oilfield review sring 2013 - schlumberger
TRANSCRIPT
Spring 2013
Developing Talent
Structural Steering
Expanded Downhole Sampling
Imaging Circular Seismic Surveys
Oilfield Review
13-OR-0002
Wireline, or electric line, has come a long way since Schlumberger produced the first electrical resistivity log in Pechelbronn, France, in 1927. Today, logging includes reservoir characterization in both open and cased hole, reservoir monitoring and surveillance and workover and mechanical services. And while it is still referred to as wireline, logging tool conveyance methods have expanded to include advanced cable products, drillpipe, tractors and unique through-the-bit technologies.
At Schlumberger, decisions about how to balance a large and diverse portfolio are complex but at the core require a discussion of two essential categories: revolutionary technology geared to open new areas of operation and evolutionary technology to enhance measurements, improve efficiency or reduce costs in an ongoing market.
Of the two, revolutionary technologies are the more time sensitive. Their introduction must be carefully managed to ensure that each one meets the challenges facing custom-ers at the time. These innovations often provide the only means for breaking through former barriers. The introduc-tion of revolutionary products facilitates entrance into new markets, and once such technologies are successful, many evolutions follow—each an improved, more refined spinoff of the original.
In the mid-2000s, the Schlumberger Wireline segment embarked on several critical evolutionary technologies under the banner of Scanner* rock and fluid characterization services. The goal of this family of services was to upgrade technology to meet the demands of key petrophysical and geomechanical measurement tools—the Rt Scanner*, Sonic Scanner* and MR Scanner* services. Each product, while innovative, evolved from a similar predecessor tech-nology, and each enabled customers to take a closer look at, or scan, important petrophysical and geomechanical downhole formation properties.
Customers have long relied on Schlumberger to develop and bring to market technologies that match current needs, including those in what are probably the most challenging new arenas of operation: low-permeability formations, deep water, unconventional reservoirs and heavy oils. These new solutions are broadening the capabilities of the traditional suite of logging services.
Petrophysical evaluation of porosity and saturation in low-porosity and low-permeability unconventional reser-voirs requires an accurate evaluation of matrix density, which is a function of formation mineralogy. However, conventional methods for determining mineralogy are not independent of the level of maturity of the organic content or of formation salinity, density or resistivity. As a result,
Evolving Revolution
1
operators must conduct expensive and time-consuming coring operations for laboratory analysis to obtain the necessary quality of mineralogy data.
With recent increases in the producibility of unconven-tional resources, improved reservoir characterization in these plays has been a top priority of the Schlumberger Wireline engineering portfolio. As a consequence, this year the company is introducing innovative and well-timed tech-nologies for both petrophysical and reservoir applications.
The unprecedented accuracy of the new Litho Scanner* spectroscopy service provides elemental weight fractions, particularly for magnesium, and a stand-alone total organic carbon output for quantifying the amount of hydrocarbon in place; these measurements are crucial to petrophysical modeling in complex lithology. The Litho Scanner mea-surement yields mineralogy and matrix density corrected for organic content, which has made it possible to deter-mine porosity in unconventional reservoirs worldwide without the need to collect extensive samples and wait for laboratory analysis.
Equally impressive, and featured in an article in this issue of Oilfield Review, is a wireline-conveyed reservoir tool that will probably have the most impact of any tool since the inception of the MDT* modular formation dynam-ics tester platform. The Saturn* 3D radial probe combines the efficiency of a probe with the operating range exten-sion of a dual packer (see “New Dimensions in Wireline Formation Testing,” page 32). This technology extends formation testing to previously inaccessible fluids and reservoir environments. Since its introduction in 2012, it has become a worldwide phenomenon; the Saturn probe has been successfully operated on six continents and 19 countries, both onshore and off.
In the Schlumberger Wireline segment, we like to think of ourselves as measurement pioneers. With the introduction of revolutionary and evolutionary technologies, Schlumberger, as it has done since 1927, will keep meeting customers’ needs as the E&P industry continues to break barriers in hydrocarbon exploration.
Catherine MacGregorPresident, Schlumberger WirelineClamart, France
Catherine MacGregor is President of Schlumberger Wireline. After joining the company in 1995 as a field engineer with Sedco Forex, she held diverse management and marketing positions throughout Europe, Asia and the US for Schlumberger Drilling & Measurements. In early 2007, she became Schlumberger personnel director and later that year was appointed vice president personnel for Schlumberger Limited. She was named to her present position in 2009. Catherine holds degrees in general engineering and aerospace engineering from Ecole Centrale de Paris and a diploma in advanced studies of energetics and heat transfer. She is based in Clamart, France.
An asterisk (*) is used to denote a mark of Schlumberger.
www.slb.com/oilfieldreview
Schlumberger
Oilfield Review
1 Evolving Revolution
Editorial contributed by Catherine MacGregor, President, Schlumberger Wireline
4 Bridging the Talent Gap
To remain current with developments in the rapidly chang-ing oil and gas industry, petrotechnical professionals must have effective training. One approach to petrotechnical training uses competency management and a blended learn-ing-by-doing approach to accelerate learning and proficiency.
14 Structural Steering—A Path to Productivity
The technologies that enable horizontal drilling continue to improve, changing the way operators plan and drill oil and gas wells. Structural steering, which integrates data from deep-reading resistivity tools and high-resolution imaging LWD devices, is helping operators better under-stand structurally complex reservoirs and proactively optimize well placement.
Executive EditorLisa Stewart
Senior EditorsTony SmithsonMatt VarhaugRick von Flatern
EditorRichard Nolen-Hoeksema
Contributing EditorsJohn KingstonGinger OppenheimerRana RottenbergDon Williamson
Design/ProductionHerring DesignMike Messinger
Illustration Chris LockwoodMike MessingerGeorge Stewart
PrintingRR Donnelley—Wetmore PlantCurtis Weeks
Oilfield Review is published quarterly and printed in the USA.
Visit www.slb.com/oilfieldreview for electronic copies of articles in English, Spanish, Chinese and Russian.
© 2013 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited.
For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at www.glossary.oilfield.slb.com.
About Oilfield ReviewOilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to employees, customers and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates.
On the cover:
An engineer prepares to download data from an LWD logging tool that records resistivity and imaging data while drill-ing. Geologists interpret high-resolution image data from this tool to identify faults and fractures and determine for-mation dip. The data are either sent uphole in real time using mud pulse telemetry or downloaded from the tool when it returns to the surface. Well placement engineers use these interpre-tations to validate drilling programs or make changes to planned wellbore tra-jectories based on geologic conditions encountered while drilling.
2
Spring 2013Volume 25Number 1
ISSN 0923-1730
56 Contributors
59 New Books and Coming in Oilfield Review
63 Defining Drilling Fluids: Drilling Fluid Basics
This is the ninth in a series of introductory articles describing basic concepts of the E&P industry.
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32 New Dimensions in Wireline Formation Testing
Operators face many challenges obtaining pressure measure-ments and samples with conventional wireline formation testers. This is especially problematic in fractured reservoirs, low-permeability rocks and unconsolidated formations. Engineers have recently developed a tool that reliably obtains formation tests in these challenging environments and is also effective sampling from heavy-oil reservoirs.
42 Developments in Full Azimuth Marine Seismic Imaging
Traditional marine seismic data are acquired by a seismic vessel sailing in a series of straight lines over a target. However, shooting in continuously linked circles delivers richer datasets with reflection contributions from all azi-muths and the added benefit of little or no nonproductive time. Case studies from Indonesia, Brazil, Angola and the Gulf of Mexico demonstrate the benefits of circular shooting for imaging challenging environments such as subsalt and other complex geologic settings.
Hani Elshahawi Shell Exploration and Production Houston, Texas, USA
Gretchen M. Gillis Aramco Services Company Houston, Texas
Roland Hamp Woodside Energy Ltd. Perth, Australia
Dilip M. Kale ONGC Energy Centre Delhi, India
George King Apache Corporation Houston, Texas
Andrew Lodge Premier Oil plc London, England
Advisory Panel
Editorial correspondenceOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-1194Fax: (1) 713-513-2057E-mail: [email protected]
SubscriptionsCustomer subscriptions can be obtained through any Schlumberger sales office. Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BHUnited KingdomE-mail: [email protected]
Distribution inquiriesMatt VarhaugOilfield Review 5599 San FelipeHouston, TX 77056United States(1) 713-513-2634Fax: (1) 281-285-0065E-mail: [email protected]
Oilfield Review is pleased to welcome Andrew Lodge to its editorial advisory panel. Andrew is Exploration Director at Premier Oil plc in London. He joined the Premier board of directors in April 2009 from Hess Corporation, where he was vice president, exploration, responsible for Europe, North Africa, Asia and Australia. Previously, he was vice president, exploration; asset manager and group exploration advisor for BHP Petroleum, based in London and Australia. Prior to joining BHP Petroleum, he worked for BP as a geophysicist. He has a degree (Hons) in mining geology from the University of Wales and a master’s degree in applied geophysics from the University of Leeds, England. He is a Fellow of the Geological Society of London. Andrew became a Nonexecutive Director of Egdon Resources in March 2012.
4 Oilfield Review
E&P companies are investing in the education of current employees as well as
acquiring additional talent. A Schlumberger training program is helping companies
manage such talent and accelerate employee training by assessing, developing and
monitoring employees’ skills and abilities. Geoscience and petroleum engineering
courses, integrated training programs and competency assessment and development
services are being used to bridge the gap for the next generation of petrotechnical
professionals while sharpening the skills of current employees.
Seraj Al-AbdulbaqiAl-Khafji, Saudi Arabia
Abdulaziz AlobaydanAl-Khafji Joint OperationsAl-Khafji, Saudi Arabia
Ravi ChhibberAbul JamaluddinLynn MurphyKalyanaraman VenugopalHouston, Texas, USA
Jeffrey D. JohnsonConsultantTulsa, Oklahoma, USA
Oilfield Review Spring 2013: 25, no. 1. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Tamir X. Aggour, Salam P. Salamy and Khalid A. Zainalabedin, Saudi Aramco, Dhahran, Saudi Arabia; Alvin Barber, Alan Lee Brown and Patricia Marçolla, Houston; Ronald Carter, College Station, Texas; and Claude Hernandez, Al-Khafji, Saudi Arabia. Petrel is a mark of Schlumberger.
Every job requires certain skill sets and knowl-edge. In the oil and gas industry, skills and knowledge tend to be honed while on the job. However, because changes are constantly taking place, even experienced professionals may feel some degree of inadequacy. In today’s fast-paced E&P world, operators need interdisciplin-ary approaches to exploration and production, an intense focus on new technologies and atten-tion to the changes in tactics required to pursue new plays, often in settings that were previously deemed inaccessible. For E&P engineers and scientists, these are exciting times filled with innovations and changing paradigms. These cir-
cumstances require both new and existing employees to increase their knowledge and upgrade their skills.
In addition to the challenge of new technolo-gies and new ways of accessing resources, E&P companies must also fill gaps in experience and workforce resulting from a demographic shift in petrotechnical professionals (PTPs), many of whom are leaving their jobs as part of the “great crew change.”1 Many experts who entered the industry during the boom days of the late 1970s and early 1980s are reaching retirement age. This situation is compounded by the baby boom gen-eration in the US, a large number of births
> Global staffing changes, present and future. The percentage of PTPs per age category illustrates the “great crew change” dilemma. The retirement rate is at 20% for 55- to 59-year-olds, 90% for 60- to 64-year-olds and 100% for those 65 and older. The E&P industry attrition rate is 1.4%. (Adapted from Rostand and Soupa, reference 1.)
Glob
al P
TPs,
%
Age, years
0
5
20 to 24 25 to 29 30 to 34 35 to 39 40 to 44 45 to 49 50 to 54 55 to 59 60 to 64 65+
10
15
20
25
20092015
Bridging the Talent Gap
Spring 2013 55
recorded between 1946 and 1964. The first of these “baby boomers” reached age 65 in 2011, and the expectation is that up to 50% of the US energy workforce will retire within the next decade.2 At the same time, the experienced mid-career population of 32- to 50-year-olds is under-represented because of low hiring rates during the boom-and-bust cycles of the 1980s and 1990s.
Although companies are hiring young workers to replace retiring workers, many younger people typically have limited experience and inadequate
training because companies, under restricted budgets, have cut training. The result is a loss of know-how leading to a talent gap (previous page). Companies are already reporting delays in some projects caused by this talent shortage.3 Consequently, some operators ask relatively inex-perienced PTPs to assume the responsibilities of their mentors and managers without allotting time for them to acquire the necessary skills. Young employees also have to take responsibility for complex engineering projects earlier in their
careers than did their predecessors. The result-ing situation necessitates intensified training and development programs.
Changing demographics, the accelerated introduction of new sciences and technologies and the experience gap are combining to com-pel E&P companies to reassess the strategic importance of their training and development programs. In addition, companies want to improve and accelerate the transfer of existing knowledge from senior experts to recent hires
1. The term petrotechnical professionals refers to geoscientists and petroleum engineers. Geoscientists include geologists, geophysicists and petrophysicists. Petroleum engineers include reservoir, drilling, completion and production engineers.
For more on the great crew change: Coton S: “The Great Crew Change: A Challenge for Oil Company Profitability,” Journal of Petroleum Technology 63, no. 4 (April 2011): 58–59.
Rostand A and Soupa O: “The Strategic Importance of Talent,” SBC Energy Perspectives (Summer 2011): 48–51.
2. Tennant J: “Making Informed Human Resources Decisions Based on Workforce Outlook,” World Oil 233, no. 9 (September 2012): R127–R132.
3. Talent refers to a person or persons with ability or aptitude in a particular domain, field or area of knowledge or specialization.
Rousset J-M, Bismuth P and Soupa O: “Technical Talent Shortage Could Begin to Limit Growth,” Journal of Petroleum Technology 63, no. 6 (June 2011): 46–49.
Olson B, Klump E and Kaskey J: “Dearth of Skilled Workers Imperils $100 Billion Projects,” Bloomberg (March 7, 2013), http://www.bloomberg.com/news/2013-03-07/dearth-of-skilled-workers-imperils-100-billion-projects.html (accessed March 7, 2013).
Huizer TJ and Portner F: “Building a Talent Engine,” SBC Energy Perspectives (Semester 1, 2013): 4–9.
6 Oilfield Review
while those experts are still available. Current training programs focus on accelerating the development and transfer of domain knowledge to novice PTPs but are often rooted in tradi-tional classroom learning environments, a methodology that tends to neglect practice and learning using real data and workflow proficien-cies. These proficiencies are essential for suc-cess in the rapidly changing E&P environment.
To make immediate contributions, young PTPs must have a firm grasp of their subject matter and have practical knowledge of the data, tools and workflows important to their work groups and businesses.
The challenge for accelerating petrotechnical learning is to maximize its efficiency, practicality and effectiveness. NExT—Network of Excellence in Training—a Schlumberger company, uses
blended learning-by-doing and competency man-agement to meet these challenges. The approach consists of three components:
These components are achieved through a combination of classroom-based, instructor-led coursework and workshops, case study learning, field trips, visits to laboratories and engineering and manufacturing facilities, mentoring and coaching programs and on-the-job training (left). The exact mixture of these training tools depends on each customer’s needs and the competency levels to be achieved.
Learning-by-doing emphasizes analytical think-ing and experience gained through a mixture of traditional teaching and hands-on training com-plemented by comprehensive technology and data exposure.4 The goal is to shorten the time to auton-omy, transforming a newly hired PTP into a compe-tent, independent decision maker who contributes to a company’s success.5
For fit-for-purpose training, NExT uses com-petency assessment and management to estab-lish the curricula, benchmarks and milestones to ensure that training is efficient, targeted, effec-tive and meets the needs of businesses to acquire talent and the needs of employees to acquire knowledge and skills to do their jobs. These com-petency programs are customized to the require-ments of E&P disciplines and job functions of each business. Competency management uses a matrix of specific skill elements and levels of required proficiency for a job at each rank or pro-gression level. Training and development staff use the matrix to assess proficiency, identify skill gaps, design curricula to fill gaps and verify train-ing effectiveness.
This article describes the NExT program, a training approach created to bridge the talent gap, and explains how training programs are tailored to meet specific customer needs while providing proficiency metrics to quantify success. Case studies of competency manage-
> Geology field trip. At an outcrop of the Desert Member and Castlegate Sandstone in Thompson Canyon, Utah, USA, a field trip leader (second from left) shows trainees that what they see in the outcrop translates to a geologic cross section and a deterministic Petrel E&P software platform model. The outcrop relief here is about 100 ft [30 m].
