uptake, it could take 2 more decades before investment decisions by industry could turn concern about the value of unconventionals into certainty.

Unconventional gas has a particular production profile and economics; consequently, operators must be able to drill, produce, and build facilities within tight cost parameters, which can be marginal. The underpinning culture and supply chain in the North Sea is not as conducive to that development. Therefore, it is crucial that there is a fundamental shift in the approach toward equipment, infrastructure, service industry support, and onshore and community stakeholder engagement.

Historically, the UK and Europe have engineered large gas deposits offshore and deployed pipeline and transport facilities to handle the delivery of large volumes of conventional high-pressure gas to market. Therefore, the existing base infrastructure presents a costly challenge for unconventional operators seeking entry into the industry. It is also true that where there has been the opportunity to turn gas into electricity by generation, both the generating and distribution network is geared to high-voltage, coal-fired power stations and nuclear electricity generation.

The story now centers on the indigenous supply of natural gas. Five years ago, it looked as though the world might have only 50 to 60 years’ worth of gas. However, by some estimates, shale and other unconventional gas finds have increased that life span to 200 years or more.

The successful exploration, appraisal, and development of UK onshore unconventional resources have the potential to provide a significant contribution to the hydrocarbon component of the nation’s balanced portfolio and strategy.

Despite the technical, environmental, financial, and political challenges, the UK and other European countries, are taking the first tentative steps to establish the development of shale and coalbed methane. Coring activity is now under way in reservoirs to ascertain the presence of gas, geological permeability, and the natural fracture system within the rock, and that presents an encouraging commercial opportunity.
Subsea Corrosion/Erosion Monitoring
Authors: JPT staff _
Published: February 2015

Young Technology Showcase

Detection and monitoring are important prognostic means in preserving material integrity and reducing the life cycle cost of industrial infrastructure, ships, aircraft, ground vehicles, pipelines, oil installations, etc. Having better control of your infrastructure’s condition will enable you to optimize profitability and lower maintenance cost. Hence, monitoring an oil and gas pipeline will not only work as a precaution, but can also give information on when replacement or repair is necessary, thereby maximizing uptime. There is a huge need for reliable monitoring of pipe wall thickness, both topside and subsea. Even in topside applications, the conditions of operation may be hostile and problems such as large temperature variations, lack of space, fluid loading issues, and a host of other factors make development of such a tool a challenging task. Going subsea makes it even more demanding when you have to take into account factors such as high pressure and limited access.

Over the past years, ClampOn has offered a corrosion/erosion monitor (CEM) for topside installations. Major advantages of this technology are its noninvasiveness, high repeatability, lack of any transducer movement, and high coverage. The measurement principle is based on dispersion of ultrasonic-guided wave modes, and by using electromagnetism, these waves are transmitted along the pipe wall without the sensor being in direct contact with the metallic surface. This makes it an excellent candidate for subsea use. It is installed on the outer pipe wall to produce real-time wall thickness information, not as a spot measurement, but as a unique average path wall thickness. With several successful installations topside, the ClampOn CEM has also found applications subsea, with the first unit installed at 2300 m in the Gulf of Mexico in February and another 10 units to follow in the future.

Corrosion and erosion in subsea installations is detected by several methods. In topside applications, the alternatives are both more reliable and many. In subsea applications, the more hostile environment makes the detection of corrosion and erosion a more challenging task. Piggable pipelines are normally inspected at regular intervals and tracking of pipeline integrity is in general not problematic. Some unpiggable pipelines can be inspected using cable-operated tools, but such inspections are expensive and may require a shutdown of production. Subsea production templates, flow jumpers, manifolds, and flow lines can today only be inspected by preinstallation of corrosion/erosion sensors or by use of sensors controlled by remotely operated vehicles (ROVs).
Keeping the Pipeline Full
Authors: Rassenfoss Stephen
Published: February 2015

Large infusions of money and new technology will be needed to fill the oil gathering systems in the West Siberian oil fields. The owner of this field, Salym Petroleum Development, hopes to increase the output of its fields using chemically enhanced oil recovery and by producing oil from the Bazhenov formation.

Russia Considers Its Unconventional Options

To search online for the story of how Russia became one of the world’s top oil producers, try the keywords “West Siberia.” For the future, try “Bazhenov.”

The Bazhenov is the source rock for the prolific West Siberian fields that still yield about two-thirds of Russia’s crude oil production nearly 50 years after the oldest of those fields went into production.

