bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Drilling Management (September 2012)
Authors: Cunha J.C.
Published: February 2015

Technology Focus

At the very beginning of my career, as a young drilling engineer in South America, I used to work in a company where, as far as drilling activity was concerned, we would do (almost) everything by ourselves. We had our own rig and everybody on the location was a company employee. We had our own mud technician, who would, with the help of almost everybody on site, mix the chemicals and prepare our own drilling fluid, sometimes with formulations being decided on the go, depending on the formations we would encounter or on the mechanical problems we faced. We had our own cement unit, and, of course, we would decide on the cement-job specifications and then mix and pump/displace our own cement slurry.

No, I am not bragging. This was not a good thing and, actually, I do not want the industry to ever return to that primitive stage. I am certain that, even for those simple wells, we positively could have done a better job if we had had the help of specialists in drilling fluids, cementing, directional drilling, geomechanics, and other areas. Additionally, we definitely would have had a more-reliable drilling rig if we were not performing the maintenance, welding, and repairs ourselves.

On the other hand, in today’s operational environment, with so many companies on board, so much expertise, so much equipment, and so many parameters to check and control, it may be a real challenge to have a smooth operation, where all pieces are placed in the right place at the right time. Managing such complex drilling operations requires, besides experienced managers, a very well-trained team. A flawless operation is a result of good management and careful planning. Integration of the many disciplines is a must. No one is there to do a single, isolated job. Everybody should be aware of each other’s tasks and responsibilities and of which role these play in achieving the final common objective. As in an orchestra, the final result will depend as much on a good conductor as on capable and integrated musicians. They may be playing different instruments, but they are playing the same music.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE 150422 Early Symptom Detection Based on Real-Time Evaluation of Downhole Conditions: Principles and Results From Several North Sea Drilling Operations by Eric Cayeux, SPE, IRIS, et al.

SPE 150201 Improving Management and Control of Drilling Operations With Artificial Intelligence by Giulio Gola, Institute for Energy Technology, et al.

SPE 150069 Real-Time Drilling Engineering: Hydraulics and T&D Modeling for Predictive Interpretation While Drilling by Ricardo Borjas, SPE, Schlumberger, et al.

SPE 149906 Advanced Predrill Simulations for Safer and More Cost-Effective Drilling by Dan Sui, Sintef Petroleum Research, et al.
Multidisciplinary Collaborative Concept Aids Challenging Deepwater Operations in Brazil
Authors: Wilson Adam
Published: February 2015

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 151186, ’Upgrading the Real-Time Drilling-Optimization Culture in Brazil's Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept,’ by Augusto Borella Hougaz, Danilo S. Gozzi, Isao Fujishima, and Klaus L. Vello, Petrobras, and Sandro Alves, Ian Thomson, Raul Krasuk, SPE, and Frank Buzzerio, Baker Hughes, prepared for the 2012 SPE/IADC Drilling Conference and Exhibition, San Diego, California, 6-8 March. The paper has not been peer reviewed.

In Brazil, deepwater well-construction activity has increased significantly since the first major presalt discovery in the Santos basin in 2006. The creation of a multidisciplinary drilling-optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole-drilling-dynamics measurement-while-drilling (MWD) tool changed the drilling-optimization concept in Brazil. This new optimization concept pioneered the remote (off-the-rig) downhole drilling-parameters surveillance in deepwater operations.

Introduction

A novel real-time optimization drilling service was implemented in 2008 with the major deepwater operator in Brazil in the Santos basin. Throughout the implementation and execution of the real-time optimization service, the importance of not only knowing where (wellbore placement) and what (formation evaluation) you are drilling but also how you are drilling, which is mainly driven by the integration between operator and service company, became apparent. After 3 years, it was clearly observed that the higher the integration between service company and operator was in a proactive and collaborative environment, the higher the drilling performance was. Today, in the deepwater Santos basin presalt environment, the real-time optimization drilling service is already part of the drilling program in almost every well, from the top hole section to the reservoir section.

Real-Time Drilling-Optimization Team

In 2008, to answer the “how” questions in the Santos basin, a new culture of real-time optimization arose with the concept of a multidisciplinary optimization team from the service company acting in collaboration with the major operator in Brazil in an integrated manner to achieve superior performance.

To accomplish effective remote and rigsite real-time drilling optimization, it is important to use a highly specialized downhole drilling-dynamics MWD tool that records and transmits real-time dynamics data (e.g., stick/slip, lateral vibration, whirl, and axial vibration) and downhole drilling parameters (e.g., weight on bit, torque, revolutions per minute, and bending moment), which allows for a better judgment of the down-hole conditions while drilling and better support for adjusting the surface drilling parameters to optimize operations, in a continuous feedback cycle (Fig. 1).
Creating a Common Safety Culture
Authors: Keiller Bob
Published: February 2015

Guest editorial

Most people who work in the oil and gas industry know what a “permit to work” is. A blue permit indicates that it covers “cold” work—work with no potential to create a naked flame, hot surface, spark, or explosion. Having a permit ensures that the job site is safe for the team to do its work, that the team understands the potential risks of the work it is planning to do, and that it agrees to put suitable controls in place.