> Training program. Trainees meet with a Schlumberger subject matter expert (center) to discuss drilling operations in a NExT training program.
4. Learning-by-doing is a form of problem-based learning. For more on problem-based learning: Galand B, Frenay M and Raucent B: “Effectiveness of Problem-Based Learning in Engineering Education: A Comparative Study on Three Levels of Knowledge Structure,” International Journal of Engineering Education 28, no. 4 (July 2012): 939–947.
5. Soupa O: “Benchmarking Industry Talent Needs,” Journal of Petroleum Technology 62, no. 7 (July 2010): 28–30.
6. Bowman C, Cotten WB, Gunter G, Johnson JD, Millheim K, North B, Smart B and Tuedor F: “The Next Step in Collaborative Training,” Oilfield Review 12, no. 2 (Summer 2000): 30–41.
7. Some program participants may receive master’s degrees from Heriot-Watt University if the programs are certified by that university for academic credit.
Spring 2013 7
ment and integrated training programs illus-trate the NExT approach to developing and executing training programs.
BackgroundIn 2000, Schlumberger and three universities that offer curricula in petroleum studies created a limited liability company called NExT, a Network of Excellence in Training. The three uni-versities with close links to the energy industry—Texas A&M University, College Station, USA; the University of Oklahoma, Norman, USA; and Heriot-Watt University, Edinburgh, Scotland—combined their educational capabilities with the operational experience of Schlumberger profes-sionals to provide the NExT organization with training and development expertise.6 This part-nership continues today.
In 2010, Schlumberger purchased commer-cial rights from the three alliance universities
but retained and maintained their instructor pool. In addition, NExT augmented its instructor staff with Schlumberger petrotechnical experts and industry-recognized experts from various consulting organizations.
NExT provides services to E&P companies in more than 50 countries. These services span three categories: oil and gas courses, competency management services and training programs (previous page, bottom).
The NExT course catalog contains more than 420 offerings that include technical and software courses, integrated training programs, software certification, and in some cases, credit toward master’s degrees.7 Competency management ser-vices include initial assessments, competency gap analysis, curriculum development and train-ing to fill assessed gaps in employee competen-cies as well as follow-up verification to quantify improvements from training.
Competency and GapsNExT training programs are often tailored to meet a customer’s business objectives and tech-nical challenges. A NExT team begins the process by building a tailored, customer-specific compe-tency catalog and matrices for each job function; then it executes competency assessments and gap analysis. The results provide the data neces-sary for NExT experts to propose priorities for training and development programs and recom-mend strategies to meet those priorities.
To define job functions, NExT subject matter experts (SMEs) work with a company to under-stand its business and technical needs. Then they draft discipline-based competency matrices for jobs within the company. The matrices con-sist of skill units, skill elements and required proficiencies for each domain—the field or area of knowledge or specialization (above). Each
> Job profile. A job profile matrix is a collection of skill units, skill elements and proficiency levels; only a portion of a matrix is shown here. A skill unit is a collective job function such as reservoir engineering foundations. A skill element is a subset of a skill unit, such as reservoir production geology. Each skill element has a required proficiency (black dot) that depends on the job, required skill unit and a trainee’s experience level. The matrix also includes specific definitions of each skill element (not shown) at each rank and proficiency level; including these specifics reduces assessment subjectivity. A participant performs a self-assessment (checkmark), which is adjusted (X) after an SME interviews selected participants. The deviation of the final adjusted assessed proficiency from the required proficiency shows gaps (blue) and strengths (green) in the individual’s skills and abilities; where there is no deviation color, the individual has met the required proficiency level.
Reservoir production geology
Skill unit Skill element Deviation of assessment from required proficiencies
Reservoir Engineering Profiles
Reservoirengineeringfoundations
Basicreservoir
engineeringmethods
Advancedreservoir
engineeringmethods
Awar
enes
s
Know
ledg
e
Skill
ed
Adva
nced
Expe
rt
–4 –3 –2 –1 0 1 2 3 4
Formation evaluationFluid flow through porous mediaProperties of petroleum fluidsWell performance predictionWell test design and interpretationData managementGeologyPetrophysicsDecline curvesUnconventional reservoirsReserves determinationGas reservoir engineeringPetroleum economicsAnalytical techniquesReservoir management principles and practicesSecondary recovery processImmiscible and miscible gas injectionSubsurface integrationInteractive real-time data transmissionSimulation-model construction and history matchingSimulation-model behavior forecastSimulation compositional modelingSimulation of complex, dual-porosity systems
Gap Strength
XX
X
= Self-assessment= Required level
= Final adjusted assessmentX
XX
X
X
X
X
X
XX
XX
X
XXX
XXX
X
X
X
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skill element in the competency matrix has five proficiency levels: awareness, knowledge, skilled, advanced and expert (above). To reduce subjec-tivity in the assessment, the matrix includes specificity about each skill element, rank and proficiency level. A job profile maps the required proficiency level for the skill elements in that job
within the domain. Core competencies are ele-ments that are critically important in performing the job or meeting a business or technical chal-lenge. The remaining elements are called com-plementary competencies.
SMEs then perform a competency assessment to determine an individual’s actual level of
knowledge and skills compared with the level of knowledge, skills, abilities and competencies required for the job.8 The participants in the training program complete a self-assessment questionnaire by selecting the proficiency level they believe they possess for each of the skill ele-ments. Following the self-assessments, the results are compiled and analyzed, and a sample of participants, who represent the distribution of responses to the questionnaire, is selected for interviews to validate and adjust the self-assessments.
Finally, gap analysis is performed to compare individuals’ assessed proficiency level with the required proficiency level for job functions. When assessed proficiencies are less than required, curriculum planners target these skill gaps for training. When assessed proficiencies are greater than required, these are noted as technical strengths. Gap analysis results form the basis of recommendations for training priorities and pro-grams that address skill gaps and raise the com-petency levels of trainees (below left).
Redefining IndependentSmall, independent oil companies are often char-acterized by flat organizational structures with very little vertical hierarchy. Their business model is simple—to add more reserves through exploration, development and production. Typically, most employees are involved in looking for exploration plays, leads and prospects that may turn into successful discoveries; preparing and executing field development plans; and con-ducting production or reservoir analysis tasks to grow or maintain production from existing assets. These job tasks are focused on growing and exploiting reserves for a company. As a success-ful, small independent oil company grows, its staff increases, and the company eventually imposes some degree of vertical structure and hierarchy. To do so, it must understand what tal-ent it has and how to use it to run the business most profitably and effectively.9
An independent oil company in the US recog-nized that it was facing a personnel development dilemma. The company was expanding rapidly; its workforce and proven reserves doubled in five years. To address this rapid growth, the company formed a talent and development division within
8. Knowledge is the set of facts, concepts, language and procedures needed for a job. Skill is the acquired experience and know-how needed to perform tasks in a job. Ability is the innate aptitude to carry out a job. Competence is the combination of knowledge, skill and ability to perform a job at some specified proficiency level.
9. Sanghi S: “Building Competencies,” Industrial Management 51, no. 3 (May–June 2009): 14–17.
> Proficiency levels and their definitions.
Advises the company on the strategic value and direction of the technology.Considered an authority on the technology by peers and company.
Proficiency Levels
Expert
Advanced
Skilled
Knowledge
Awareness
Applies the knowledge and skills, regularly and independently, in projectsand can demonstrate their use.
Has attended a relevant course or training that covers principles and canexplain and apply technology under supervision.
Recognizes a technology or technique, knows its purpose, can describe it and understands its value and limitations.
Advises others engaged in applying the skill and can teach or mentor others. Has applied the technology on numerous projects in several diverse, complex areas.
> Competency management. Competency management is a process that responds to customer company objectives and business needs. NExT SMEs and company representatives gather technical requirements, which are based on the current corporate and business objectives. They align the competency framework with the technical needs and then create processes and job profiles that represent the projects and position competency requirements. Working with NExT, the company assesses its staff and evaluates the gaps between required and actual proficiencies. Last, NExT and the company design a roadmap to close these gaps in the short term and provide a plan for long-term career development. As the company’s business changes, the human resources department realigns the models.
Define job profiles and requiredproficiency levels
Identify skill gaps anddevelopment needs
Prepare appropriate competencymatrices by function
Perform self-assessments
Define business needs
Competency Management
Update
Begin
Conduct interviews with experts
Recommend development options
Review process
Spring 2013 9
its human resources (HR) department to acquire, develop and manage talent.
The first task for the HR department was to evaluate the current level of employee expertise, assess each employee’s skill set and define spe-cific job roles within the organization (right). The department also needed to understand the skill gaps that existed and to align and develop skill sets commensurate with business objectives; the HR department had to conduct this process to understand how to attract, develop, engage and retain talent for the company and cultivate future technical leaders within the organization. The HR department also needed to identify those with technical leadership and establish a struc-tured system to transfer knowledge from senior to junior staff.
The HR department required quantifiable measurement points to determine the business value of this process. Business value may come in the form of direct and indirect benefits. Direct benefits include accelerating personnel develop-ment and improving retention of those with key skills in the company. Indirect benefits include engaged employees who are empowered to take control of their careers.
The company approached NExT to assist with talent management. NExT SMEs teamed with the company SMEs to define job profiles and compe-tency matrices for each domain represented in the organization.
For the first step of the process, early career staff—those with one to seven years of experi-ence—completed individual self-assessments, and the SMEs created skill assessment reports for each participant. The HR department provided the SME team with background information for each participant, including job assignment, years of experience, education level and place of educa-tion. This background information helped the team compare skill levels of participants with skill levels based on industry requirements. The team then conducted skill assessment interviews that enabled the team to validate each participant’s self-assessment, and the results of the interviews allowed the team to update the self-assessment reports (right). The team of NExT and company SMEs then planned multiyear training actions for each participant. Plans included courses, work-shops, learning-by-doing programs, self-study and on-the-job coached project work.
Through the competency assessment pro-cess, the company has aligned job functions with its business objectives, compiled required job profiles, defined proficiency requirements,
Attract talent
Developfuture leaders
Alig
n co
mpetency
Assess competencies
Develop talent
with
bus
iness
What do we needto accomplish?How much do we needto accomplish?
M
Are we developing enoughtechnology and businessleaders?
M
How are we doing?Where are we inthe process?
MWhat entry level skills do we desire?Is our developmentprogram attractive totargeted employees?
M
What skills are needed to deliver business?What is technicalperformance?
M
Measurementrequired
M
3
2
3
4
1
>Talent development steps. Counterclockwise from upper left, talent development starts with the development of competency models—a combination of competencies and job profiles that are aligned with the needs of the business (1). The company must attract the correct talent (2), which is a continual process and is influenced by business needs and the alignment of competency models with them to help with recruitment of both midcareer staff and new graduates. The keys to building talent are skills assessment and personnel career development (3). Using the competency models, a company assesses existing talent, establishes the gaps in proficiencies and uses the gaps to develop training options and plans for employees. Finally, through this process, the company identifies, develops and nurtures its future leaders (4). The measurement points (M) identify questions that must be quantified to determine the progress of development.
> Gap analysis of job trainee population. Every job has skills that an employee must perform at required proficiency levels (black dots). A group of job trainees undergoes competency assessment, and the trainees’ final adjusted assessment scores are aggregated and averaged (X). Gaps (blue) and strengths (green) in the trainees’ proficiencies provide the data to establish training targets for improving the group’s skills and to identify talent within the company.
Reservoir production geology
Skill elements
Proficiency Level
Non
e
Awar
enes
s
Know
ledg
e
Skill
ed
Adva
nced
Expe
rt
Formation evaluation
Fluid flow through porous media
Properties of petroleum fluids
Well performance prediction
Well test design and interpretation
Data management
Geology
Petrophysics
Decline curves
Unconventional reservoirs
Reserves determination
Gas reservoir engineering
Petroleum economics
Analytical techniques
Reservoir management principles and practices
Secondary recovery process
Immiscible and miscible gas injection
Subsurface integration
Interactive real-time data transmission
Simulation-model construction and history matching
Simulation-model behavior forecast
Simulation compositional modeling
Simulation of complex, dual-porosity systems
GapStrengthRequired levelAssessed levelX
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
10 Oilfield Review
completed roadmaps for training and develop-ment and established benchmarks for assessing talent and training. The company has learned what skill sets are required for individuals to do their jobs now and in the future. The company became cognizant of the baseline skills for their current staff, and as a result, established a training plan for closing the skill gaps (above).
As the independent oil company grows and redefines itself, the HR department has a road-map for aligning and managing its talent to fit its business objectives. The competency matrices will facilitate the company’s ability to foster and reward performance and optimize its ability to attract and retain talent. The employees should then have a complete understanding of the per-formance drivers within the organization, which will help them develop their careers.
Maximizing Software ProficiencyWhen companies experience rapid growth, they sometimes need to restructure to adapt to their expanded size and activity. A medium-sized North American independent oil company had to con-tend with growing pains as it sought to expand operational activities and add seasoned technical and managerial staff. The company also intended to adopt the latest field and software technolo-gies. In doing so, it recognized the need for effec-tive software training and thus provided generous training opportunities for its technical staff.
Embracing the most current software tech-nologies is a tactic for increasing efficiency and productivity of PTPs on exploration, operations and asset teams. To benefit from changes in
software technology, employees must have a good technical foundation in science and tech-nology along with skills for using specific soft-ware products championed in the company. NExT was called in to assess the company’s training environment, including the organiza-tion’s structure, technologies used, types of training offered, current competencies of the staff and anticipated technology needs.
To begin its evaluation, NExT interviewed the company’s management to understand the orga-nization, its current business outlook and its expectations for technology in the future. NExT placed parameters on these expectations to develop metrics—standards of measurement—to assess experienced employees, defined as those with 10 years or more in the industry. Most respondents had been with the company for 10 years or less but had more than 10 years of industry experience. A sample group of these employees took a survey that measured their cur-rent proficiency with the company’s software technologies and workflows. The company expected experienced PTPs to be proficient with technology, yet the survey revealed gaps in skills and abilities that provided NExT with the data necessary to establish targets for improvement.
Assessment results also revealed that the cur-rent technology training program was not provid-ing desired benefits to the company (next page, top right). The self-assessment surveys showed that few people were highly proficient in software usage. Follow-up interviews confirmed these findings. Some PTPs used only basic functions provided by the software and, because they lacked awareness and knowledge of software capabilities, these PTPs did not use other soft-ware applications.
Survey results suggested that, with few excep-tions, the company software training program was not meeting the technical requirements of employees. Employees’ software proficiency needed to be aligned with domain experience, and targeted training had to be designed to fill gaps between assessed and expected software proficiency. Knowledge transfer could also be facilitated by fostering a climate in which junior staff members feel comfortable asking for help and expert staff are expected to mentor, coach and transfer knowledge to junior staff.
The surveys and interviews identified employ-ees’ concerns regarding the current state of the organization; their own learning, competency and software usage; and standard practices sur-rounding software technology. The survey and interview results suggested that the company’s
> Gap analysis. This summary of gap analyses from a population of one company’s production engineering employees revealed areas where training should be focused to eliminate gaps (blue) in proficiency. The analysis also showed some expertise within well completions, as this element showed the highest strength (green). For each production engineering skill, the bars summarize four statistics of the deviations of assessment from required proficiency—maximum, minimum, average (red dot) and median deviation. Zero deviation means that the assessed proficiency equals the required proficiency for the skill element. Positive deviations are strengths—when the assessed proficiency is greater than the required proficiency. Negative deviations are gaps—when the assessment is less than required. The boxes along the bars show the central tendency of the deviations; they are black when the median is less than the average and gray when the median is greater than the average. The spread of deviations results from the mix of backgrounds and experience in the sampled population.
Deviation of Assessment from Required ProficienciesSkill Elements
–4 –3 –2 –1 0 1 2 3 4
Production impediments
Safety and environment
Special topics
Surface production operations
Unconventional completions
Well completions
Well control
Well evaluation
Well intervention techniques
Well performance
Sand control andstimulation techniques
GapStrength
Spring 2013 11
lack of a software vision and strategy had led to haphazard adoption of software. NExT recom-mended the following strategic solutions to address these concerns:
strategies and industry best practices
critical to the company mission as well as soft-ware recognized to be E&P industry standards
-mended software, organized by workflow and discipline
within asset teams to transfer knowledge of assets, facilitate peer-to-peer training and fos-ter a sense of technical achievement.