The formation covers an enormous area—conservative estimates put it at more than 1 million km2, which is 1.5 times as large as the US state of Texas. The low-end estimate of the total reserves in the Bazhenov by a national agency that estimates Russian resources in the ground, Rosnedra, is 182 billion bbl, according to Platts, an oil industry trade publication. The high end is double that total.

Now, some of the biggest oil companies in Russia, and the world, are trying to figure out how to convert that resource into reserves. Bazhenov wells have been drilled for decades, and have earned the formation a reputation for unpredictability.

The drive to take what has been learned about unconventional oil production in the US and use it in West Siberia was a key theme at the recent SPE Russian Oil & Gas Exploration and Production Technical Conference and Exhibition in Moscow. Another theme was the growing list of techniques being employed to extract more oil out of conventional formations: from using advanced seismic analysis, to new drilling and completion methods to tap unproductive formations, to enhanced oil recovery (EOR) using chemicals.

An example of all of the above is Salym Petroleum Development (SPD). The 50/50 joint venture between Shell and Gazpromneft, a Gazprom subsidiary, has been investigating the Bazhenov in its fields in West Siberia, where it has also been drilling hundreds of wells based on advanced seismic studies to reach unproduced zones. And it is testing chemical EOR.

Based on lab work and a single-well field test, using alkaline surfactant polymer (ASP) treatments could significantly increase its ultimate production, Simon Durkin, chief executive officer of SPD, said in an interview during the Russian conference. Using chemicals to free more of the oil from the formation and improve the sweep of a waterflood could add more than 100 million bbl of incremental production over 30 years, according to company estimates.
Who Drives E&P Innovation?
Authors: Perrons Robert K. , Donnelly John
Published: February 2015

Management

Few would argue that the upstream oil and gas industry has become more technology-intensive over the years. At the same time, the increasing costs and complexity of today’s exploration and production (E&P) technologies are making it increasingly difficult for any one company to support an aggressive research and development (R&D) agenda single-handedly. The coming together of these two evolutionary forces gives rise to important questions. How does innovation happen in the E&P industry? Specifically, what ideas and inputs flow from which parts of the industry’s value network, and where do these inputs go? And how do firms and organizations from different countries contribute differently to this process? This survey was designed to shed light on these issues.

Consisting of 23 questions, this survey asked respondents about several aspects of their business unit’s R&D and innovation-related activities. Much of the survey focused on the sources of knowledge they rely upon throughout their innovation activities. What sources of information, data, and knowledge are most important as they develop new technologies? This part of the survey was modeled after the Eurostat Community Innovation Survey, which has been used in more than 60 academic articles for measuring the knowledge inputs that go into innovation-related activities (Laursen and Salter (2005) and Cosh and Zhang (2011) are specific examples of research that have used this type of framework for analysis). The framework consists of 16 potential sources of knowledge (Table 4). Respondents were asked to identify the degree to which they had used each of the sources throughout the past 3 years, ranging from “not used” to “high use.”

The survey also asked for several measures of R&D output from their business unit, including the number of patents arising from technologies principally developed by their business unit in the past 3 years, the number of technologies deployed by their business unit in the past 3 years, and the number of radical innovations among these. All of these output measures were self-reported by the respondents. Respondents were informed before completing the survey, however, that their results would be made anonymous and aggregated with data from other respondents, thereby removing any incentive to distort their responses.

Respondents were asked at the end of the survey if they would object to being asked a few clarifying questions about their responses. Several said yes, and a handful of follow-up discussions were carried out to deepen an understanding of the survey results.
Unconventional Resources Headline SPE Annual Conference
Authors: Henni Abdelghani , Rassenfoss Stephen , Beckwith Robin , Dunnahoe Tayvis , Boschee Pam , Parshall Joel , Donnelly John
Published: February 2015

Conference review

Best practices in developing unconventional resources was one of the main themes during the 2012 SPE Annual Technical Conference and Exhibition (ATCE), held in San Antonio in October. The conference brought together 11,095 oil and gas professionals from around the world, making it among the top five highest attended ATCEs.

The technical program represented all six SPE technical disciplines with an expanded focus on the projects, facilities, and construction (PFC) discipline. New PFC sessions, including a special panel dinner on megaprojects, were part of SPE’s yearlong emphasis on the discipline.