I spoke recently at the Piper 25 Conference, a 3-day event held in Aberdeen to mark the 25th anniversary of the Piper Alpha disaster that killed 167 people on board the oil platform in the North Sea. On display at the conference was a copy of Cold Work Permit 23434. The tattered paper was found in the accommodation module that was recovered from the seabed. The permit was for the replacement of a relief valve on the B condensate pump. It was this work that was at the heart of the initial release and explosion when the operators tried to start the pump even though it was not ready. The rest, tragically, is history.

It begs an obvious question and a supplementary one: Could something similar happen again and, if so, can we do anything to reduce the chances of it happening?

The oil and gas industry has made huge advances in safety management over the past 25 years. The goal-setting regime, safety cases, and verification schemes have been hugely beneficial.

We have greater collaboration and everyone now talks about safety as being important and most people genuinely believe it. However, the industry is still experiencing too many serious events which, if we are unlucky, could easily result in another tragedy.

We are a global industry in which good practices are shared across our operations. The loss of life in any country has to be as unacceptable as a tragedy on our own doorstep.

Over the past 25 years since Piper Alpha, there have been more than 25 multi-fatality accidents in our industry. In June, two people died in an accident on a gas platform in the Dutch sector of the North Sea. Last year, three died in an explosion in the Gulf of Mexico (GOM) and 11 died in the Deepwater Horizon explosion in the GOM in 2010.
Storing Oil on the Sea Bottom to Improve the Bottom Line
Authors: Jacobs Trent
Published: February 2015

Technology Update

The growing desire of offshore operators to speed up subsea field development while reducing costs has fostered many compelling innovations. Among those systems under development to meet this demand, and one with broad applications, is a subsea storage unit (SSU) created by Kongsberg Oil & Gas Technologies. The SSU employs the new concept

of a “flexible bag” protected by a dome for oil storage on the seafloor (Fig. 1). Depending on field conditions, the dome can be made of concrete, fiberglass, or steel. The system offers oil companies a safer, more cost-effective method of developing subsea fields in extreme weather zones or in the Arctic where ice floes are prevalent. The SSU is also being qualified for extended well testing (Fig. 2) and early production startup, and it may enhance the economics of fields with insufficient reserves to support full field development. Furthermore, the SSU could be used in place of subsea storage cells, fixed platforms, floating storage units (FSUs), and pipelines.

“It is an alternative to existing storage facilities and could also potentially commercialize the development of marginal fields,” said Astrid Rusås Kristoffersen, a subsea systems product and technology manager at Kongsberg. “The [SSU] will increase profitability of marginal fields, because the oil can be stored subsea. And then, using small shuttle tankers for more frequent offloading will precipitate the cash flow and reduce operational costs.”

Ideally, two or more SSUs could be used to maximize the allowable output volume that could be uploaded into a tanker. As production increases, SSUs could be added to the cluster. Kongsberg is considering standardizing the dimensions of the SSU to fit different needs, with the largest version on the drawing board being 131 ft (40 m) in diameter with a capacity of 120,000 bbl of oil.

Subsea storage technology has been used before in limited applications, but never has the design used a collapsible bag to store the oil. The bag is partly made of a polyester woven yarn that is coated with an impermeable layer on both sides to eliminate the possibility of seawater and oil mixing. Were that to happen, an emulsion layer could form, leading to bacterial growth that could cause corrosive damage inside steel pipe-lines and valves.
SPE Strategic Plan Identifies Four Priorities
Authors: JPT staff _
Published: February 2015

Strategic Plan

Editor’s note: The SPE Board of Directors approved the SPE Strategic Plan 2013–17 in March 2013. The SPE Strategic Planning Steering Committee consisted of Ganesh Thakur, SPE 2012 President and Steering Committee Chair; Mark Rubin, SPE Executive Director; Egbert Imomoh, SPE 2013 President; Ken Arnold, SPE 2012 Vice President Finance; Janeen Judah, SPE 2013 Vice President Finance; Alain Labastie, SPE 2011 President; and Jeff Spath, SPE 2014 President-Elect. Consultant and facilitator was Susan S. Meier, Principal, Meier and Associates.