After implementing various recommenda-tions, the company saw measurably positive returns on its training investment.
Accelerated LearningAramco Gulf Operations Company and Kuwait Gulf Oil Company formed Al-Khafji Joint Operations (KJO) in 2000 to operate jointly and share equally in hydrocarbon production from the Saudi–Kuwaiti neutral zone between the bor-ders of Saudi Arabia and Kuwait. KJO wanted to expand its exploration activities. However, it faced an acute shortage of trained PTPs. To accelerate its training of exploration PTPs, KJO contracted with NExT to develop a blended train-ing program for new hires and midcareer engi-neers and geologists.
NExT developed two training programs, one designed to train 20 new hires over three years and the other to train 20 midcareer PTPs over two years. Both programs started with a trainee competency analysis followed by gap analysis. These data formed the bases of blended learning curricula featuring theory and software courses, on-the-job training (OJT), workshops, field trips, mentoring sessions, projects and project manage-ment training. The programs included verifica-tion of training effectiveness to gauge competency growth and individual participation.
The new-hire program focused on training seven engineers and five geoscientists in sub-surface geology and eight engineers in surface facility operations. The goal was to develop semiautonomous professionals who were able to operate at a skilled proficiency level. The three-
year curriculum evolved from 100% classroom training at the start of the first year to 90% OJT by the end of the third year. Building a founda-tion of core competencies in each subject domain was the purpose of Year 1. Training included a blend of instructor-led and self-directed learning and field trips. During Year 2, the focus moved to strengthening core compe-tencies in each trainee’s primary discipline through advanced coursework, mentoring by peers and experts and starting OJT projects. By
the end of Year 3, trainees were expected to achieve proficiency and autonomy in their job function, to be fully engaged in OJT under struc-tured mentoring by experts and to be responsi-ble for project assignments.
The new-hire program started in October 2010. After the first year devoted primarily to coursework, the trainees’ competency rose from an awareness level of 1.55 to a knowledge level of 2.04 (below).10 After three years, trainees were expected to be at the skilled level of 3.
> Self-assessed software proficiency and technology fit. Fifty geoscientists at one company participated in self-assessment surveys about their software proficiency and understanding of how the software fit with their job workflow. The bubble size corresponds to the number of respondents. The bubble colors and numbers represent average scores on software proficiency (left) and fit to job workflow (right). Software proficiency is low across the experience spectrum. However, the respondents rated the software as being appropriate for their jobs. These findings suggest that low software proficiency results from inadequate training rather than from inappropriate software.
9.0 1.0
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9: High 5 to 8: Medium 1 to 5: Low 1 to 2: High 2 to 3: Medium-high 3 to 5: Medium-low
> Return on KJO investment in training. Competency models and measurements provide a standard for assessing skill levels and ensuring that training is fit for purpose. The range of improvement in the trainees’ competency since their initial assessments was 18% to 47%. This result gives the company confidence that the training program is working.
Overall 1.55 2.04
Subsurface engineering 1.55 2.01
Surface engineering 1.50 2.21
Subsurface geology 1.61 1.90
Domain Initial Assessment End of Year 1
10. The competency proficiency scale levels are the following: not aware 0, awareness 1, knowledge 2, skilled 3, advanced 4 and expert 5.
12 Oilfield Review
Based on lessons learned during the first year of training, NExT and KJO will modify the new-hire program. The ability to modify such training programs illustrates the flexibility of the NExT system. Rather than starting the program with a year of classroom coursework and ending with principally OJT, the new program will include a richer mix of classroom and hands-on training from the outset—from 60% classroom training at the start to 80% OJT by the end. Program partici-pants indicated that staggering the courses and mixing in hands-on training would be more effec-tive and would also facilitate learning and reten-tion of course material. During 2013, KJO expects to hire 30 recent graduates; these new employees will follow the modified training regimen.
The program for midcareer hires focused on training seven geoscientists and nine engineers in geology and reservoir engineering and four engineers in drilling engineering. The goal was to develop participants into autonomous profession-als, able to operate at an advanced to expert level and be responsible for conducting a full field development plan. NExT training professionals designed a two-year curriculum that began with 100% classroom learning and concluded with 100% onsite mentoring. During the first year, the trainees took preliminary courses to fill in gaps in the group’s knowledge and combined their disci-plines to collaborate on fully integrated multidis-ciplinary projects. In addition, individualized courses resolved gaps in trainee education and functional knowledge.
During the second year, each trainee was assigned to one of three integrated field develop-ment training projects following consultation with mentors and KJO management. NExT SMEs designed each integrated field development training project to last approximately four months. In the first two weeks, the trainees con-ducted an initial project assessment and took part in a project management course. During the following seven weeks, participants attended courses on the theory and workflows related to field development plans, including subsurface reservoir geology and geophysics, surface facili-ties, predictions of production and field opera-tions and maintenance. In the final eight weeks, the trainees planned a field development project and worked on a subset of data from a general development plan. The trainees concluded the program with a final project and a presentation to KJO management. After these training proj-ects, each midcareer trainee is expected to capi-talize on knowledge gained and become a contributing member of an asset team.
The midcareer hire program was completed in 2012. The successor to this program is the KJO Specialist Talent Development Program (STDP), which is open to high-potential national employ-ees with at least seven years of industry experi-ence. STDP is a competency-based development program with the goal of transforming employees skilled in a discipline into specialists or experts. For the new program, each participant is evalu-ated for acceptance into the program based on competency level, then each phase of that per-son’s individualized development plan will be evaluated by KJO SMEs.
The new hire and STDP programs are important to KJO because these programs eliminate the knowledge and skill gaps created as experienced employees depart KJO through retirement and attrition. For KJO, the pro-grams help to build PTP leaders, develop young qualified PTPs into skilled PTPs who can work independently and enable the company to become less reliant on external specialists.
Unconventional Talent for Shale PlaysSaudi Aramco collaborated with NExT to train and develop expert PTPs in unconventional gas resource (UGR) exploitation. The company made a commitment to an accelerated training pro-gram to train asset teams of engineers and geo-scientists for the UGR group. The training program emphasized integrating trainees into coherent asset teams, in which each team mem-ber has a core discipline competency and also has familiarity with the other team members’ disciplines.
A typical training program begins with com-petency assessments of trainees. However, in this case, candidate trainees received general over-view coursework on shale gas geoscience and engineering. Based on their coursework evalua-tions, the candidate teams of geoscientists and engineers were selected for UGR training.
The trainees then underwent baseline compe-tency assessments evaluating their knowledge of the geoscience and petroleum engineering of shale gas resources. Following assessment, they began their UGR training, a blend of 20% learn-ing, 20% technology exposure and 60% on-the- job training.
The program began with a focus on the fun-damentals of UGR technology. This curriculum consisted of instructor-led coursework covering shale play geology, geophysics, petrophysics,
geomechanics, reservoir engineering, well engi-neering, completions and stimulation, produc-tion engineering and water management.
Following the classroom component, the geo-science and petroleum engineering trainees focused on their core technologies, although each group was exposed to the technologies of the other group through cross-disciplinary training. Such training ensured that all participants under-stood the role of each technical discipline since interdisciplinary teamwork is vital for UGR exploi-tation and reservoir management.
The heart of the training program was an extended period of practical OJT. Trainees were expected to conduct tasks on actual shale play datasets and apply knowledge gained from classroom and software training. The trainees, separated into their geoscience and engineer-ing groups, were rotated through diverse paral-lel projects in various Schlumberger facilities.
In conjunction with OJT, the trainees partici-pated in the following:
data under the supervision of industry shale experts
-ine openhole logging tools, wellhead assem-blies, drill bits and other technology
and correlate them with software-based geol-ogy models
resource technology.Following OJT, the groups came back
together to work as asset teams on integrated facilities and shale play asset management proj-ects. Each asset team member shared responsi-bility for the successes and failures of projects and learned the economics of unconventional gas resources using a mixture of theory and soft-ware to analyze datasets.
At the end of the program, each asset team evaluated an integrated project and produced a report detailing how it would manage the asset. Each team presented its report to a panel of industry SMEs, who graded the team.
Each trainee underwent a closing competency reassessment to measure and verify improvement in proficiency in shale play geoscience and engineering. The improvement in the trainees’ skill proficiencies, which was quantified by the reassessments, demonstrated the return on investment from the UGR training program.
Spring 2013 13
Multidisciplinary LearningThe Saudi Aramco training program focused on acquiring capabilities needed to develop shale plays. In addition to conventional instructor-led training, the program exposed trainees to enabling technologies, field operations and on-the-job practice, culminating in trainees working through a scenario from a real project. This par-ticular program will enable Saudi Aramco to accelerate the capabilities of its PTPs to exploit UGR opportunities.
Unlike Saudi Aramco, many companies in North America have mature shale play busi-nesses. Even so, some companies may still need to expand their employees’ capabilities in shale play technologies. Based on recommendations
>Multidomain shale training program. This 12-week training program (left) consists of parallel geoscience and engineering tracks. The training is a blend of theory, data analysis and interpretation (right), site visits to operations, geology field trips, laboratory visits and projects. The order of training proceeds from bottom to top. Geoscientists and engineers begin together learning the fundamentals of shale plays. Their tracks diverge for several weeks. At the end of the program, the trainees come back together to learn the economics of shale plays, form asset teams and work on common pilot projects. Finally, the teams give presentations to industry SMEs, who grade the trainees on their evaluations and recommendations for the projects.
Introduction toshale plays
Theory Data analysisand interpretation
Geologyfield trips
Laboratoryvisits
Projectapplication
Site visits
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Basin modelingof shale plays
Shalepetrophysics
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Oilfield watermanagement practicesfor shale plays
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Completion andstimulation of shale
and feedback from participants and mentors of the Saudi Aramco program, in addition to discus-sions with SME advisors from US-based compa-nies, NExT designed a 12-week multidisciplinary shale training program, which is expected to be available during the fourth quarter of 2013 (above). Each part of the 12-week program is a blended learning-by-doing module. In addition, customer companies may provide their employ-ees with additional OJT in shale play resource exploitation and management.
The solution to development and accelera-tion of petrotechnical learning is to maximize its efficiency, practicality and effectiveness. NExT uses blended learning-by-doing and competency management to achieve these objectives and
help bridge the talent gap in the E&P industry. Learning-by-doing combines learning modes based on customers’ business objectives and technical challenges, while competency man-agement ensures that the training is efficient, targeted and effective. Using these techniques puts E&P businesses of all sizes on the path to sustainable talent development and puts their PTPs on the road to proficiency. —RCNH
14 Oilfield Review
Structural Steering—A Path to Productivity
The number of oil and gas wells drilled horizontally continues to increase as
operators strive to maximize contact with target formations, develop more-efficient
completion programs and optimize recovery from complex geologic structures.
Structural steering, a method by which operators direct horizontal and high-angle
wellbore trajectories, integrates data from deep-reading LWD resistivity tools
and high-resolution imaging devices to create structural models of the geologic
conditions encountered by the drill bit. This technique allows drillers to correct
wellbore trajectories in anticipation of structural changes ahead of the bit and helps
operators better understand the formations already drilled.
Aimen AmerEast Ahmadi, Kuwait
Filippo ChinellatoMilan, Italy
Steve CollinsChief Oil & Gas LLCDallas, Texas, USA
Jean-Michel Denichou Sugar Land, Texas
Isabelle DubourgClamart, France
Roger GriffithsPetaling Jaya, Selangor, Malaysia
Randy KoepsellDenver, Colorado, USA
Stig LyngraSaudi AramcoDhahran, Saudi Arabia
Philippe MarzaAberdeen, Scotland
Doug MurrayAbu Dhabi, UAE
Iwan (Bob) RobertsDhahran, Saudi Arabia
Oilfield Review Spring 2013: 25, no. 1. Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Danny Hamilton, Frisco City, Texas; Remi Hutin, Clamart, France; Emmanuelle Regrain, Houston; and Haifeng Wang, Stavanger.CMR, eXpandBG, eXpandGST, FMI, FPWD, MDT, MicroScope, PeriScope, Petrel and PowerDrive are marks of Schlumberger.
The drilling of oil and gas wells today has little in common with the early days of exploration when wildcatters punched holes, sometimes based on seemingly random patterns, in hopes of discovering untapped resources. Today, modern drilling engineers access an array of technologies to visualize the subsurface and then command sophisticated downhole hardware to precisely target reservoir sections. After analyzing data from various sources, well placement engineers can adjust wellbore trajectories while drilling to maximize reservoir contact. Service companies
continue to introduce new technologies that help operators drill wells that produce longer, drain the reservoir more completely and improve return on investment.
The ability to drill high-angle and horizontal well trajectories has been one of the most signifi-cant changes in drilling in recent years. Although horizontal wells typically average two to three times the cost of conventional vertical wells and involve higher risks, the proportion of horizontal wells continues to increase (below). For exam-ple, in the US at the end of 2012, 63% of the
> Horizontal drilling in the US. The number of wells drilled horizontally, as a percentage of the total number of wells drilled in the US, has increased sharply in the past decade. (Data used with permission from Baker Hughes.)
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16 Oilfield Review
1,817 wells being drilled were classified as hori-zontal and another 11% were labeled directional wells. Only 26% of the wells were classified as vertical.1 A primary reason for this shift to hori-zontal and high-angle wells is that they bring potential short- and long-term rewards that ver-tical wells cannot typically provide. Through a single wellbore, high-angle and horizontal wells can improve drainage, access discrete compart-ments in complex reservoirs, reduce interven-tion costs, improve efficiencies and provide exposure to more of the reservoir. Despite their higher initial costs, horizontal wellbores often provide operators with a method for developing reservoirs that otherwise might not be profit-able. Horizontal wellbores are especially impor-tant in unconventional reservoirs where their use has been a key enabling technology in devel-oping shale resources.2
These improvements in drilling technologies and practices have transformed the way operators approach developing resources.3 In the early days of horizontal drilling, wells were constructed based primarily on geometric well plans. When some wells were not optimally placed in target zones, results were often disappointing. Today, geoscientists and drilling engineers understand that the term horizontal drilling is an oversimplification of the process, and accurate well placement involves more than turning a well 90° from vertical. Maximizing reservoir contact and understanding subsurface geometry and
geology are crucial components of successful drilling operations.
Technological advances in LWD formation evaluation tools are also making it possible for engineers to achieve well placement objectives more effectively. Tools that probe the formation some distance from the wellbore allow drilling engineers to visualize complex subsurface geom-etry. Engineers use real-time, high-resolution image data to define structural geometry and pro-actively adjust drilling programs. LWD measure-ments also help operators differentiate intervals that have superior production characteristics from those that may not be profitable.
To optimize the horizontal drilling process, well placement engineers have developed work-flows that help them in the quest to realize drill-ing objectives. Even before the well is spudded, these workflows play a role in helping geologists and engineers identify targets and develop realis-tic trajectories that avoid unnecessary drilling complications. While drilling, the well placement team can update models with real-time informa-tion utilizing a 3D approach.
These new technologies and workflows may not always provide the answer. The critical ele-ment in determining which well type performs best is the drilling team’s understanding of how reservoir geology impacts long-term performance of the well. In many high-permeability reservoirs, particularly during the early phase of develop-ment, vertical and horizontal wells may perform
equally well, which makes vertical wells more attractive because of lower costs. In a recent study from a complex, naturally fractured reser-voir, vertical wells produced with higher oil rates and lower water cuts than horizontal wells.4 This phenomenon was a result of waterflood maturity and unique reservoir geology.
Nevertheless, recent drilling and geosteering technology developments have allowed access to resources for which conventional vertical or geo-metrically drilled horizontal wells would not have worked as well. This article discusses LWD tools that provide data directly impacting drilling pro-grams, software for visualization of subsurface geometry and a workflow operators use to optimize well placement through structural steering tech-niques. Examples from a gas storage project in Italy, an unconventional reservoir in the US and a thin carbonate reservoir in the Middle East dem-onstrate how operators are optimizing well place-ment and more effectively accessing reservoirs and resources.
Dimensions of DrillingTechnological advances in drilling were key fac-tors in the sharp rise in the number of horizontal and directional wells in the 1990s. In 1986, there were 41 horizontal wells drilled worldwide (below left).5 Just four years later, in 1990, there were 1,190 horizontal wells drilled, the majority of which were in Texas, USA. More than 20% of those wells were concentrated in the Austin Chalk formation. Activity in this formation epito-mizes the evolution that has occurred in horizon-tal drilling.