Monday’s opening general session addressed the event’s unconventional theme with a panel of experts discussing the technological and financial challenges associated with unconventional oil and gas resources. David Hobbs, chief energy strategist at IHS CERA, moderated the panel that consisted of Mark Albers, senior vice president of ExxonMobil; Timothy Dove, president and chief operating officer of Pioneer Natural Resources; Steve Holditch, director of the Texas A&M Energy Institute; and David Lesar, chairman of the board, chief executive officer, and president of Halliburton.

The rush to develop unconventional resources has been an unstructured, chaotic, often costly learning experience that is still in its early days, according to the panelists. Ultimately, the opportunity to develop resources once seen as impossible to produce is likely to be an industry-changing experience.

“It is about transforming an entire industry to operating in a new and dynamic environment,” said Mohammed Al-Qahtani, vice president of petroleum engineering at Saudi Aramco, during his introduction to the panel discussion on making unconventional resources conventional.

The changes they described range from how engineers develop fields to what they say about what they do.

The furor over fracturing has forced the industry to address critics who say the technique is a threat to water supplies. “We need to educate the public to the risks and how we are managing them,” Albers said.

The push to maximize profits and minimize costs has altered relationships as companies consider whether the traditional division of labor makes sense.

“It is a business free-for-all,” with oil companies buying and running rigs and service companies taking on reserves, said Lesar.

The US has become a magnet for exploration and production professionals from around the world because of the boom in unconventional resources, said Holditch. While the United States is seen as a university for those looking to learn shale, much remains to be learned. A favorite phrase among the panelists was, “It is early days.”
Correlating the Returns of Oil-Producing Projects Realistically
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150909, ’How To Measure the Correlation Between Return of Oil-Production Projects Realistically,’ by G.A. Costa Lima, SPE, A.T. Gaspar Ravagnani, SPE, and D.J. Schiozer, SPE, Unicamp, prepared for the 2012 North Africa Technical Conference and Exhibition, Cairo, 20-22 February. The paper has not been peer reviewed.

Portfolio theory has been an important tool for economic-risk management. There are only three input parameters: mean return, standard deviation of return, and correlation between pairs of such things as assets, projects, and prospects. Although the model is simple, a problem with it is estimating the correlation because there are no historical data. Alternatively, correlation on return of projects is assumed subjective (typically 70%), but with this model it can be estimated in a much more sound way. Results indicate that the main determinants of correlation are fixed cost, variable cost, and oil quality. With this information, managers can select best portfolios (e.g., by means of farm in and farm out) to create value for stakeholders considering means, risk, and possible benefits from diversification.

Introduction

Often, decision makers must manage portfolios containing many projects, including exploration, development, production, and decommissioning. The life span of these portfolios is similar to that of the company, possibly several decades. Most company portfolios are updated yearly. In this process, the return to stakeholders depends on such factors as the skill of decision makers to add and remove projects, performance of individual projects (and the synergistic interaction in terms of geologic features), operating infrastructure, and marketing conditions.

In portfolio management, decisions are made on the basis of the mean and standard deviation (risk) of the rate of return of investments. The risk depends on the standard deviation of each individual asset, correlation between pairs of assets, proportion of investment allocated in each asset, and the number of assets in the portfolio. Of these variables, only the risk of the individual asset is beyond the manager’s control because it depends on variables such as oil production, operating cost, fiscal regime, reservoir conditions, and geologic aspects; therefore, it is called systematic risk.

The use of portfolio theory to solve real-world problems depends strongly on calculations/estimations of correlations. Therefore, the focus in this paper is on the methodology to estimate correlations between pairs of net present value (NPV) of oil projects.

Correlation vs. Diversification

Consider an oil company with an opportunity to construct a portfolio having two oil-production projects. Initially, professionals complete a traditional economic analysis at the project level to estimate mean and standard deviation of the NPV of each project. Results of this initial analysis are shown in Table 1.
Installation, Hookup, and Commission Phase of Ghana's Fast-Tracked Jubilee Project
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 23456, ’Jubilee Development Installation, Hookup, and Commissioning and Ready for Startup,’ by Laurent Culembourg, Kosmos Energy, Cory Weinbel, SPE, Anadarko Petroleum, Keith Mutimer, Tullow Oil, Frederic Chauvin, Technip, and Andrew McDonald, consultant, prepared for the 2012 Offshore Technology Conference, Houston, 30 April-3 May. The paper has not been peer reviewed.