Since its inception 55 years ago, SPE has remained constant in its mission to collect, disseminate, and exchange technical knowledge and to provide opportunities for professionals to enhance their technical and professional competence. SPE is increasingly aware of the impact a changing environment and global influences may have on its ability to be effective in serving an increasingly diverse membership in a highly complex industry.

By all objective measures, SPE is a highly successful organization. SPE has seen dramatic growth in member-ship globally (Fig. 1) and in the number of meetings offered (Fig. 2) to serve these members. At the same time, SPE has added new programs, expanded the reach of its programs and services, opened new offices to serve its global membership, and worked with other organizations to create greater value for members and the industry as a whole.

One SPE

Throughout this period of strong growth, SPE has strived to operate in a manner consistent with a set of One SPE Guiding Principles adopted by the Board in September 2001:

The Society of Petroleum Engineers is a diverse community of professionals that provides valuable knowledge and services to those professionals and to the industry in varied forms.

The concept of One SPE reflects the goal that each function and activity of the Society should serve the broader membership while addressing local needs, supporting technical and professional excellence, and making wise use of Society resources.

The voluntary donation of time and talent by SPE members is our most vital asset and the creative energy of volunteers must be encouraged and supported by the Society.
Dry Tree Semisubmersibles: The Next Deepwater Option
Authors: Jacobs Trent
Published: February 2015

Dry Tree Semisubmersibles

To commercialize some of the world’s most challenging deepwater fields, offshore engineering companies are developing a new class of drilling and production platform known as the dry tree semisubmersible (DTS). The challenge involves taking existing technologies and lessons learned from previous floater designs to create an alternative platform for waters too deep to cost-justify the use of tension-leg platforms (TLPs) and fields too large for spar platforms.

Dry trees, also known as Christmas trees, are wellhead devices installed during the completion stage of a well’s life and give the operator control over production. Used on onshore wells, dry trees have been used extensively on shallow water fixed platforms, TLPs, and spars, but never on a deepwater semisubmersible because that platform’s motions are too extreme to support a dry tree system.

As the DTS concept awaits introduction into the deepwater market, multiple designs are under evaluation by major off-shore oil companies and the Norwegian classification society Det Norske Veritas (DNV).

The chief advantages of using a DTS are that opera-tors can drill, complete, and carry out intervention operations on multiple wells from the same platform in depths below 6,000 ft. This saves the operator significant resources that otherwise would be spent over the life of the field on contracting mobile offshore drilling units or purpose-built, well-intervention semisubmersibles.

Going Deeper With a DTS

A TLP typically uses four columns to support a large topside facility and is secured to the seafloor with mooring lines that allow the floating platform to move from side to side, but not up and down. Operating at a water depth of 4,674 ft, ConocoPhillips’ Magnolia TLP in the US Gulf of Mexico (GOM) is the deepest structure of its kind in the world. Next year, Chevron hopes to begin first production from its Big Foot TLP, also to be located in the GOM, at a depth of approximately 5,200 ft. Beyond 6,000 ft, TLPs become impractical because of the amount of steel needed for the tendons that moor the platform to the ocean bottom.
E&P Software: The Next Generation
Authors: Rassenfoss Stephen
Published: February 2015

Incubator for Startups

A handful of entrepreneurs are out to disrupt the daily routines of workers in oil exploration and production (E&P) by applying digital technologies.

The entrepreneurs are members of a generation of digital natives who grew up expecting constant online contact and information, so their ideas are typically a version of how they expect the world to work.

RunTitle wants to cut the number of days spent in courthouses searching title records to find the owners of mineral rights by creating a national online database.

The Global Material Exchange

(Gmex) is creating an online marketplace for the millions of tons of steel products now bought and sold using phones, faxes, and email.

Skynet Labs plans to replace spread-sheets and manual calculations by drillers with applications that can be used on smartphones or tablets, and ultimately with a cloud-based system offering greater computing power and the ability to collaborate.

Secure Nok is going about drilling rig security from a different angle, looking for signs of trouble by closely analyzing machine performance.

Waveseis seeks to create better seismic images of formations otherwise obscured by thick layers of salt.

They are among the 12 companies in the second class of startups nurtured by the Surge Accelerator—a 2-year-old Houston venture created to use techniques developed in the technology sec-tor to jump-start early-stage companies in energy. About half the business plans are based on software to improve oil and gas operations.

Surge was founded on the premise that the energy industry is ripe for a digitally driven change that has transformed business sectors such as finance and manufacturing. “They (plans of Surge companies) are all focused on collecting data, managing data, analyzing data—all in real time—and providing actions on top of that,” said Kirk Coburn, managing director of Surge, who summed it up as “true real-time intelligence.”

Initially, Surge was investing only in software for energy—including alter-native energy and electricity—but its investment committee has added hard-ware. The group includes Dynamo Micro-power, which makes a simplified turbine that can be powered by wellhead gas to generate power. Water has also been added because it is so critical in this realm.