The Austin Chalk is a low-permeability and low-to-moderate–porosity reservoir. The first wells were drilled in this formation in the 1920s. Production of oil and gas in commercial quanti-ties relied on the well intersecting existing inter-connected fractures. To enhance production from vertical wells, operators introduced new technologies with varying degrees of success. These technologies included acid treatments to open pathways from the wellbore to existing frac-ture networks, seismic interpretation to locate fracture clusters and hydraulic fracture stimula-tion to increase wellbore connectivity to natu-rally occurring networks.
In the 1980s, operators began experimenting with lateral well extensions, usually by reenter-ing existing nonproductive wells. Because this approach allowed the wellbore to contact many more fractures than was possible with the original vertical well, spectacular production increases often ensued.
> Horizontal drilling before 1995. In 1986, only 41 wells worldwide were classified as horizontal. A dramatic increase in these numbers occurred between 1989 and 1990, driven by technological improvements and by the resultant increases in production experienced by some operators drilling horizontal wells. Although at the outset the trend was primarily in the US, operators in other regions, especially Canada, also drilled more horizontal wells. (Adapted from Kuchuk et al, reference 5.)
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Some experts have attributed the global growth in horizontal drilling to the successes and lessons learned in these and other Texas wells.6 However, not all horizontal wells drilled in the Austin Chalk formation experienced dramatic increases in production. Many operators failed to take into account the complex nature of the for-mation, which included compartmentalization and subseismic faults that divided the Austin Chalk into multiple isolated reservoirs.
Today, operators use extensive reservoir mod-els to extrapolate surface and downhole data and predict the formations that horizontal wellbores will encounter. This approach attempts to iden-tify rock of better reservoir quality, and where
applicable, of better completion quality. However, until a well is drilled, the model, which is a func-tion of the type and quality of available data, remains an approximation.
Well Placement MethodsDownhole hardware for drilling horizontal wells has improved considerably over the past decades, and well placement methodologies and work-flows have been developed to capitalize on new technologies and drilling techniques. With these improvements, well placement methods continue to evolve. Today, three complementary methods are generally used in well placement.7 The first method is characterized as model, compare and
update and is a reactive drilling process. The sec-ond relies on estimating and extrapolating the orientation of bedding planes from formation dip data, usually with azimuthal measurements acquired while drilling. The third method relies on deep-reading directional data for remote boundary detection to proactively adjust the well-bore trajectory to maximize reservoir contact and avoid exiting target zones.
In the model, compare and update method, the well placement team first generates a model of logging tool responses based on expected for-mations observed in offset log data (above). Seismic data interpretations are included in the analysis to help geologists estimate the location
>Model, compare and update method of well placement. Log data from offset wells are used to construct geologic and tool response models. Geologists generate geologic models by first squaring the original data, creating layer columns and labeling formation markers and surfaces (top left). Formation markers and layering are propagated from offset well data to create a geologic model (bottom left), which may also be enhanced with seismic data. A forward modeling program predicts how logging tools, such as a resistivity tool, will respond to formation properties (red, top right). Once the model is generated, a well trajectory (green, bottom right) is proposed to target specific reservoir layers. As the horizontal well section is drilled, the measured response (blue, top right) observed from the well is compared with the modeled response. (Adapted from Griffiths, reference 7.)
Geologic Model
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1. Baker Hughes: “Interactive Rig Counts,” Investor Relations, http://gis.bakerhughesdirect.com/RigCounts/ (accessed February 13, 2013).
2. Alexander T, Baihly J, Boyer C, Clark B, Waters G, Jochen V, Le Calvez J, Lewis R, Miller CK, Thaeler J and Toelle BE: “Shale Gas Revolution,” Oilfield Review 23, no. 3 (Autumn 2011): 40–55.
3. For more on the evolution and innovations in drilling technology: Felczak E, Torre A, Godwin ND, Mantle K, Naganathan S, Hawkins R, Li K, Jones S and Slayden F: “The Best of Both Worlds—A Hybrid Rotary Steerable System,” Oilfield Review 23, no. 4 (Winter 2011/2012): 36–44.
Bennetzen B, Fuller J, Isevcan E, Krepp T, Meehan R, Mohammed N, Poupeau J-F and Sonowal K: “Extended-Reach Wells,” Oilfield Review 22, no. 3 (Autumn 2010): 4–15.
Williams M: “Better Turns for Rotary Steerable Drilling,” Oilfield Review 16, no. 1 (Spring 2004): 4–9.
Downton G, Hendricks A, Klausen TS and Pafitis D: “New Directions in Rotary Steerable Drilling,” Oilfield Review 12, no. 1 (Spring 2000): 18–29.
4. Widjaja DR, Lyngra S, Al-Ajmi FA, Al-Otaibi UF and Alhuthali AH: “Vertical Cased Producers Outperform Horizontal Wells in a Complex Naturally Fractured Low Permeability Reservoir,” paper SPE 164414, presented at the SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, March 10–13, 2013.
5. Kuchuk F, Nurmi R, Cassell B, Chardac J-L and Maguet P: “Horizontal Highlights,” Middle East Well Evaluation Review 16 (1995): 7–25.
6. Kuchuk et al, reference 5.7. Griffiths R: Well Placement Fundamentals. Sugar Land,
Texas, USA: Schlumberger (2009): 10.
18 Oilfield Review
of formation boundaries. The team may use 3D visualization software that usually includes plan-ahead functionality to develop wellbore trajec-tory and drilling programs. Real-time data acquired while drilling either validate the model or are used to update it in response to the new information (left). The directional driller can then make changes in the wellbore trajectory based on the updated model.
The second well placement method requires an understanding of the orientation and magni-tude of the formation dip. After interpreting azi-muthal data from wellbore images, well placement engineers are able to estimate and extrapolate the orientation of the target bed or formation. The bit is steered to remain within the target. If the bit is no longer in the target reser-voir layer, the LWD data can be used to determine whether the bit has exited the top or the bottom of the reservoir, and the directional drilling engi-neer can apply corrections to steer the bit back toward the target (below). When the wellbore crosses a fault and leaves the reservoir, this tech-nique may not be effective because the engineer must know which direction to proceed to recon-nect with the target, and azimuthal data alone may not provide that information.
In the third method, well placement engi-neers use remote boundary detection to proac-tively determine the direction in which to steer the bit. Deep azimuthal measurements give
> Tracking the model. Well placement engineers and geologists may create software models of logging tool responses from anticipated subsurface geology. The gamma ray (green, top) and shallow resistivity data (blue, middle) are tracking the modeled response (red), which would indicate that the 2D model for well trajectory (bottom, green) is valid. Differences between the modeled and measured deep resistivity data (log data, bottom) may indicate that the well trajectory will need to be adjusted, although the deep resistivity data are again tracking at the current bit position.
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>Well placement using formation dip data. Azimuthal log data in the shapes of smiles and frowns help well placement engineers determine bit corrections. When a wellbore crosses a bedding plane, an azimuthal logging tool response indicates whether the wellbore is exiting an ascending or descending geologic layer. When the wellbore cuts an ascending layer (left), the first contact with the formation is at the bottom of the hole (bottom left); when the bit exits the layer, the last contact will be at the top of the hole. When the bit cuts an ascending layer, the data appear as a frown in the image. Conversely, measurements from a wellbore that exits a descending bedding plane appear as a smile (right). The bit can be guided up or down based on these interpretations to ensure that the wellbore remains in or reconnects with a target zone.
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Spring 2013 19
early warning of approaching changes in the target and surrounding layers (right). This tech-nique works best when there is sufficient resis-tivity contrast between the bounding layer and the target. Drilling programs that optimize drainage, access untapped compartments and steer clear of potential water sources are some of the primary beneficiaries of this type of pro-active drilling. In thick reservoir sections or in low-contrast environments, this technique may not be as effective. Complex geologic environ-ments, such as faulting and folds, are also prob-lematic for this technique.
Another well placement technique, structural steering, extends the capabilities of these three methods. It replaces geometric assumptions about planar surfaces with geologically informed predictions of structure based on observed well data (below right). Whereas most well placement techniques focus on geometry, structural steering uses some aspects of the traditional methodolo-gies but attempts to resolve geologic complexi-ties with LWD data, some of which have only recently become available in real time.
Structural Steering Workflow Directional drilling is defined as the science of steering a wellbore along a planned path to a tar-get located at a given lateral distance and direc-tion. Structural steering, which leverages information from LWD services, is the process of combining structural analysis and modeling capabilities with borehole images to create 3D models that operators use to optimize well place-ment, often in real time. By incorporating geo-logic models created with new software tools and developing greater trust in interpretations that might not fit original drilling programs, operators are able to make real-time decisions based on structural steering methodologies.
One example of software that enables well placement by means of structural steering com-bines two plug-ins used in the Petrel E&P soft-ware platform: eXpandBG near-wellbore to reservoir scale modeling and the eXpandGST real-time geosteering module. Real-time data from the MicroScope resistivity- and imaging-while-drilling service can be combined with deep mea-surements from the PeriScope bed boundary mapper tool to provide structural analysis and modeling capabilities.
Using data from tools that provide deep-read-ing capabilities along with those that acquire real-time borehole images, geologists at Schlumberger have developed a structural steering workflow that provides a framework for well placement
> Distance to boundary (DTB) technology for well placement. Real-time distance to boundary mapping technology uses directional measurements and large depth of investigation (DOI) to determine the distance to adjacent layers above and below the well path. For DTB technology to be used effectively, resistivity contrasts between adjacent beds must be present, and the adjacent beds must be within the measurement window. Resistivity data from deep-reading LWD services, such as the PeriScope tool, can be inverted and the values converted to colors. Contrasting colors highlight the differences in bedding plane properties. Data are processed and presented in such a way as to give the appearance of curtains, giving rise to the name curtain display. When the well position relative to adjacent beds is known, the bit can be steered by making adjustments to the drilling assembly to point the bit in the desired direction (blue) so that the wellbore stays within target zones or returns should the trajectory exit from a target. Had the planned trajectory (green) been followed, this well would have exited the target zone (light colors).
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> Structural steering for well placement. Structural steering incorporates reservoir modeling and distance to boundary technology in conjunction with high-resolution imaging to manage drilling decisions. From these data, geologists create 3D models, such as the one shown, which help directional drillers visualize the formations around and ahead of the bit. This is especially useful for predicting subsurface geometry and for guiding the bit in complex reservoirs with faults and folds.
20 Oilfield Review
decisions (left). The interpreter picks the dis-tance to boundaries, and the boundaries are dis-played on an eXpandGST curtain section. Image data from tools such as the MicroScope service provide bedding dip, fracture information and fault detection.
The eXpandBG module imports the LWD log-ging data, and engineers generate an updated model that includes drilling polarity logs. Polarity logs indicate whether the well is heading toward the bottom or toward the top of a structure. The software next computes a true stratigraphic thickness (TST) index; TST is related to the thickness of the reservoir section. Well place-ment engineers can compare structural dips while the drilling progresses with those in the original model and quickly identify anomalies. The software projects the structural dip away from the well using stratigraphic horizons, and the geologist can label formation tops and strati-graphic surfaces. Armed with this information, the well placement team can determine whether corrections are required and in which direction to steer.
Two crucial elements for structural drilling are LWD data that can be used to develop realis-tic models and software that can provide a robust solution describing the reservoir. Without real-time data, engineers and geologists may have difficulty understanding the geometry of the subsurface and accurately projecting where the next step should be taken. Unfortunately, engineers must often make decisions with insuf-ficient data about complex reservoirs. Until recently, the tools for resolving these complexi-ties did not exist for LWD operations, but this is no longer the case.
8. Borghi M, Piani E, Barbieri E, Dubourg I, Ortenzi L and Van Os R: “New Logging-While-Drilling Azimuthal Resistivity and High Resolution Imaging in Slim Holes,”
, Structural steering workflows. Prejob planning for structurally steered wells begins with geologists creating a structural model from offset well logs, which may be from a vertical pilot well (top). Data are correlated to determine the location of formation tops and geologic markers. These data are then propagated away from the vertical well, and a well trajectory is created based on the expected subsurface geometry. As the well is drilled, well placement engineers use real-time analyses of dip data to steer the well. They may use true stratigraphic thickness (TST) profiles to determine distances from marker beds and make adjustments in well placement. When the well reaches TD, the job is not finished. Models are updated with the newly acquired data, completions and designs can be optimized and new well plans may be developed to maximize recovery (bottom).
Postjob Evaluation and Deliverables
Well PlacementTST Profiling
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presented at the 10th Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 23–25, 2011.
Spring 2013 21
Tools of the TradeAlong with modeling software and drilling hard-ware, LWD tools are experiencing an evolution in design and function. Originally, LWD tools repli-cated information available from conventional wireline logging tools, which are designed pri-marily to obtain high-quality petrophysical data essential for reservoir characterization. Modern LWD tools still provide petrophysical information and have the advantage that data are acquired before the formations have been exposed to drill-ing fluids, which over time can alter rock and fluid properties. However, the real-time aspect of LWD operations is creating a divergent path in tool development.
Service companies are introducing LWD tools that probe regions deeper in the formation than is customary with wireline tools. New tool designs also make it possible to acquire data at the bit. With a wide swath of the formation around the wellbore illuminated by these measurements, drillers can precisely position the wellbore to optimize production or injection performance.
Application of data from these new tools has the potential to fundamentally change the way directional wells are drilled. For example, well placement engineers can use information pro-vided by deep-reading tools to help steer the well within a narrowly defined target zone. Using deep-reading measurements and TST processing, engi-neers can now manage the direction of wellbore trajectories based on surrounding structures rather than conditions very close to the wellbore.
For fractured reservoirs, such as the Austin Chalk and many shale plays, the reservoir section may be tens or even hundreds of meters thick, and well placement may be more focused on intersecting fracture networks than staying in a narrow zone. Imaging tools that provide high-resolution measurements can confirm the pres-ence of fractures and perhaps lead to redirecting or redrilling wellbore sections that are not opti-mally placed. Conversely, to prevent early-onset water production, fracture and fault avoidance may be the objective in some reservoirs. Engineers use these same imaging tools to iden-tify fractures and faults and to accurately charac-terize their orientation.
Because these measurements, especially wellbore imaging, involve large amounts of data, and LWD data transmission rates are orders of magnitude below those of wireline logging sys-tems, the primary source for imaging data has been wireline tools. Recently, LWD data trans-mission systems and imaging tools have been introduced that can replicate the capabilities of
wireline tools for detecting fractures and faults and determining their orientation. No longer are separate logging runs required to obtain this information, and drillers can make decisions while the drilling assembly is still in the hole.
Resolution EvolutionMost LWD tools transmit data to the surface using mud pulse telemetry (MPT). Although today, data rates are often given in megabits/s and terabits/s, mud pulse telemetry systems orig-inally offered data rates in the single-digit bit/s (bps) range (above). Because LWD tools have the ability to continuously transmit data uphole while drilling, giving them the benefit of having more time to acquire and send data than their
wireline counterparts, service companies have found ways to overcome inherently low MPT rates. However, data-intensive measurements, such as those associated with borehole imaging, were almost always performed with wireline log-ging tools because the logging cable offered the ability to transmit data at sufficiently high rates.
Modern LWD MPT systems transmit at higher rates—some systems can approach 128 bps. These enhanced transmission speeds, together with new methods for data compression, have opened up a new world of possibilities for real-time data acquisition. One tool that has benefited from higher data transmission capabilities is the MicroScope service (below).8 Acquiring data from focused azimuthal sensors while rotating,
> Transmission rates with mud pulse telemetry (MPT). LWD tools transmit and receive data using mud pulses encoded with data. Early MPT systems had transmission rates in the single-digit bit/s range. Although these rates have increased in the past few decades, LWD data transmission rates are two orders of magnitude below that of wireline logging tools. For some operations, LWD data must be stored in memory and retrieved when the tools are back at the surface. Downhole storage is typical for LWD measurements that require large amounts of data such as high-resolution images. New data compression techniques, combined with higher data transmission rates, now make it possible to acquire some of these data in real time for operations such as structural steering.