The Jubilee Field Development, 60 km offshore Ghana, began Phase 1 production just 3.5 years after field discovery. Here is highlighted the successful execution of the in-country installation, hookup, and commissioning (IHUC) phase of the project in conjunction with operations readiness and assurance activities to bring the production system safely to an on-time ready-for-startup (RFSU) condition. Success was found through integration of a multipartner project team and the management of critical interfaces.

Introduction

The Jubilee partners, along with the Ghana National Petroleum Corporation (GNPC), decided to develop the field using a phased approach. The integrated project team (IPT) developed a plan to target just less than 300 million bbl in Phase 1 with a 17-well subsea system and a 120,000-BOPD floating production, storage, and offloading (FPSO) unit. Phase 1 was approved in Au-gust 2008, and first oil was achieved in November 2010.

The overall project schedule was aggressive, with critical path activities occurring primarily within the IHUC phase of the project.

Despite efforts to plan and meet the aggressive schedule, the IPT still encountered some significant challenges onshore and offshore Ghana during the IHUC phase. The key to resolving these issues successfully was linked with the execution strategy and the experienced team’s ability to develop a response plan and implement it successfully.

IHUC Planning, Organization, and Execution Strategy

The Jubilee Leadership Team (JLT) recognized that the IPT organization and interfaces with the unit operator needed to evolve with the progression of the project. As such, the development activities were divided into the following four phases, with governance models designed for each:

Phase 1—FPSO construction and subsea procurement

Phase 2—IHUC

Phase 3—Startup

Phase 4—Steady state

Contracting Strategy and Resources

A contracting strategy was put in place to favor IPT control over schedule imperatives with the following elements:

Selecting world-class contractors with records of delivering on-time projects with excellent engineering

Incentives for meeting, and penalties for failing to meet, critical milestones

Separating the scope of umbilical, riser, and flowline (URF) activities that could be performed off the critical path from those that had to be done on the critical path and negotiating different incentives/penalties for each
Guide to Borehole-Enlargement-Tool Selection
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142431, ’A Practical, Application-Based Guide to Borehole-Enlargement- Tool Selection,’ by J. McCarthy, SPE, J. Rebellon, SPE, S. Barton, SPE, and R. Rambhai, National Oilwell Varco, prepared for the 2011 Brazil Offshore Conference and Exhibition, Macae, Brazil, 14-17 June. The paper has not been peer reviewed.

Borehole enlargement (BHE) has become commonplace. Still, it can be very demanding from planning and execution points of view, particularly in deepwater basins. To address the needs of challenging applications, a variety of tools has been developed. The two primary BHE methods use either eccentric or concentric tools. Depending on the type of well that is being drilled and the formation characteristics, the engineer must choose the optimal bottomhole assembly (BHA) and drilling parameters for successful BHE. Understanding the application is critical in delivering a successful BHE operation.

Introduction

BHE technology has enabled exploiting complex and unconventional reservoirs. Heavier and larger casing strings are set at greater depths, allowing operators to obtain improved recovery rates from the reservoirs. Each application must be analyzed thoroughly to provide the best design. Proper selection of BHE technology is critical. Improper selection of BHE technology can lead to complete loss of the well.

For this paper, a BHE tool is one that can expand a borehole beyond the diameter at which it can pass through. Typically, this means creating a borehole larger than the inner diameter of the casing already in place. BHE tools are defined by their pass-through diameter and their expanded diameter, or drill size. BHE tools can pass through casing (or other restriction) to create a larger-diameter hole than the restriction and then can be retrieved safely from the well.

To select the appropriate BHE technology, the engineer must understand the intricacies of the application and configure the drilling system to provide the best results in an economical and safe manner. Several factors affect this selection, some of which are set before the operation begins. Factors such as economics, rig capabilities, borehole quality, and drive type or system used to drill the well must be reviewed during the selection process.

BHE Technology

Fig. 1 shows the two primary categories of BHE tools: eccentric and concentric. Tools can be placed in the drillstring at two locations (at the bit or up in the drillstring). A third category of tools, the hole opener, often is thought of as a BHE tool, but these tools cannot generate a borehole larger than the minimum restriction of a well, so they do not fit the definition used here. However, they are sometimes used in conjunction with BHE tools, as a secondary cutting structure to provide a solid platform for the BHE device.

Many hole-enlargement products are available, each of which fits a particular application. The simplest are the fixed-cutter designs.