If these ideas turn into profitable enterprises, Coburn and the other Surge backers have a chance to profit from it. The accelerator gets a 6% stake in the companies in exchange for financial support, training, mentoring, and connections to potential investors and users during a 3-month program in Houston.
Saudi Aramco Oil and Gas Production Hits Historic Levels
Authors: Henni Abdelghani
Published: February 2015

Production Record

Saudi Arabian state oil company Saudi Aramco released its annual report in July, noting that it produced more oil and gas last year than ever before, and also raised its technical capabilities to new heights as part of it 2020 strategy to be a fully integrated energy and chemicals company.

The company’s annual production exceeded 3.4 billion bbl of oil, equal to an average of 9.5 million BOPD. “In 2012, we produced 3.479 billion bbl of oil, about one in every eight bbl of the world’s crude oil production and the most we have produced in a single year in our history,” Saudi Aramco said in its annual report.

“During 2012 at Saudi Aramco, we responded to market conditions by producing crude oil at the highest level in our company’s history,” said Khalid Al-Falih, president and chief executive officer of Saudi Aramco.

The company’s recoverable crude oil and condensate reserves have reached 260.2 billion bbl, while gas reserves reached 284.8 Tcf. “Our maximum daily sustainable crude oil production capacity remained at 12 million BOPD during the year. Our gas plants now have a gas processing capacity of 13.23 Bscf/D,” the report said.

Gas production has also reached historic levels, as the company reported an 8.3% increase in output in 2012 com-pared with 2011 at about 3.924 Tcf/yr, the highest in Saudi Aramco’s history. The company also said that it produced 482 million bbl of natural gas liquids including 82 million bbl of condensates.

Crude oil exports increased 100 million bbl in 2012 to 2.52 billion bbl, with 53.2% exported to the Asia Pacific region followed by 16.5% to the United States, 7.4% to the Mediterranean region, and 5% to Europe.

In 2012, Saudi Aramco focused on exploring frontier areas in the Red Sea and complex reservoirs onshore and offshore. Discoveries included one oil field—Aslaf—and two gas fields—Sha’ur and Umm Ramil—bringing its total oil and gas field discoveries throughout its history to 116. Sha’ur was its first discovery in the marine portion of the Red Sea.
Industry/Research Collaboration Advances Oil and Gas Technologies
Authors: Stepankiw Mika
Published: February 2015

R&D on Campus - Universities are working hard to anticipate the demand for new technologies and techniques as oil and gas exploration delves into deeper waters, harsher climates, and unconventional fields. Numerous universities are teaming up with the industry on projects such as modeling software, heavy oil technologies, fines migration, drilling technologies, and foam to enhance oil recovery and production. Through these research collaborations, more efficient methods are being developed to meet the increasing global consumption of oil and gas.

Petroleum Engineering Department, Colorado School of Mines, US

The Petroleum Engineering Department at the Colorado School of Mines has a large undergraduate and graduate enrollment and a healthy mix of multidisciplinary research efforts including the Unconventional Natural Gas and Oil Institute; the Marathon Center of Excellence for Reservoir Studies; the Fracturing, Acidizing, Stimulation Technology Consortium; the Energy Modeling Group; the Unconventional Reservoir Engineering Project; and the Physics of Organics, Carbonates, Clays, Sands, and Shales Consortium.

One area of focus is the Routes to Sustainability for Natural Gas Development and Water and Air Resources project in the Rocky Mountain Region. For this project, the Petroleum Engineering and the Civil and Environmental Engineering departments are working with their sister school, the University of Colorado at Boulder, and seven other institutions in a Sustainability Research Network (SRN) funded by a 5-year grant from the US National Science Foundation. The mission of the SRN is to provide a logical, science-based framework for evaluating environmental, economic, and social trade-offs between the development of natural gas resources in the Rocky Mountain Region and the protection of water and air resources. The SRN plans to give the results of these evaluations to the public in a way that will improve policies and regulations governing oil and gas exploration. “Our goal is to find the balance between maximizing the development of natural gas and oil resources for the benefits of short-term reduction of CO2 emissions from power generation and transportation, national energy independence, and national job growth, while minimizing damage to water and air resources and risks to human health,” said Joseph N. Ryan, faculty director of the research project.
Design of an Automated Drilling-Prediction System
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 163709, ’Design of an Automated Drilling-Prediction System - Strengthening-While-Drilling Decision Making,’ by Samuel R. Perez Bardasz, SPE, Edwin David Hernandez Alejadre, and Armando Almeida Leon, Petrolink, prepared for the 2013 SPE Digital Energy Conference and Exhibition, The Woodlands, Texas, USA, 5-7 March. The paper has not been peer reviewed.