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>MicroScope tool. The MicroScope LWD logging tool provides four laterolog resistivities, four borehole image measurements and two toroidal resistivities. The tool also includes inclination and azimuthal gamma ray measurements. High-resolution borehole images from the tool can be used to define structural conditions. From these data, faults as well as fractures can be identified. Because the tool provides high-resolution information at multiple depths of investigation (DOIs), natural fractures can often be differentiated from shallow drilling-induced fractures. Toroidal resistivity measurements are useful for determining drilling conditions and identifying formations at the bit.
Azimuthal gamma ray
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22 Oilfield Review
the tool provides images of the borehole compa-rable to those of wireline tools such as the FMI fullbore formation microimager. An added bene-fit of the MicroScope tool is that it can provide high-resolution resistivity images at different radial depths of investigation, which allows engi-neers to distinguish natural fractures from drilling-induced fractures.
The tool uses toroidal antennas as transmit-ters to send axial currents along the collar and into the formation for resistivity measurements. Two electrode buttons mounted at opposite sides of the collar provide borehole coverage as the tool rotates. The current leaves the tool surface, is directed through the conductive drilling fluid into the formation and returns to the button elec-trodes.9 Once corrected for borehole effects, the
measurement of current is a function of the for-mation conductivity (and its reciprocal, resistiv-ity). The buttons measure azimuthal resistivity in 56 separate bins distributed around the borehole circumference, and the orientation of the button measurements is determined with respect to the Earth’s magnetic field, which is measured with an azimuthal orientation system mounted per-pendicular to the tool’s axis.
The full array of measurements has depths of investigation approximately 2.5, 7.6, 13 and 15 cm [1, 3, 5 and 6 in.], measured radially out-ward from the tool surface. These data can resolve bedding planes and features as small as an inch. Although FMI images can resolve smaller features, which are useful for texture analysis and characterization of fractures, MicroScope image data compare favorably with FMI images (above).
A bit resistivity measurement, derived from two antennas at the bottom of the tool, is also available. One antenna acts as a transmitter and the other as a monitor. Current flows out from the bit and returns farther up the toolstring. The drillstring below the antennas acts as an elec-trode, and the measured current depends on the formation resistivity and mud properties.
Other than the large amount of data needed to provide images, one of the biggest challenges of producing high-resolution images using LWD tools is the conversion of time-based to depth-based data. Traditional LWD measurements are indexed to pipe movement observed at the drilling floor. This technique is not adequate for detection of small formation features because drillpipe movement at the surface may not reflect small tool movements downhole. Scientists at Schlumberger have introduced a new algorithm to derive local depth information based on tool revolutions rather than observed pipe movement.10
For this technique, high-resolution data, along with magnetometer-based tool orientation, are recorded versus time. These data can be viewed as strips with a constant and known thick-ness. Converting the time-based measurements to a depth-indexed image requires precise esti-mations of the azimuthal and axial position of the sensors. As the tool advances, overlapping strips are merged and then correlated to axial tool movement. The technique provides a high-resolu-tion depth match (next page, top). The images are then transmitted to the surface with minimal resolution degradation.
Well placement engineers also use measure-ments with greater depths of investigation than those of wireline logging tools to identify dis-tances to top and bottom boundaries of reservoir sections. These measurements help engineers plan wellbore trajectories so they remain within target intervals. The PeriScope bed boundary mapper makes a 360° measurement and can detect beds as far as 6.4 m [21 ft] from the bore-hole. Tilted receiver coils that have directional sensitivity can determine bed orientation. As long as there is sufficient resistivity contrast between target beds and those adjacent to the zones of interest, the PeriScope tool can provide crucial information about the position of the wellbore in the formation.11
Modern well placement requires more than determining the location and orientation of the bit within a target zone. If faults are encoun-tered, well placement engineers may not have
>Wireline versus LWD imaging. Data from wireline imaging tools, such as the FMI tool (left), have been the standard, even though running these tools in horizontal wells can be time consuming and may result in added risk of sticking. Recently introduced LWD imaging tools, such as the MicroScope tool, provide images (right) with a quality comparable to that of wireline tools, often in real time or stored for surface retrieval. (Adapted from Allouche et al, reference 10.)
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sufficient information from deep-reading tools alone to understand the geometry required to guide the bit back to the target. Integrating high-resolution image data with data from deep-reading tools helps geologists construct a 3D picture of the structure surrounding the well-bore and can often help directional drillers decide where to go next and how to reconnect with the reservoir if the wellbore trajectory exits the target interval (right).
Resolving ComplexitiesDuring the past decade, gas production from organic-rich shales has become a global pursuit; this phenomenon has been driven in large part by hydraulic stimulation and horizontal drilling. The conventional approach to developing these resources is to drill a vertical pilot well followed by a horizontal sidetrack targeting the shale interval. Because of the complex geologic struc-tural settings in many of these plays, some well-bores may exit the pay zone or encounter rock with poor reservoir quality. Although seismic data are frequently used to resolve reservoir com-plexities, in many cases these data lack the reso-lution to adequately define subsurface features. A new 3D structural technique, which includes the application of eXpandBG modeling, was recently utilized in a Marcellus Shale well oper-ated by Chief Oil & Gas LLC.12
9. The MicroScope tool is designed for use in conductive muds.10. Allouche M, Chow S, Dubourg I, Ortenzi L and van Os R:
“High-Resolution Images and Formation Evaluation in Slim Holes from a New Logging-While-Drilling Azimuthal Laterolog Device,” paper SPE 131513, presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, June 14–17, 2010.
11. For more on the PeriScope tool and bed boundary mapping: Chou L, Li Q, Darquin A, Denichou J-M, Griffiths R, Hart N, McInally A, Templeton G, Omeragic D, Tribe I, Watson K and Wiig M: “Steering Toward Enhanced Production,” Oilfield Review 17, no. 3 (Autumn 2005): 54–63.
> Correlating high-resolution measurements to depth. LWD logging depths are referenced to pipe measurements taken at the surface. For most data, this is an acceptable acquisition method. However, the accuracy of this method is not sufficient for high-resolution measurements. To compensate for shortcomings of traditional depth measurements, engineers at Schlumberger developed a technique that uses overlapping strips from images (left) to create an internal depth reference based on known fixed distances between sensor buttons on the tool. Correlation takes into account the mismatch between tool movement downhole (middle, blue) and surface movement (black). The resulting correlated images (right) are much improved compared with the noncorrelated images. (Adapted from Borghi et al, reference 8.)
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> Data integration. Geologists use real-time images (top) to identify faults and determine dip direction; these data are then used to explain geologic conditions. Geologists may also use DTB measurements to help generate models of subsurface layers (bottom). The integration of these data allows directional drillers to modify planned well trajectories (green) to maximize reservoir contact and determine the optimal path (blue) to return the wellbore to the target (yellow) should the wellbore encounter unexpected conditions such as faults and folding.
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Bourgeois D, Tribe I, Christensen R, Durbin P, Kumar S, Skinner G and Wharton D: “Improving Well Placement with Modeling While Drilling,” Oilfield Review 18, no. 4 (Winter 2006/2007): 20–29.
12. Amer A, Collins S, Hamilton D, Gamero H, Contreras C and Singh M: “A New 3D Structural Modeling Technique Unravels Complex Structures Within the Marcellus Shale: Utilizing Borehole Image Logs,” presented at the AAPG Eastern Section Meeting, Washington, DC, September 25–27, 2011.
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Constructed with data from the pilot well, the original model indicated a syncline plunging to the northwest and an anticline plunging to the southeast toward the toe of the proposed lateral section. Engineers at Chief Oil & Gas proposed a well trajectory based on this interpretation from the vertical pilot well.
The horizontal section was drilled using only LWD azimuthal gamma ray data. After the lateral was drilled, borehole images were acquired on wire-line with an FMI tool. The interpretation provided by eXpandBG processing highlighted significant dif-ferences between the original reservoir model and the geologic structure observed in the well.
The eXpandBG approach solves for geometric complexities without the need for extensive input by the interpreter. The software can also create
structural models using multiwell data for input. In this example, formation dip was computed using the local curvature axes technique to pro-duce the eXpandBG structural model.13 Solutions using this technique may not be unique; however, the interpreting geologists may intervene and adjust the solution to fit with other data such as 3D seismic interpretations.
Geologists with Chief and Schlumberger analyzed dip sequences in both the pilot well and the subsequent horizontal section and clas-sified structures using the local curvature axes technique on a Schmidt plot to resolve the structural complexity. Contrary to the original model, the new model revealed three distinct sections: an asymmetrical anticline, a highly tilted block and a third section characterized as gently tilted (above).
Based on the dips identified in the vertical well, the formation was assumed to be gently dip-ping to the NNW at 5°. The well was to be landed in the target interval and follow this trend. However, the lateral was actually landed at a fold axis where the structure immediately turned down to the south at 24°. The well soon exited the reservoir section and crossed a fault, eventually reconnecting with the reservoir but in a section that dipped in the opposite direction, north at 25°. The well encountered a second fault and was then back in the target formation; drilling contin-ued along the path indicated by the original structural model. Unfortunately, because the for-mation was dipping more steeply than had been modeled, the well exited the bottom of the Marcellus Shale earlier than expected.
A review of the well path validates the need for real-time structural data while drilling. With only azimuthal gamma ray data available for interpreting the formation structure, the drilling program did not produce an optimal well path. Had imaging and deep resistivity data been acquired with LWD tools in real time, the resul-tant drilling and completion programs may have been quite different.
One final step in the modeling process involves validation with Petrel geologic recon-struction software. This suite enables restora-tion and forward modeling of complex folded and faulted geologic models. By simulating mechanical rock behavior with a comprehensive set of boundary conditions, the software allows the user to analyze complex structures. The software confirmed the viability of the complex present-day interpretation (next page, top). Newly acquired 3D seismic data also validated the structural model.
Production from this well was classified as dis-appointing compared with that in nearby wells. Had the structural model been updated using LWD images, the well path may have been modi-fied or perhaps redrilled based on the new model. Similarly, the four-stage stimulation design may have been more effective (next page, bottom). Only Stages 2 and 3 were completely within the target zone. Stages 1 and 4 covered zones that were in the target for only half the interval. Additionally, a section of the Marcellus Shale at the heel of the well was not stimulated, although it coincides with a highly stressed interval around the fold where FMI data indicated the presence of natural fractures, which often enhance produc-tion in shale reservoirs. In this case, real-time structural data may have resulted in a well trajec-tory that contacted more of the target formation and led to better well production.
> Complex Marcellus Shale model. The original reservoir model (inset) was created by propagating formation tops picked from pilot hole data, and well placement engineers designed a well trajectory based on the model. The actual structure was quite different. The lateral well was landed in what was thought to be a gently upward sloping (5° NNW) layer cake formation. However, before reaching horizontal, the well crossed a fold axis with steeply dipping beds, and then exited the target interval. Although the directional driller hoped that continuing to drill would help determine which way to steer the well, the well soon crossed a fault; the fault block was lifted and tilted relative to the previous section and was also dipping in the opposite direction. The well reconnected with the target interval only to cross a second fault. Fortunately, the well was still within the Marcellus Shale, and drilling continued close to the originally projected angle based on the pilot hole, from which it was assumed that the formation dipped 5° NNW. The well exited the bottom of the target earlier than expected because the formation was dipping more steeply (8° NNW) than projected. The directional driller had little help determining how best to steer this well because only azimuthal gamma ray information was available for guidance. Geologists later loaded image data, acquired with an FMI tool, into the eXpandBG module of Petrel modeling software, which generated an interpretation that explained why the well failed to encounter the reservoir as expected.
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Steering for StorageA structural steering workflow that did use real-time LWD data and eXpandBG processing was recently employed in an underground gas storage project carried out by Stoccaggi Gas Italia (Stogit) SpA, the gas storage division of Società Nazionale Metanodotti (Snam). The multifield, multiwell project was developed with the techni-cal contribution of Eni SpA specialists. The objec-tive of the drilling program was to expose as much reservoir section with optimal properties as possible in the shortest well length.14 To that end, wells were drilled and steered using real-time LWD data.
As is the case in many areas of Italy, horizon-tal drilling is challenging because of steeply dip-ping beds, faulting and abrupt stratigraphic changes. The reservoir section of the Furci field is characterized as a limited extension Pliocene turbidite system. It includes several sand bodies with smaller interbedded laminations. The pro-cedure for drilling wells in the field followed a predetermined workflow. The operator chose horizontal targets, and well placement engineers loaded the well plan into the eXpandGST module in the Petrel E&P software platform, which was populated with log properties from a vertical pilot well. The program created a forward mod-eled log to predict log responses for several sce-narios such as a formation dip that was higher or lower than expected. These scenarios would indi-cate that the well was in a different part of the reservoir than planned.
For the second of two wells drilled in the field, the target consisted of two large sand lobes separated by two shale beds. The objective was to drill through the shallow sand lobe, cross the thin shale beds and navigate into the deeper sand lobe. The operator drilled the vertical pilot hole as planned and then began the horizontal section following the predetermined trajectory.
Geologists determined formation dips by using two independent tool systems: a deep-read-ing bed boundary PeriScope tool and a borehole imaging MicroScope tool. These measurements provided information about faults and bedding that cut across the borehole. As horizontal drill-ing commenced, the PeriScope tool indicated flat dip and then a slightly rising inclination. A sud-den decrease in resistivity appeared to indicate
13. Amer et al, reference 12.14. Borghi M, Loi D, Cagneschi S, Mazzoni S, Donà E,
Zanchi A, Boiocchi D, Gremillion J, Chinellato F, Lebnane N, Lepp R, Chow S and Squaranti S: “Well Placement Using Borehole Images and Bed Boundary Mapping in an Underground Gas Storage Project in Italy,” presented at the 10th Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, March 23–25, 2011.
> Structural balancing and restoration. To confirm the validity of an interpretation created using the eXpandBG model, structural balancing and restoration modeling must be performed. Assuming the original layer cake geometry (top), the model is exposed to postdepositional loading using Petrel geologic reconstruction software. Early-stage compression (middle) produces the complex geometry observed, and later uplift explains the present-day condition (bottom). This last modeling step validates the interpretation generated by the eXpandBG software.
Uplift results in localized extension
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> Completion results. The operator designed the stimulation program for the Marcellus Shale well based on interpretation of the azimuthal gamma ray data; the program was developed before the revised structural model, shown here, was created. Of the four stages shown (magenta), only Stages 2 and 3 were wholly within the target zone. Stages 1 and 4 were only partially in the Marcellus Shale. No treatment was applied to the heel of the well (dashed white oval) where fractures were identified, which engineers viewed as a missed stimulation opportunity. The operator considered the performance of this well disappointing compared with that in offset wells.
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26 Oilfield Review
that the trajectory had crossed the upper lobe and the middle shale sections and was approach-ing the lower lobe; however, geologists inter-preted the image data as indicating the well had crossed an unexpected fault and was now in an upthrown section (above).
Drilling through the upthrown section con-firmed the fault interpretation, and eventually the wellbore crossed a second fault and again encountered the reservoir section. Log data acquired after the trajectory crossed the second fault indicated that the well was penetrating the lower sand lobe, and the drilling team made the decision to incline the bit to more than 90° and reconnect with the upper lobe.
The well crossed back through the shale lay-ers and eventually reached a downdip section of the upper sand lobe. After crossing the first fault, the original well trajectory would have missed the lower lobe entirely, and a large portion of the
well would have been drilled through the shale layers that separated the lobes. The updated trajectory, modified using real-time LWD data, intersected both lobes and maximized wellbore contact with the reservoir section.
Shale Drilling In a Niobrara Shale exploration well in northeast Colorado and southeastern Wyoming, USA, engi-neers used the structural drilling workflow to resolve complex geologic conditions in a shale well.15 The Niobrara Shale play is an upper Cretaceous calcareous shale that produces oil and gas. The shales are composed of argillaceous limestones with interblended chalk, marl and bentonite. Because of the rock’s low permeability and porosity, production is generally higher in zones with natural fractures enhanced by hydrau-lic stimulation.
The typical development scenario for Niobrara Shale wells is to drill a vertical pilot
hole and acquire petrophysical data using logging tools on wireline. For evaluation wells, the log-ging program usually consists of resistivity, neu-tron and density porosity, elemental capture spectroscopy and nuclear magnetic resonance (NMR) tools. Borehole image logs are run for fracture identification and geologic characteriza-tion. Acoustic logs may be run for mechanical properties, which are used in fracture stimula-tion design and wellbore stability estimations. Operators often include conventional coring for the pilot wells to determine lithology and describe fractures. Data from the pilot holes are used to characterize the reservoir, define the ori-entation of target zones and identify the optimal depth for landing the lateral section.
15. Koepsell R, Han SY, Kok J, Munari M and Tollefsen E: “Advanced LWD Imaging Technology in the Niobrara—Case Study,” paper SPE 143828, presented at the SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, June 14–16, 2011.
> Complex geology in an Italian gas storage well. The targets for this horizontal well were two sand lobes separated by shale layers. The original model assumed a layer cake geology, and the drilling engineers developed a trajectory (green) to pass through the upper sand lobe, cross the shale layers and terminate in the lower lobe. Instead of encountering continuous layers, the actual trajectory (blue) encountered a fault, entered an uplifted section below the target sand lobes and crossed another fault before reconnecting with the lower sand lobe in a downthrown section. After drilling through a section of the lower sand lobe, the well placement engineers turned the well upward and then it again crossed the shale layer and reconnected with the downward-dipping upper sand lobe. Traditional petrophysical measurements—resistivity (Tracks 2 and 3), gamma ray (Track 4) and formation density (not shown)—did not provide much directional guidance. In addition, had engineers used only DTB data from the PeriScope tool (red and blue dots, bottom), they would have had difficulty determining directional adjustments. Image data from the MicroScope tool (top) allowed geologists to identify the faults and determine dip direction and correctly steer the well. Without the two complementary measurement systems, engineers would have had difficulty determining in which direction to steer the well after it crossed either fault. (Adapted from Borghi et al, reference 14.)
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Spring 2013 27
Logging objectives in the horizontal section differ from those of the vertical pilot wells. Fracture population density, type and orientation are needed for stimulation design. Measuring the wellbore path and orientation are crucial, espe-cially when the well crosses in and out of reser-voir layers. Identifying faults and determining their location and orientation aid completion
design. Engineers identify zones with structural complexity to help them keep the wellbore in the reservoir unit or determine the best path to reconnect if the well exits the target. Depositional variations can be determined with LWD tools, and geologists use these data to adjust models that extrapolate properties from the pilot well.
Traditional methods of acquiring image data in the lateral section require that drillpipe- conveyed wireline tools be deployed. Geologists used these data to identify the presence of natu-ral fractures and quantify their orientation and density. However, high-resolution image data from the MicroScope tool eliminate the need for separate wireline logging runs (above).
> Resolving complex geology. Image data from the MicroScope tool can be presented in dynamic (Track 2) or static (Track 4) mode. Formation dip (top, Track 1) can be handpicked from images or computed from these data. The green tadpoles indicate the down direction of the dip, 0° to 360° clockwise around each tadpole, which represents north-east-south-west-north. The magnitude of dip is also computed and can be read from the log. The magenta tadpole indicates a fracture and provides its orientation. The image data can be presented in a wrap mode that simulates the horizontal well (inset). Bedding planes (green), faults (magenta), open fractures (blue) and healed fractures (cyan) can be visualized as they appear in the horizontal wellbore. (Adapted from Koepsell et al, reference 15.)
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28 Oilfield Review
tures at an azimuth of 104° and with a length of approximately 2,400 ft [730 m].
The MicroScope tool provided real-time high-resolution images for structural and fracture anal-ysis. Engineers created 3D models using eXpandBG software, which helped them optimize well place-ment and design hydraulic stimulation operations. The MicroScope image data were particularly use-ful in revealing the complex structural setting. In addition to numerous open and healed fractures, geologists identified numerous faults, a missing section and structurally deformed beds (below).
The planned well trajectory, developed from pilot hole and surface seismic data, resulted in the well crossing a fault and exiting the target zone into unproductive marl sections below the target. The last half of the well was below the C bench and was drilled mostly in nonreservoir quality ductile shale. After these data were ana-lyzed, the well was sidetracked and redrilled through most of the interval and steered higher in the structure based on the new model.
The logging results affected a number of the engineers’ decisions for the completion program for the sidetrack well. For instance, the program called for openhole packers for isolation. Engineers identified washed out and elliptical borehole sections and avoided setting packers in these zones. Packers were not set near faults, which can affect the quality of the seal as well as impact stimulation results. For similar reasons, packers were not set in open natural fractures,
> Stepping out from vertical. Geologists can identify the location and orientation of bedding planes and faults in vertical wells and project them away from the wellbore, but horizontal wells often encounter unexpected geologic geometry. In this vertical well section (top), geologists identified several geologic sections, including the target reservoir C bench section, which is a mixture of chalk and marl bounded by ductile shales and unproductive chalks and is part of the Niobrara formation. Well placement engineers developed a trajectory to follow the target, and directional engineers landed the lateral well in the C bench (bottom, expanded section). Horizontal drilling proceeded for approximately 2,350 ft [716 m] and the well encountered structural geometry that differed from geologists’ expectations. The well (black) crossed at least seven major faults (magenta lines). After the first set of faults, the C bench was found to be upthrown, which positioned the well in the lowest part of the reservoir. As drilling progressed, the well crossed a fifth major fault and was below the target formation and completely out of the reservoir. After geologists developed the new model of the horizontal well, the operator pulled back to the first fault section and redrilled the horizontal section with an orientation (not shown) that carried the well above the original trajectory; this repositioning allowed the well to remain in the target interval. Geologists can also use dip data to identify other features. The stereonet plots shown across five of the intervals can be used to identify fracture and fault type and orientation. The far left plot shows the NNW by SSE orientation of healed fractures, probably resulting from folding. (Adapted from Koepsell et al, reference 15.)
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An operator in the Denver-Julesburg basin began a campaign to develop the Niobrara formation with multistage hydraulic fracturing in horizontal wells. From the vertical pilot well logs, geologists were able to confirm the presence of a
target layer known as the C bench. The image data indicated open fractures with strike popula-tions oriented NW-SE and mineralized fractures striking NNE-SSW. To maximize intersection with the natural fractures, the horizontal well section was planned perpendicular to the natural frac-
Spring 2013 29
which were also identified in image data. Fracture stimulations were performed in stages, and the stages were designed to target similar rock types identified from petrophysical data. Stimulation designs also included consideration of local stresses that resulted from formation structural complexity.
Drilling Between the LinesUnconventional resources may require approaches for drilling and completions that differ from those for conventional reservoirs, but conventional res-ervoirs can benefit from application of unconven-tional solutions. Saudi Aramco used the real-time structural steering workflow with eXpandBG and eXpandGST processing to access resources that oth-erwise would have been difficult to produce eco-
> Pilot hole logs. An oil-bearing carbonate reservoir section was identified from openhole logs acquired in a pilot hole drilled at a 30° angle. The pay zone (gray shading) was less than 20 ft [6 m] thick based on measured depth. Corrected for well deviation, the true vertical thickness would be even less than shown. Fluid mobility, determined from NMR (Track 5) and MDT data (not shown), indicated a small permeable streak within the interval. The well placement team proposed drilling a horizontal well that would be steered using PeriScope and MicroScope tools. Directional drillers use petrophysical measurements to guide them in steering wells, but there was insufficient variation in the gamma ray (Track 1), resistivity (Track 2) or porosity (Track 3) within the target zone for these to be used. A high-resistivity caprock overlying the zone, however, provided a boundary layer for reference in steering the well.
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nomically. The carbonate reservoir consisted of a thin, permeable layer sandwiched between low-permeability intervals overlain by a thick, nonpo-rous carbonate caprock.
The well was drilled in a mature giant field located in Saudi Arabia.16 Historically, this field has produced mainly from two major carbonate reservoirs. In the early 1980s, two smaller strati-graphic oil accumulations were discovered. The example well was drilled in the larger of these two reservoirs. The discovery was further delin-eated and tested by several vertical wells. The low-permeability reservoir contains good quality light oil with a relatively high gas/oil ratio.
In early 2012, Saudi Aramco drilled the first reservoir development well, deepening an exist-ing dead producer originally completed in the
main producing horizon. The pilot hole was drilled as a 30° slanted well across the reservoir section, and Saudi Aramco carried out an exten-sive data acquisition program that included cor-ing the full reservoir interval.
Porosity and resistivity in the zone of interest were fairly uniform; the operator used a CMR combinable magnetic resonance logging tool to identify the presence of movable oil (above). An MDT modular formation dynamics tester con-firmed that only a thin layer within the zone had
16. Al-Suwaidi SH, Lyngra S, Roberts I, Al-Hussain J, Pasaribu I, Laota AS and Hutabarat S: “Successful Application of a Novel Mobility Geosteering Technique in a Stratified Low-Permeability Carbonate Reservoir,” presented at the SPE Saudi Arabia Section Annual Technical Symposium and Exhibition, Al-Khobar, Saudi Arabia, May 19–22, 2013.
63952schD5R1.indd 29 6/25/13 4:41 PM
30 Oilfield Review
>Well placement and job execution. Within the oil-bearing carbonate zone of interest, engineers confined the target to a narrow permeable streak (bottom, yellow) bounded by lower-permeability oil-bearing layers (tan). The drilling objective was to guide the well maintaining a constant distance from the high-resistivity, low-porosity caprock (green) overlying the reservoir. Resistivity (Track 4) and porosity (not shown) data exhibited little variation across the interval. For guidance, engineers used PeriScope curtain data (Tracks 7 and 8) to maintain the DTB. Geologists also used MicroScope image data (Track 3) to detect subtle changes in orientation and formation dip (Track 2). Well placement engineers proactively corrected the well trajectory based on polarity data (Track 6, red indicates drilling up structure, green indicates drilling down structure). Because fluid mobility and permeability were the properties that differentiated the target interval from the rest of the zone of interest, an FPWD tool was included in the LWD logging suite. Mobility measurements were acquired at irregular intervals along the well (blue circles, Track 1), but after validating the presence of fluid mobility for approximately 1,700 ft [520 m], engineers removed the FPWD tool from the string because of concerns about tool sticking. The well placement team steered the well for approximately 2,900 ft [884 m] (bottom, blue) and stayed within the narrow window throughout the interval.
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Spring 2013 31
good mobility and would produce oil. From the log data, petrophysicists determined that the permeable layer was less than 10 ft [3 m] thick and was positioned about 6 ft [1.8 m] below the high-resistivity caprock layer. Log analysts were uncertain whether the zone with high mobility extended farther out in the reservoir or was sim-ply a stratigraphic anomaly.
Even if the zone extended into the reservoir, engineers knew that effectively producing from such a small interval in the pilot well would be difficult. Thus, they designed a horizontal pilot producer to more effectively drain the reservoir. Challenges included using real-time data from LWD tools to verify the presence of the high-mobility zone and stay within this narrow, high-permeability window. Porosity and resistivity logs provided little help in identifying the zone with the best mobility.
The technical team determined that the best course of action was to drill the well with a trajec-tory that maintained a constant standoff or dis-tance from the overlying caprock. The standoff was based on distance to boundary (DTB) mea-surements computed from a PeriScope tool. The team relied on true stratigraphic thickness (TST) data to maintain a constant position relative to the caprock location. Well placement engineers with Schlumberger were able to compute TST in real time using eXpandBG processing of formation dips picked from MicroScope images. Saudi Aramco personnel used these interpretations to instruct the directional driller in the proper direction to guide the PowerDrive rotary steer-able system.
Based on results from the pilot hole, NMR data were judged to be insufficient to identify the zone with mobility. Consequently, an FPWD formation pressure while drilling tool was used to confirm that the wellbore trajectory remained in the high-mobility streak. To ensure that the wellbore followed subtle changes in dip and direction, the geosteering staff used interpreta-tions from borehole images acquired with a MicroScope tool.
Geologists created a 2D structural model from pilot well data and forward modeled logging responses for the LWD tools. The well placement team landed the well near the interval, steering the well stratigraphically upward to attain the required distance to the upper boundary. Once the data from eXpandBG processing confirmed the required trajectory, the well was drilled main-taining the proper orientation (previous page).
FPWD data were acquired for the first 1,700 ft [520 m] and confirmed that the chosen path was following the high-permeability streak. Each FPWD mobility test required leaving the drilling assembly stationary for 20 min. Significant over-pulls began to occur after each mobility test, and the FPWD tool was removed because of opera-tional concerns related to hole conditions and sticking. The remainder of the well was then drilled using only DTB and TST data from eXpandBG and eXpandGST processing to deter-mine corrections to the wellbore trajectory. Images from the MicroScope tool helped estab-lish the formation dip and were a key input in the interpretation. The horizontal interval covered approximately 2,900 ft [884 m] and remained within a 4-ft [1.2-m] sweet spot window for the entire interval.
The well confirmed that the high-permeabil-ity streak was not a stratigraphic anomaly and extended far out into the reservoir. The well was tested after completion and produced at a rate of several thousand bbl/d. Further evaluation is ongoing, but early analysis confirms that because the well followed the high-permeability path, resources were accessed that otherwise might have been difficult to produce economically.
Knowledge Is PowerAt one time, horizontal drilling was an exercise in geometry and drilling technology. However, as well placement techniques and practices have evolved, LWD tools have been introduced that provide well placement teams with a better grasp of geologic and subsurface structural conditions. Integrating downhole data into modeling soft-ware provides operators with the ability to visual-ize subsurface complexities. This knowledge gives operators powerful tools to modify drilling plans, alter wellbore trajectories and optimize completion programs.
Service companies continue to add to the assortment of LWD tools that may have been considered impractical for the drilling environ-ment in the past. Pressure sampling, downhole seismic acquisition and acoustic logging devices were once considered to be beyond the capabili-ties of tools used while drilling. Just as these services have been accepted by the industry, high-resolution measurements that image the borehole and result in large amounts of data are now becoming available. Proper interpretation of these data has the potential to alter the way wells are drilled; such drilling is no longer based primarily on geometry but optimized for down-hole structural conditions.
Structural steering involves more tools and requires more data for analysis than conven-tional drilling; in addition, the costs of structural steering are higher. But the answers provided by the tools and data to engineers and geologists have the potential to reveal better access to more of the reservoir, enhance recovery and pro-duce more hydrocarbons. Structural steering may not be the answer for every well, but the opportunity to resolve the complexities of down-hole geology offers operators a tremendous tool for enhancing resource recovery. —TS
32 Oilfield Review
New Dimensions in Wireline Formation Testing
Operators have had difficulties obtaining pressure measurements and samples
with conventional wireline formation testers in certain formations and reservoir
fluid types. Engineers have recently developed a tool for reliable testing even in
challenging environments such as low-mobility formations and heavy oil.
Cosan Ayan Paris, France
Pierre-Yves CorreAbbeville, France
Mauro FirinuEni SpA E&PRavenna, Italy
Germán GarcíaMexico City, Mexico
Morten R. KristensenAbu Dhabi, UAE
Michael O’KeefeLondon, England
Thomas PfeifferStavanger, Norway
Chris TevisSugar Land, Texas, USA
Luigi Zappalorto Eni Norge SAStavanger, Norway
Murat ZeybekDhahran, Saudi Arabia
Oilfield Review Spring 2013: 25, no. 1. Copyright © 2013 Schlumberger.ECLIPSE, MDT, Quicksilver Probe and Saturn are marks of Schlumberger.
1. For more on WFTs: Ayan C, Hafez H, Hurst S, Kuchuk F, O’Callaghan A, Peffer J, Pop J and Zeybek M: “Characterizing Permeability with Formation Testers,” Oilfield Review 13, no. 3 (Autumn 2001): 2–23.
Spring 2013 3333
Engineers seeking to characterize reservoirs and design completions for maximum production effi-ciency depend heavily on analysis of downhole reservoir fluid samples and transient pressure testing. But identifying mobile fluids and defining hydrocarbon columns can be difficult in complex formations. Reservoir engineers and petrophysi-cists use a variety of data to make accurate reserves estimates and create representative res-ervoir models. These include fluid composition, pore pressure measurements, reservoir tempera-ture, reservoir response to pressure changes and integration of seismic data.
In the past, most formation fluid samples were captured after they reached the surface during drillstem tests and production well tests and were then separated into gas, oil and water
components. These samples were transported to offsite laboratories for analysis. Well tests con-tinue to provide engineers with useful data about reservoir fluids, reservoir size and produc-tion potential. But characterizing fluids from samples captured at the surface can be prob-lematic. Recombination of the separated fluids at the surface requires great care: It is often difficult for technicians to avoid contaminating the samples or inducing pressure losses during capture and transportation, particularly when working at remote locations; re-creating in situ conditions in the laboratory is difficult but nec-essary for accurate analysis.