Data-mining processes are fundamental in obtaining the predictive benefits of real-time systems and have been progressing from descriptive to predictive optimization methods. These methods are enhanced by real-time and historic data. Advanced sensor technologies, improved data-quality control, wellsite information-transfer standard-markup-language (WITSML) data advantages, and virtual real-time drilling-optimization concepts have been assimilated into the design and implementation of prediction systems.

Introduction

As technologies evolve and the WITSML standard allows data exploitation by many specialized applications, more-accurate and reliable drilling data are available at real-time operation centers (RTOCs) to analyze and mitigate drilling issues. This enhances and speeds up the drilling-optimization process, and allows a small group of highly skilled drilling engineers to support several wellbore constructions simultaneously.

However, the traditional tasks of monitoring drilling parameters are still constrained by the constant need for human intervention. First, the particular field-operations knowledge gained by RTOC monitoring engineers is very valuable but fragile, because it requires the continued participation of team members. To ensure that nothing is overlooked, that knowledge should be gathered and used by an intelligent system. Second, the status of a particular event or well is constantly changing as key drilling factors change, and monitoring engineers must review all data in detail before manually defining the new status of a system. Third, a complete update of a general well-operations status report is time consuming. The operations status for a set of wells being drilled and monitored can change dramatically from one minute to the next and therefore requires the constant participation of an engineer. Such a report should be automated to de-rive maximum benefit from the best real-time and historic data.

Drilling-Data Mining

The drilling industry is aware of the importance of pattern analysis and past performance of correlation wells. It has looked to similar drilling-well experiences to predict the probability of a particular event or drilling outcome. This has been achieved effectively with human intervention, despite the fact that multiple data families that needed to be taken into account were difficult to access for different reasons.
Management Strategies Optimize Drilling and Completion Operations
Authors: Carpenter Chris
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165325, ’A Successful Optimization Case of Drilling and Completion Operations Through Management Tools and Strategies,’ by Oscar R. Silva, Guden O. Silva, and Luis I. Valderrama, Ecopetrol, prepared for the 2013 SPE Western Regional and AAPG Pacific Section Meeting and Joint Technical Conference, Monterey, California, USA, 19-25 April. The paper has not been peer reviewed.

By 2010, all applicable drilling solutions had seemingly been applied to the Castilla field in Colombia.  But new problems were identified, and a model of management strategies was implemented to reduce drilling and completion timing. During the resulting optimization process, the Castilla field became the model for the rest of the fields in the company portfolio. It is believed that this model might also be applied successfully to other fields.

Introduction

In a May 2010 evaluation, several facets of Castilla field operations were assessed: current processes, operations, and technologies; the state of drilling operations by use of management indicators; nonproductive time (NPT); field characteristics; and roles and responsibilities of personnel. The objectives were to prioritize processes by importance, create a process guide, develop a new manpower plan, improve communication, and apply technology efficiently.

Optimization Evaluation Results Field Characteristics. The Castilla field is 200 km from BogotÁ in the Llanos basin. This field has three formations of heavy oil (T2, K1, and K2) to 7,500, 8,000, and 8,500 ft in true vertical depth (TVD), respectively. Most of the wells are drilled to approximately 9,500 ft in measured depth. The majority of the wells are J-shaped, with inclinations from 30 to 70°. The most common operational problems in the field were to be found at approximately 1,000-ft TVD, at the shale formation found immediately above pay zones.

Optimization Model. The optimization process had three principal stages: implementation, consolidation, and optimization excellence. The development of each well had involved five steps during the drilling process: planning, implementation, control, feedback, and optimization. The drilling engineer had to plan the well; implement, explain, and communicate the plan; control the drilling while continuously monitoring parameters, ensuring compliance with the plan and the application of the lessons learned; catalog the lessons learned; and apply these lessons to new optimization plans.

The working optimization model was designed around several major strategies, all developed on the basis of technical limits related to health, safety, and environment (HSE): continuous monitoring of indicators; establishment of only one line of communication; application of short-, medium-, and long-term well vision; and organization based on engineering.
Techbits: Real-Time Data's Value Explored in Workshop
Authors: JPT staff _
Published: February 2015

Techbits

A one-day workshop held in June in Houston focused on “The Value of Real-Time Data.” Jointly sponsored by the SPE Gulf Coast Section (GCS) and the SPE Real Time Optimization Technical Interest Group (RTO TIG), the workshop compiled published reports on the value of real-time data and also gave the 150 attendees the opportunity to discuss the challenges that remain.

“Some years ago, the industry was challenged with large targets achievable from the creation of digital oil fields,” said Roger Hite of Business Fundamentals Group and chair of the workshop committee. “Since then, we have all been busy with various projects—building infrastructure, writing software, adapting work processes, and training staff—all with the goal of capturing this promised value.”