In the 1950s, the industry began addressing these and other sampling difficulties by introduc-ing wireline formation testers (WFTs) that were
lowered on wireline logging cable to the zone of interest. One recent version of these tools uses dual straddle packers inflated above and below the sample point, or station, to isolate the forma-tion from wellbore fluids and to expose more of the formation for sampling (above left). Formation fluids are then flowed or pumped into the tool for capture and retrieval to the surface.
Probe-type WFTs use hydraulically operated arms to force a packer assembly against the borehole wall (above). The probe, located in the center of the packer, extends into the forma-tion, and then reservoir fluids flow or are pumped into the tool. The fluids are analyzed downhole, and samples may be captured while pressure is measured using downhole gauges. Fluids are analyzed for purity before being directed to the sample chambers. This allows contaminated fluids to be removed before wire-line engineers take formation samples. Sample bottles maintain the fluids at formation pres-sure to avoid phase changes while the samples are being retrieved to the surface for transport to a laboratory for analysis.1
> Dual straddle packer wireline formation tester (WFT). Some WFTs use hydraulic inflatable packers to seal the formation from contamination by borehole fluids during sampling and transient testing.
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> Probe-type WFT. Once a probe-type tool is on depth, the tool extends pistons from one side of the WFT against the wellbore wall, while a packer assembly is forced firmly against the formation to be tested. A probe in the center of the packer assembly then extends into the formation; the reservoir fluids flow through the probe into the tool’s flowline and sample chambers for retrieval to the surface. The packer seal, which surrounds the probe, prevents wellbore fluids from mixing with reservoir fluids.
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34 Oilfield Review
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WFTs often delivered fluid samples that were more representative of reservoir fluids than those captured on the surface. However, the probes used in early tools were not applicable in certain forma-tions where establishing a seal was difficult. In addi-tion, testing formations in which fluids move slowly to the tool prolonged the time the tool was on sta-tion and often resulted in samples that were con-taminated with excessive mud filtrate. Furthermore, highly viscous fluids can typically be mobilized through the formation and into the wellbore only by creating a relatively high differential pressure between the wellbore and the formation. This draw-down, or differential pressure, may exceed the rat-ings of the WFT packer or may cause the borehole wall in unconsolidated formations to fail, leading to loss of the seal around the packer assembly.2 A high pressure differential may also cause the pressure at the tool to drop below the bubblepoint pressure, inducing free gas and composition changes in the oil, which jeopardizes sample integrity.
In certain well conditions, it may be difficult to capture representative samples using standard single-probe WFTs because the sealing packer isolates the formation or the probe assembly only from drilling or completion fluids in the borehole. Fluids that have invaded permeable zones may also contaminate the sample. To acquire a rela-tively pure sample of reservoir fluids, engineers use a pumpout module—a miniature pump
included in the WFT toolstring—to flow or pump fluids from the formation through the tool and out to the wellbore until contaminants have been pumped away. The nature of the incoming fluids is analyzed downhole by a variety of sensors. Flow is then directed to sample bottles that capture and store fluids for transport to surface laborato-ries for analyses.
Under any condition, obtaining a representa-tive reservoir fluid sample can be a challenge because it can be difficult for engineers to know when the flow stream is sufficiently purged of contaminants. Engineers must rely on informa-tion about the reservoir and nature and amount of contaminant invasion to calculate the time it will take for the formation to clean up at a given flow rate. This calculation is further complicated because the flow from the reservoir streams in a conical volume toward the probe and draws con-taminants from the near-wellbore invasion zone as well as from some vertical distance along the wellbore. The outer edge of this flow stream may contain significant nonreservoir fluids, which may then require extended periods of time to be pumped away. Often, because engineers may underestimate the amount of time this process can take, they capture nonrepresentative sam-ples, or conversely, if engineers overestimate the time, they spend unnecessarily long and costly periods of time at the sampling station.
Innovations in WFT designs have done much to overcome these limitations. For instance, to shorten cleanup and ensure a representative sample, Schlumberger engineers developed the Quicksilver Probe focused extraction of pure res-ervoir fluid tester, which uses two concentric
sampling areas through which pumped fluids enter the tool. The outer ring is a conduit for the more contaminated outer segment of the flow stream, which is discarded to the wellbore. The inner probe draws fluids from the more represen-tative inner section of the conical flow, which may then be diverted into the WFT sample bot-tles (below).3
Another innovation, downhole fluid analysis (DFA), uses optical spectroscopy to identify the composition of reservoir fluid as it flows through the WFT. This technology allows engineers to determine contaminant levels and begin sam-pling only after these levels within the flow stream have reached an acceptably low value. When DFA is deployed at selected intervals within a well and in multiple wells, engineers gain previously unavailable data with which to perform reservoir architecture analysis.4
In addition to ensuring the purity of samples, these innovations shorten time on station, which may aggregate to significant savings in operating expenses. However, hurdles remain. This article discusses obstacles to capturing fluid samples in certain troublesome reservoirs and a new WFT probe that helps overcome these obstacles. Case histories from the Middle East, Mexico and Norway illustrate how the new tool facilitates fluid sampling in challenging environments.
The Continuing ChallengesIn most formation types, enhancements to WFT technology have greatly increased an operator’s ability to capture representative fluid samples suit-able for analysis while obtaining highly accurate downhole pressures. But operational constraints, unconsolidated sands, heavy oils and low-permea-bility rock still impact sampling success.
Traditional dual straddle packers offer one solution for these conditions. However, this solu-tion comes with operational concerns. In large holes, the packers require extended inflation times, and their relative positioning above and below the zone being tested creates a large sump volume. The effect of this storage volume can sig-nificantly extend cleanup times and create prob-lems for transient testing measurements in low-permeability reservoirs.5
In the testing of low-mobility formations, draw-down pressures during pumpout may become quite high. The resulting differential pressures can exceed existing straddle packer ratings of about 31 MPa [4,500 psi]. High differential pressures may also result from flowing high-viscosity fluid through unconsolidated sands, causing seal failure or even borehole wall collapse.
> Formation fluid sampling with the Quicksilver Probe focused sampling tool. The probe has two intake ports, the guard intake surrounding the sample intake (bottom left). Packers surround and separate these probes and seal against the borehole wall (right). Formation fluid is blue-gray and filtrate is light brown. When pumping begins, fluid flowing through the sample intake is highly contaminated (top left), but contamination levels quickly reach an acceptable value.
Spring 2013 35
Crumbling formations may also foil sampling operations when sand from the formation plugs the probe and flowlines. In addition, drilling through rock with low mechanical strength typi-cally results in a highly rugose wellbore wall with few sections of in-gauge hole against which to obtain a good packer seal.
To address these issues, engineers have increased probe size 10-fold over the years and devised probe shapes to better accommodate various formation types. Probes that create larger flow areas have increased success rates in tight formations and friable sands, and dual packer technology has increased the ratings for differential pressure to 40 MPa [5,800 psi]. DFA measurements also help ensure sample purity and enable a different set of complex fluid anal-yses than is possible on samples brought to the surface and transported to laboratories. The next step in the evolution of WFTs was recently introduced by engineers at Schlumberger with the development of a probe that provides a sig-nificantly larger flow area between the forma-tion and the tool while simultaneously providing a better sealing element.
A Radial Solution To address the limitations of differential pressure and issues of related seal and packer failures, Schlumberger engineers developed the Saturn 3D radial probe. This tool uses four elongated ports spaced evenly around the circumference of the module rather than a single probe or dual packers. The ports are individually isolated from the wellbore by a single inflatable packer that creates a large sealing surface against the forma-tion (right).
The packer used in the Saturn probe seals more reliably against a rugose borehole than sin-gle-probe WFT packers do and inflates and deflates more quickly than the dual straddle packers while completely eliminating sump volume. The four openings are embedded in the packer, and each is significantly larger than those on conventional probes, which further hastens cleanup.
Cleanup time—a primary component of for-mation test times—is the period required to flow the well until contamination of the reser-voir fluid flow stream has been eliminated or reduced to an acceptable level. One key to reducing prolonged test times is to shorten cleanup through higher flow rates. To test whether the Saturn probe design accomplishes this goal, reservoir engineers constructed a numerical model comparing cleanup time using the Saturn probe to those with a traditional
2. Drawdown is a differential pressure condition that induces fluids to flow from a reservoir formation into a wellbore. It occurs when the wellbore pressure is less than the formation pressure and may occur naturally or be created by pumping or producing from the well.
3. For more on the Quicksilver Probe tool: Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B, Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M, Tarvin J, Weinheber P, Williams S and Zeybek M: “Focusing on Downhole Fluid Sampling and Analysis,” Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.
> Saturn probe. The Saturn probe (top) captures reservoir fluid samples through four large ports spaced evenly on the tool’s circumference. The ports are pressed against the borehole when the packer that contains them is inflated, which creates a seal separating reservoir fluids from wellbore fluids. The tool geometry provides a radial flow pattern (middle, right) for reservoir fluids (green) and faster removal of contaminated fluids (blue). This differs from the flow pattern of a typical WFT (middle, left), which has a single opening on one side of the tool. The Saturn probe also has a flow area that is many times larger than that of traditional probes (bottom).
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area, in.2
0.15Surface flow
area, in.2
Saturn 3DRadial Probe
EllipticalProbe
Extra LargeDiameter Probe
Quicksilver ProbeProbe
Large DiameterProbe
StandardProbe
4. For more on downhole fluid analysis: Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H, Hegeman P, O’Keefe M, Peters K and Zuo JY: “Downhole Fluids Laboratory,” Oilfield Review 21, no. 4 (Winter 2009/2010): 38–54.
5. Wellbore fluid expansion and compression effects distort the reservoir response to pressure changes used in pressure transient analysis. A critical element of pressure transient analysis is distinguishing between the wellbore storage effects and the true reservoir pressure response.
36 Oilfield Review
extra large diameter (XLD) probe. The team used ECLIPSE reservoir simulation software on three probe configurations to test the proposi-tion. A fine grid was used to model the XLD and Saturn probes. For miscible contamination, investigators simulated a single-phase fluid sys-tem and represented the drilling fluid filtrate contamination using an embedded tracer. In addition, investigators conducted immiscible modeling for oil-wet and water-wet systems.
During the simulated tests, engineers consid-ered parameters such as permeability, anisotropy, viscosity contrast between filtrate and oil, disper-sion of the invasion front and extent of invasion. In a miscible contamination cleanup scenario, engineers found that although the breakthrough of formation oil is faster for the XLD probe, cleaner samples can be collected with the Saturn
3D radial module with less total volume pumped. In a simulation of immiscible contamination cleanup, mud filtrate viscosities of 1.0 cP [1.0 mPa.s] and 0.6 cP [0.6 mPa.s] were used. In scenarios using typical water- and oil-wet relative permeability, cleanup times to reach 5% contami-nation were similar to those for miscible contam-ination (above).6
Because mobilizing heavy fluids often gener-ates drawdown pressures high enough to cause weak formations to collapse, the combination of high-viscosity fluids in poorly consolidated sands constitutes one of the most formidable wireline formation testing challenges.
The behavior of fluid flow from the reservoir to the sampling tool is governed by Darcy’s law, in which flow is directly proportional to perme-ability, drawdown pressure and cross-sectional
surface area and inversely proportional to fluid viscosity and the length over which the draw-down is applied. By introducing a flow area about 40 times larger than that of traditional XLD probes, the Saturn probe reduces the nec-essary drawdown pressure to mobilize heavy fluids or fluids in low-permeability formations (next page, top).
In the past, traditional WFT options restricted operators to a choice between the higher draw-down and reduced flow rate of a traditional probe and the larger flow rate of a straddle packer. The disadvantage of lower flow rates is longer cleanup times. On the other hand, while dual packers allow higher flow rates than the flow rates of tra-ditional probes, they create large storage vol-umes and may lose seal because they cannot provide necessary borehole wall support in unconsolidated formations. The Saturn probe design provides the benefit of both a probe and a dual packer: a large flow area to reduce time to cleanup and a packer-probe configuration that provides mechanical support of borehole walls to create a more reliable seal.
The Saturn 3D radial probe innovations allow operators to capture samples, perform DFA and identify transient flow regimes in situations where they previously could not. These include low-per-meability formations, heavy oils, unconsolidated formations, single-phase fluids close to the bubble-point, ultratight formations and others.7
Putting Theory to the TestAn operator deployed the Saturn tool to distin-guish between oil and water zones in formations that had been difficult to test using traditional tools. Among the problems was a history of forma-tion tests in which mud losses had restricted sampling time to four hours per station. Because these were also low-mobility formations, this operational constraint made it difficult to cap-ture samples using traditional probes.
Engineers viewed this operation as an oppor-tunity to compare the Saturn tool with traditional sampling methods. They designed a WFT tool-string that comprised an XLD probe, a Saturn probe, a compositional DFA module and several sample bottles. Engineers took multiple pressure measurements as the tool was run into the hole,
6. Al-Otaibi SH, Bradford CM, Zeybek M, Corre P-Y, Slapal M, Ayan C and Kristensen M: “Oil-Water Delineation with a New Formation Tester Module,” paper SPE 159641, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, October 8–10, 2012.
7. Mobility is the ratio of formation permeability to fluid viscosity. Therefore, lower formation permeability or higher fluid viscosity decreases mobility.
> Parameters of a cleanup test simulation. Engineers performed a model comparison of the cleanup efficiency of the Saturn probe, dual straddle packer and XLD probes using a reservoir model based on specific wellbore, formation, fluid and simulation parameters (top). Model output (bottom) confirmed that the greater flow area of the Saturn probe significantly decreased cleanup times for various vertical and horizontal permeabilities for both water-wet and oil-wet sands. The simulations take into account the storage effects of the dual packer sump. In these simulations, a sump volume of 17.0 L [4.5 galUS] is assumed, and oil- and water-base mud filtrates are assumed to be segregated instantaneously within the sump. The interval height between packers is 1.02 m [40 in.].
PorosityHorizontal permeabilityVertical permeabilityWellbore diameterFormation thicknessTool distance from boundaryFormation pressureMaximum drawdown during cleanupMaximum pumpout rateDepth of filtrate invasion
20%10 mD2 mD
21.6 cm [8.5 in.]50 m [164 ft]25 m [82 ft]
21 MPa [3,000 psi]4 MPa [600 psi]
25 cm3/s [0.4 galUS/min]10 cm [4 in.]
Common Parameters Value
Oil viscosityOil-base mud filtrate viscosity
1 cP1 cP
Oil viscosityWater-base mud filtrate viscosity
1 cP0.6 cP
Relative permeabilityResidual oil saturationIrreducible water saturationWater relative permeabilityOil relative permeabilityWater and oil core exponentsConnate water saturation
Water-wet0.100.200.201.00
3.0 and 1.50.12
Oil-wet0.300.150.800.60
1.5 and 3.00.12
Model Output
Model Output
Value
Saturn 3D radial probeXLD probeSaturn speedup over XLD probe
0.71 h9.10 h12.8
0.42 h7.17 h17.0
0.99 h14.61 h
14.8
MiscibleCleanup
Immiscible Cleanup,Water-Wet
ImmiscibleCleanup, Oil-Wet
Miscible Cleanup Parameters Value
Spring 2013 37
and seven samples were captured as the tool-string was retrieved from the well.
At the first station, samples were captured using the XLD probe after DFA measurements had identified 60% to 70% oil in the flow stream. The operator chose Station 2 in an effort to deter-mine the depth of lowest mobile oil. Engineers attempted to capture a sample at Station 2 using the XLD probe, but with a 13.8-MPa [2,000-psi] drawdown, a flow rate of only 5.2 L/h [1.4 galUS/h] could be achieved. After 1.5 hours of pumping, flow was switched to the Saturn probe, and although the flow rate was increased to 7.8 L/h [2.1 galUS/h], the accompanying drawdown was only 4.7 MPa [680 psi]. Under these conditions, flow stability was achieved and engineers were able to identify the oil/water delineation within the previously imposed four-hour time limit.
While sampling at Station 2 with the XLD probe, engineers observed no oil flowing in the first 34 L [9.0 galUS] pumped during cleanup (below). Even accounting for the XLD probe contribution, engi-neers concluded that oil arrived at the tool faster
> Three-dimensional contamination distribution. Models of cleanup using the Saturn probe and an XLD probe are shown at four points in time. The same drawdown is applied to both the XLD and the Saturn probes, but because of its larger flow area and multiple, circumferentially spaced drains, the Saturn probe can operate at higher pump rates and consequently achieve cleanup 12 to 18 times faster than the XLD probe. (Adapted from Al-Otaibi et al, reference 6.)