The value of digital-oil-field initiatives has received extensive coverage in technical papers, as a quick search in the OnePetro literature database demonstrates. A literature search using the keywords “real time” and “value” yields a list of almost 3,500 papers, Hite said. “This is a bit more than most of us have time to review. We wanted to create a compilation that would be useful to SPE members. The goal was to find and document as many case studies as possible to provide quantitative data on the value actually realized from the use of real-time data.”

Literature Review

In preparing for the workshop, SPE volunteers consisting of subject matter experts narrowed the list down to a manageable number of papers. And while they did their best to locate the best papers, Hite acknowledges that some have likely been overlooked. “If JPT readers know of any papers we should have included, we will greatly appreciate your letting us know,” he said. “We intend to keep this list evergreen, possibly using wiki technology.”

The volunteers carefully reviewed each of the selected papers using a special form to capture relevant information. From these reviews, more than 40 case studies were identified as “good sources,” meaning that most of them included hard numbers that could be used to validate value, while a few provided valuable summaries and insights. “In some areas, we included references to papers that are ‘possible sources’ of information,” Hite added. “These lack hard data, but provide valuable overviews.”
R&D Investment Trends and the Rise of NOCs
Authors: Thuriaux-Aleman Ben , Salisbury Sam , Dutto Paolo R.
Published: February 2015

Management

The global energy industry has been facing a variety of challenges in recent years: high price volatility, the decline of “easy oil” and a shift of production to emerging markets, shortage of talent, pressure to reduce the carbon footprint, and a surge in petronationalism. These challenges have shifted power toward national oil companies (NOCs) and have raised questions about the current business model of the international oil companies (IOCs).

In dealing with increasingly complex oil fields, some have argued that the IOCs can maintain a competitive advantage by leveraging their internal technology competence and their experience in leading and coordinating technology-driven project skills to transform pioneering E&P approaches into commercially viable approaches. Much of this rests on the IOCs’ technology leadership based on their strengths in R&D and technology. However, recent trends in R&D spending (Fig. 1) suggest that the IOCs’ dominance in R&D is being challenged both by a leading group of NOCs and by the international service companies.

NOCs Now Lead in R&D Spending The top five IOCs by revenue increased R&D with an average year-on-year growth of 9.8% in the period 2003–2009. Total has shown the smallest R&D growth since 2003, but it had a high starting point compared to the other IOCs, especially when adjusting for size of operations (Fig. 2). Chevron has increased its spending on R&D 18% year on year since 2003 but remains behind the leaders. Starting in 2006, Shell has pushed to develop technologies for more difficult assets. In doing so, it has become the top spending IOC in terms of absolute R&D expenditure. BP appears to spend relatively little on R&D but this masks the fact that a lot of its technical efforts are centered on piloting and field trials.

In contrast to the IOCs’ moderate growth, a small group of leading NOCs has been investing heavily in R&D. Petrobras’ R&D spending has increased at a rate of 23% a year since 2003 and is now on par with Total and ExxonMobil. But the most impressive growth in R&D has been for CNPC/PetroChina, which saw an annual increase of 31% during the same period. In 2009, PetroChina overtook Petrobras and Shell as the leading spender both in absolute levels of R&D spending and on a per-BOE basis.
Akpo: A Giant Nigerian Deep Offshore Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20989, ’AKPO: Early Completion of a Giant Nigerian Deep Offshore Development,’ by Francois Rafin, SPE, and Allain Lacne, Total S.A., originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

Akpo field was discovered in January 2000 and production started ahead of schedule in March 2009 in Block OML 130, 200 km offshore Nigeria in 1400-m water depth. The Akpo project faced the challenges of combining gigantic scale, new technological frontiers, world-scale industrial execution, scarcity of resources in booming years for the offshore industry, and setting new records of local content in an unstable Niger delta. 

Introduction

A unique hybrid gas-injection/gas-export development scheme was chosen to maximize hydrocarbon recovery with massive pressure maintenance and the extensive use of intelligent and selective completions and subsea multiphase-flow measurements.

The wellhead shut-in pressure of 430 bar and temperature of 116°C represented new frontiers for the deepwater industry.

To deliver a 72-slot, 44-well, 10-manifold, 14-steel-catenary-riser (SCR) subsea development in West Africa, the project strategy was to use generic and qualified systems and equipment. The Akpo field characteristics required several technological innovations and the development of existing technology such as:

All-electric floating production, storage, and offloading (FPSO) vessel with a centralized control room on each topside module

Inconel-clad SCRs with high-pressure/high-temperature flex joints

One fully integrated control and safety system from wellbore to FPSO topside provided by a single contractor

An internally flow coated 155-km-long gas-export line that increases the flow capacity by 20%, enabling (because of a reduced diameter) the use of seamless pipe

Crushable foam and bursting disk to control the well annulus-pressure buildup, because no casing steel is available to withstand the stress at Akpo pressure and temperature conditions

First 10¾-in. frac-pack runs in a single trip

First use of 7-in. expandable screens for a subsea application

Intelligent completions with downhole monitoring and control from the FPSO control room

Automatic ultrasonic testing system for Akpo subsea pipelines, capable of detecting defects smaller than minimum acceptable
FDPSOs: The New Reality and a Game-Changing Approach to Field Development
Authors: Bybee Karen
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 20482, ’FDPSOs: The New Reality, and a Game-Changing Approach to Field Development and Early Production Systems,’ by W.D. Harris, SPE, H.J. Howard, SPE, and K.C. Hampshire, SPE, Murphy West Africa; J.A. Moore and K.J. Bayne, SPE, Doris Inc.; and Jean Pepin-Lehalleur, Doris Engineering, originally prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed.

The Azurite field development, installed in the Republic of Congo in 2009, employed the industry’s first floating drilling, production, storage, and offloading (FDPSO) vessel to develop the field. While the FDPSO concept has been a subject of interest within the industry for some time, the Azurite project team took the FDPSO from concept to reality. The concept has tremendous potential as a “game changer” for field developments.

Introduction

The Azurite field lies within the Mer Profonde Sud (MPS) Block offshore the Republic of Congo, just north of the border with Cabinda Block 14. Water depths across MPS range from 1100 to 2000 m. Azurite field was discovered in January 2005 with the AZRM-1 well. The field was appraised in late 2005 and early 2006 with the drilling of the AZRM-2 and AZRM-3 wells. Each of the latter two wells was sidetracked (ST). AZRM-2ST also was cored and tested. Aquifer support was found to be essentially nonexistent along the producing trend, necessitating water injection to support reservoir pressure.

Concepts Considered

The Azurite integrated project team began the task of identifying and evaluating field-development alternatives. Multiple development schemes were identified and evaluated. The four main alternatives evaluated were:

Subsea tiebacks to third-party facilities

Subsea tieback to infield floating production, storage, and offloading (FPSO) vessel

Dry-tree unit (DTU) producing to FPSO

Infield FDPSO

A subsea tieback to third-party facilities in the Republic of Congo or Angola was considered and deemed technically feasible, with the aid of subsea boosting. However, tiebacks to third-party facilities in the Republic of Congo or tiebacks to third-party facilities in Angola, with the associated cross-border issues, would have introduced too much schedule and political risk. Hence, tieback schemes involving third-party facilities were not selected.

A subsea tieback to an infield FPSO was considered. However, strong market demand for deepwater floating rigs exposed the project to significant schedule delays. Likewise, their associated day rates adversely affected project economics.
Probabilistic Modeling for Decision Support in Integrated Operations
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 127761, ’Probabilistic Modeling for Decision Support in Integrated Operations,’ by Martin Giese, University of Oslo, and Reidar B. Bratvold, SPE, University of Stavanger, prepared for the 2010 SPE Intelligent Energy Conference and Exhibition, Utrecht, Netherlands, 23-25 March. The paper has not been peer reviewed.

A system was designed to assist operational decisions on the basis of real-time sensor readings in a typical scenario: While drilling close to the transition to a high-pressure formation, gas influx is observed. The technology used Bayesian networks and influence diagrams (IDs) to apply the method of decision analysis. The resulting ID was tested with a simulation.   

Introduction

An assumption of integrated operations is that all information provided by the technology will help to make better decisions faster. But for this to happen, information must be presented in an accessible, useful, and decision-relevant format. Decision-analysis tools provide decision makers with logical and consistent recommendations based on the available data. This decision-analysis method was applied to a real case, representative of a typical scenario in drilling operations. The tool enabled good decisions consistently. However, effort is required and challenges exist in the modeling process along with problems regarding the way decision making is treated in the industry.

Modeling and Solving

A decision tree provides a graphical illustration of all the uncertainties, decisions, and payoffs associated with a decision situation. Although application of decision trees is intuitive for simple problems, the method loses its appeal for complex decisions. A symmetric decision tree grows exponentially with the number of variables in the decision domain, which often makes its use impractical. For complex decisions, the ID can provide a level of insight and transparency that cannot be achieved with the equivalent decision tree.

The ID is a compact graphical-model representation for reasoning under uncertainty and was developed to assist structuring and analysis of complex decisions. The ID has two advantages—structuring and probabilistic evaluation. The structuring provides a graphical representation of the inter-relationships among the decision-basis elements (i.e., alternatives, information, and preferences), while the evaluation appraises the resulting decision structure and provides an assessment of its expected utility given the quantified decision basis.

The representational framework of an ID captures the probabilistic relationships among decisions (alternatives), key uncertainties (information), and utilities (values or preferences). The ID model comprises four types of nodes. Decision nodes specify a set of alternatives. Chance nodes represent the key uncertainties in the decision domain. Deterministic nodes represent either constants or intermediate calculations. Value nodes represent the criteria used to make the decisions.
Channel Fracturing - Paradigm Shift in Tight Gas Stimulation
Authors: Denney Dennis
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140549, ’Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation,’ by J. Johnson, SPE, M. Turner, SPE, and C. Weinstock, SPE, Encana; and A. Pena, SPE, M. Laggan, SPE, J. Rondon, and K. Lyapunov, Schlumberger, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed.

The hydraulic-channel-fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, providing highly conductive paths for fluid flowing from the reservoir to the wellbore. The Lance formation in the Jonah field near Pinedale, Wyoming, was selected for this study. Results indicate that implementation of the channel-fracturing technique increased initial gas production and estimated recovery over conventional fracturing methods. Positive features during this campaign included reduced net-pressure-increase estimates from pre- and post-fracture-treatment shut-in-pressure measurements, reduced tendency for vertical fracture growth, and elimination of near-wellbore screenouts. 

Introduction

Natural gas plays a major role in the assortment of energy resources that sustain the USA. The imbalance between future energy demands and reduced availability of gas from conventional sources dictates the need to increase gas recovery from unconventional sources such as tight gas reservoirs, shale-gas reservoirs, and coal seams. Hydraulic-fracturing treatments in tight gas formations during the 1970s consisted of pumping large quantities of a propping agent and carrying gelled fluids and emulsions at pressures in excess of the formation-fracturing pressure. Beginning in the 1980s, this fracturing technique included various combinations of nitrogen gas and/or liquid carbon dioxide pumped in combination with fluid and proppant for stimulation purposes. Low-viscosity slickwater treatments, in which proppant is pumped at low concentrations within a high-rate water stream, became popular in the 1990s for stimulating tight gas reservoirs. All these techniques rely on filling the fracture with the propping agent to maintain an open fracture. The proppant pack placed within the fracture also serves as a conductive medium for gas flow to reach the wellbore. The effective area of the fracture covered by proppant varies according to the technique used. Typically, completion efficiency is low for slickwater treatments, and it often improves with the use of viscous carrying fluids and fibers, among other methods.
Technology Focus: Sand Management and Frac Pack (October 2011)
Authors: Azeemuddin Mohammed
Published: February 2015

Technology Focus

With world population increasing and industrialization demanding newer and harder-to-reach sources of hydrocarbon, the demand for energy is constantly on the rise. Development of hydrocarbons from harsh environments often leads to narrow safe drilling-mud-weight tolerances (or windows) that accompany ultradeepwater subsalt plays and high-pressure/high-temperature developments. These narrow mud-weight windows also can be found in highly compartmentalized developments that encounter severely depleted and/or unconsolidated reservoirs. Technology to tap these reservoirs must meet the growing challenging conditions and produce hydrocarbons both safely and cost effectively. 

Sand production and fines migration have long held the attention of industry professionals in developing a means to predict them, manage them, and devise innovative ways to avoid or minimize them by use of proper field-development practices and newer downhole completion tools and technologies. Most recently, progress was made in predicting the rates and amounts of sand produced for the purpose of optimizing sand-management strategies and choosing the correct completion/production strategy for the expected sand volumes. Every reservoir-rock formation, and corresponding field-development plan, provides a unique set of challenges with associated learning opportunities that may favor one completion method over another. The final decision of which completion method to use lies in an in-depth understanding of the geology, reservoir conditions, in-situ stresses, fluid and rock properties, equipment considerations, sand-management options, and costs.

The papers selected for this feature come from varied geographical locations involving different geological settings that highlight the importance of studying the unique conditions at hand, in detail, and applying a fit-for-purpose technology to maximize production and cost effectiveness. Other interesting case and modeling studies, by no means less important, are listed in the additional-reading group.

Sand Management and Frac Pack additional reading available at OnePetro: www.onepetro.org

SPE 139360 • “A Unique Sand-Control Screen That Enhances Productivity” by G. Woiceshyn, Absolute Completion Technologies, et al.

SPE 143941 • “Formation Loading and Deformation of Expandable Sand Screens” by Colin Jones, Weatherford, et al.

SPE 144047 • “Controlled Use of Downhole Calcium Carbonate Scaling for Sand Control: Laboratory and Field Results, Gullfaks” by N. Fleming, SPE, Statoil ASA, et al.