Satu
rn P
robe
Time 1 Time 2 Time 3 Time 4
XLD
Pro
be
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
Contamination
0 0.2 0.4 0.6 0.8 1.0
> Finding oil. Logs of formation pressure (Track 1), mobility (Track 2), density-neutron-sonic (Track 3) and resistivity (Track 4) in this Middle East well would lead analysts to assume the target formation to be devoid of oil. However, DFA (Track 5) during pumpout indicated the presence of oil in the carbonate formation.
0.367 psi/ft (oil)
Formation Pressure
PretestMobilitymD/cP
Fluid Type
Lithology
MDTStation
psi 930 1,000530Photoelectric Factor
0.01
46
48
49
50
51
52
70%water
30%oil
40%water
waterStation 2
Station 1
Station 3
60%oil
0.477 psi/ft (water)± 0.021 psi/ft
Invaded Zone Resistivityohm.m
Bulk Density Correctiong/cm3
Formation Densityg/cm3
Thermal Neutron Porosity%
Delta-TSonic Porosity
% 10-in. Array Induction
ohm.m
20-in. Array Inductionohm.m
30-in. Array Inductionohm.m
60-in. Array Inductionohm.m
Resistivity
Sandstone
Porosity
Dolomite
Limestone
38 Oilfield Review
using the Saturn probe, which they attributed to the increased flow rate and radial cleanup.
The operator also tested a low-porosity, low-resistivity zone in the field. The first attempt, performed with an XLD probe, produced a 13.8-MPa drawdown and flow rate of less than 72 L/h [19.0 galUS/h]. Using the Saturn probe, engineers were able to reduce drawdown to 7.6 MPa [1,100 psi] with a flow rate of 288 L/h [76.1 galUS/h]. As a consequence, they were able to capture sufficient samples to delineate the oil/water contact (OWC) using the optical density mea-surements of the DFA module.
The Saturn probe was also used to identify a small amount of oil in a low-mobility zone in which pumpout was not possible with the stan-dard XLD probe. And finally, the operator sought to use sampling and DFA to determine the OWC in a heterogeneous carbonate formation with a resistivity measurement of 0.7 ohm.m. In this instance, in which traditional sampling tech-niques were unsuited to the task, engineers were able to use DFA measurements in conjunction with fluid samples captured with the Saturn tool to determine the thickness of the oil zone.8
Heavy Oil ChallengeHeavy oil is particularly problematic for conven-tional downhole sampling devices. Production of
this type of resource through proper placement of injection and production wells can be highly dependent on accurate fluid characterization. Because moving high-viscosity oil to the wellbore and then to the surface is often accomplished using steam injection and artificial lift, it is criti-cal for operators to be aware of higher-mobility zones within the reservoir layers created by rela-tively high-permeability rock or low-viscosity fluid. Both situations may create preferential high-mobility pathways through which the oil and steam flow and often result in significant bypassed reserves.
In 2011, the national oil company of Mexico, Petróleos Mexicanos (PEMEX), reported 60% of the nation’s oil reserves were heavy or extra heavy oil.9 As other more easily produced reserves are drained, these resources have become increasingly impor-tant to PEMEX and the nation. In the Samaria heavy-oil field in southern Mexico, PEMEX is trying to produce fluids with viscosities at downhole condi-tions as high as 5,000 cP [5,000 mPa.s] from forma-tions with unconfined compressive strength of from 0.69 to 5.5 MPa [100 to 800 psi].10 Because of chal-lenges presented by the combination of high-viscos-ity fluid moving through an unconsolidated formation, operators have been able to use WFTs to take pressure measurements in these formations but have been unable to capture samples. In the
Samaria field, PEMEX engineers have instead perfo-rated and flowed each zone individually and deployed sampling bottles on coiled tubing or a drillstring. Because this approach proved impractical and costly—often taking days or weeks per zone—the operator abandoned this sampling method.
As PEMEX engineers began a new develop-ment cycle in these Tertiary-age sandstones, they turned to the Saturn probe in 2011 to evaluate four wells. The primary team objective in the first well was to test the functionality of the new tool. In the second and third wells, engineers moved to full pressure testing with fluid scanning and sam-pling. In the fourth well, they also planned inter-val and vertical interference testing.
Multiple stations were tested and sampled in each of the wells. Because the formations are unconsolidated, the wellbores are often rugose and out of round—conditions that may cause a traditional probe to lose its seal before cleanup is
> Fluid sampling. The Saturn tool was used to acquire fluid samples and measure pressure (red) at the zone of interest. Initial measurements are mud pressure. At about 2,500 s, the tool is set and pumpout begins, followed by a buildup beginning at about 10,000 s, which establishes an estimate of reservoir pressure. Cumulative total volume pumped (green) begins to increase when the pump is turned back on at about 18,000 s to begin cleanup. At around 40,000 s, a second pump is engaged, which increases pump rate. The drawdown increases because of higher pump rate and the arrival of high-viscosity oil at the tool. Two spikes in pressure at about 55,000 s are the results of pressure shocks created when samples are captured followed by stopping the pump. Pressures are also recorded by an observation probe (black). Pumpout rates (tan and blue) are recorded on the far right axis in cm3/s for the first and second pumps, respectively. (Adapted from Flores de Dios et al, reference 10.)
Gaug
e pr
essu
re, p
si
Volu
me
pum
ped,
1,0
00 c
m3
2,000
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
10
0
10
40
20
30
20
30
40
50
60
70
80
90
100
110
Pum
pout
rate
, cm
3 /s
Elapsed time, s0 10,000 20,000 30,000 40,000 50,000 60,000 70,000
Saturn 3D radial probe pressure
Rate pump 2
Rate pump 1
Volume pumped
Quartz pressure gauge (observation) pressure
8. Al-Otaibi et al, reference 6. 9. Petróleos Mexicanos (PEMEX) Exploración y Producción:
“2011: Las reservas de hidrocarburos de México,” Mexico City: PEMEX (January 1, 2011): 22 (in Spanish).
10. Flores de Dios T, Aguilar MG, Perez Herrera R, Garcia G, Peyret E, Ramirez E, Arias A, Corre P-Y, Slapal M and Ayan C: “New Wireline Formation Tester Development Makes Sampling and Pressure Testing Possible in Extra-Heavy Oils in Mexico,” paper SPE 159868, presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, October 8–10, 2012.
11. Flores de Dios et al, reference 10.
Spring 2013 39
accomplished and samples captured. In the first well, tests were run with an XLD probe and a Saturn probe to test the sealing efficiency of the new system and to adjust variables such as set-ting and unsetting time, minimum inflation pres-sure for a seal and optimal pretest volume to account for storage effects.
The Saturn probe achieved 100% sealing in each of the seven stations tested using packer inflation pressures as low as 0.2 MPa [30 psi]. As a consequence, engineers were able to obtain full pressure surveys in both oil- and water-base mud environments that indicated only minor storage effects on the pressure responses. PEMEX engineers used the pressure surveys and mobilities determined from pretests to design completions that will evenly distribute injected steam in designated intervals, which will increase sweep efficiency.
As the testing for the Saturn tool continued, engineers captured minimally contaminated fluid samples from three wells using a toolstring that included an XLD probe and Saturn probes, fluid analyzers and sample bottles. Because of the unconsolidated nature of the formations, PEMEX engineers expected to use low differen-tial pressures that would require 16 to 20 hours per station to capture a sample; much of the time would be used to pump filtrate ahead of reservoir
fluids during cleanup. At the first station, while limiting differential pressure, engineers saw first hydrocarbon after 9 hours of pumping.
The pump speed was accelerated, and the dif-ferential pressure rose to about 200 psi [1.4 MPa]; no sand was seen in the tool. Flow pressure also decreased, indicating that the seal was holding. This led the team to abandon the original plan for low drawdown pressures and instead establish a 300-psi [2.1-MPa] differential minimum for Station 2 (previous page). The minimally con-taminated sample collected at this station was 7.5°API gravity oil; subsequent laboratory analy-sis documented that this sample had a viscosity of approximately 1,030 cP [1.03 Pa.s] at down-hole conditions and about 7,800 cP [7.8 Pa.s] at atmospheric conditions. Engineers will use the results from laboratory analysis of the samples in completion and production planning of the field.
In the fourth well, engineers performed inter-val pressure transient tests using the Saturn probe combined with an observation probe. These tran-sient tests consist of complete cleanup of the mud filtrate followed by variable-rate flow and shut-in periods, which are used to evaluate formation deliverability. Data from an observation probe higher on the toolstring provided engineers with information about formation permeability and
permeability anisotropy (above). PEMEX engi-neers are applying this information to calibrate cutoffs in nuclear magnetic resonance log pro-cessing, which they use to fine-tune permeabil-ity predictions.11
Low Mobility and High ConfidenceUsing resistivity log measurements, petrophysi-cists are able to delineate oil/water contacts in the majority of formations. However, in some for-mations, operators have difficulty interpreting the log response where water- and oil-bearing zones intersect. This uncertainty can affect how engineers choose to complete the well.
For one Middle East operator trying to deter-mine the extent of an oil zone in a tight carbon-ate formation, logs strongly indicated that the top of the zone was oil bearing and the bottom was water bearing. But log results for the middle zone were ambiguous; the resistivity response was similar to that of the water zone below it. Resolving the question of the fluid types of the middle zone with DFA measure-ments using traditional downhole sampling tools was precluded because establishing flow from the tight carbonate formation would have created a differential pressure greater than tra-ditional dual packer ratings.
>WFT interference test. The Saturn probe was run beneath a single-probe WFT. Engineers conducted an interval pressure transient test, obtaining vertical permeability (kv) and horizontal permeability (kh). Delta P and its derivative were recorded by the shallower observation tool (blue) and by the Saturn tool (green). Models were built using values of 12.2 m, 640 mD, 120 mD and 370 cP for height, kv, kh and viscosity, respectively. The modeled values (solid blue and green lines) reproduce the data closely, indicating that values for vertical and horizontal permeabilities are correct. (Adapted from Flores de Dios et al, reference 10.)
Delta
P a
nd d
eriv
ativ
e, p
si
Time since end of drawdown, s
10
101
101
102
103
102 10310
Modeled delta P, Saturn tool
Modeled derivative,Saturn tool
Modeled delta P,WFT observation probe
Modeled derivative,WFT observation probe
40 Oilfield Review
Using the Saturn probe, however, engineers were able to collect samples in all three zones, which confirmed light oil in the top zone and water in the lowest zone. After 15 hours of pumping at 4,900-psi [34-MPa] differential pressure from the 0.04-mD/cP mobility zone, DFA measurements indicated the presence of mobile light oil in the middle zone, which allowed the operator to deter-mine that the thickness of the oil zone was greater than initial estimates (above).
Drawdown RestrictionsIn some instances, operators have reason to use the Saturn 3D radial probe, even though a tradi-tional one might suffice. After engineers at Eni SpA saw the results achieved using the new probe in Ghana, engineers at an affiliated com-pany, Eni Norge, elected to try the service in the Goliath field in the Barents Sea. Engineers at Eni used this application to test sandstones in a relatively low-mobility environment, update the
> Low-mobility carbonate. Wireline log measurements (top) were inconclusive or provided conflicting interpretations in a formation in the Middle East. Porosity (Track 1) and resistivity (Track 2) measurements indicate an oil-bearing zone. However, log data from a middle zone were similar to those of the deeper water-bearing zone. Engineers resolved uncertainty in the middle zone by using the Saturn probe to capture a reservoir sample and a DFA module to measure fluid properties. Downhole fluid analysis (Track 3) indicated, similar to that in the top zone, the presence of oil in the middle zone. Flow from the tight carbonate formation required a differential pressure of 4,900 psi (bottom), which exceeds traditional WFT and packer ratings. (Adapted from Al-Otaibi et al, reference 6.)
Limestone
Lithology
Porosity
Dolomite
Pres
sure
, psi
Flow
rate
, cm
3 /s
Time, s
0500
0 10,000 20,000 30,000 40,000 50,000 60,000
1,0001,500
2,0002,500
3,0003,5004,000
4,5005,000
0
5
10
15
20
25
305,500
PressureRate
Photoelectric Factor
Invaded Zone Resistivityohm.m
Bulk Density Correctiong/cm3
Formation Densityg/cm3
Thermal Neutron Porosity%
Sonic Porosity
% 10-in. Array Induction
ohm.m
20-in. Array Inductionohm.m
30-in. Array Inductionohm.m
60-in. Array Inductionohm.m
Resistivity
Fluid TypeMDT
Station
Water
4,900-psipressure
differential
Sandstone
Clay
reservoir model and fluid contacts and increase their understanding of this new technology.
During the testing operations, the formation pressure survey encountered some supercharged low-mobility zones at the bottom of an oil col-umn. This introduced some uncertainty in the pressure gradient interpretation.12 Finding a clear delineation of the OWC also proved difficult because the resistivity log response could be attributed to either high water saturation or deep invasion effects. Fluid scanning with the Saturn probe identified the location of the OWC 5.5 m [18 ft] deeper than indicated by pressure gradi-ent and log response.
Furthermore, because of the large flow area of the Saturn probe, the strength of the lami-nated and low-permeability rock was confirmed. In this case, although reservoir mobility was a moderate 45 mD/cP, the reservoir pressure was near saturation pressure. Thus, a low drawdown pressure was essential to prevent a high pressure differential that might induce two-phase flow and an unrepresentative gas/oil ratio. Using the Saturn probe, a drawdown of only 0.5 bar [0.05 MPa or 7.3 psi] was needed to scan and clearly identify reservoir oil. A sample was also acquired using an XLD probe at another station in the same well in which the reservoir mobility was 880 mD/cP—more than an order of magni-tude greater than that of the reservoir sampled using the Saturn probe. Compared with the flow rate of the XLD probe, the Saturn probe achieved twice the flow rate at half the drawdown (next page). As a result, cleanup time was one-third of that using the XLD without raising concerns over the effects of extreme pressure changes on sample integrity.
Another Step ForwardThe industry’s ability to capture fluid samples and critical pressure data has evolved rapidly since the 1970s. Innovations in these arenas have been spurred by need to develop more-complex forma-tions with tighter limits on testing operations. With increasing frequency, engineers are testing weaker formations and producing high-viscosity fluids, which means tests must take less time at each station with lower drawdown ranges and lower flow rates. Often, these restrictions conspire to make sampling impossible.
12. Supercharging occurs when mud filtrate invading through the wellbore wall during drilling creates an overpressure in the formation around the wellbore. Pressure tests with WFTs, performed during the pretest, are affected by this overpressure, which is higher than the true formation pressure.
Spring 2013 41
> Drawdown and flow rate comparison. Engineers at Eni chose the Saturn probe to capture samples from a 45-mD/cP mobility reservoir and a single XLD probe to capture a sample in a much higher 880-mD/cP mobility reservoir within the same well. While flow rate (top, green line) through the Saturn probe (left) was nearly twice that of the XLD probe (right), the drawdown (blue line) was half that of the XLD probe. Fluorescence monitoring during cleanup (middle) indicated cleanup as fluorescence increased with fluid purity. The reservoir tested using the Saturn probe reached cleanup in 10 minutes (bottom left) compared with the XLD probe, which cleaned up in about 30 minutes (bottom right).
195.0
194.5
194.0
193.5
193.0
192.5
192.0
191.5
191.0
190.5
190.0
50
45
40
35
30
25
Pres
sure
, bar
Fluo
resc
ence
Elapsed time, min0
0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Elapsed time, minWater Mud-contaminated fluidOil
0 5 10 15 20 25 30 35 40 45 50
5 10 15 20 25 30 35 40 45 50
Flow
rate
, cm
3 /s
20
15
10
5
0
195.0
194.5
194.0
193.5
193.0
192.5
192.0
191.5
191.0
190.5
190.0
50
45
40
35
30
25
Pres
sure
, bar
Fluo
resc
ence
Flui
d fra
ctio
n, %
Flui
d fra
ctio
n, %
Elapsed time, min0 10 20 30 40 50 60 70 80 90 100 110 120
Flow
rate
, cm
3 /s
20
15
10
5
0
Flow rate40 cm3/s
Flow rate22 cm3/s
DrawdownDrawdown
Quartz gauge pressure,Sample line pressure
45-mD/cP Mobility Reservoir 880-mD/cP Mobility Reservoir
Pumpout totalflow rate
Fluorescence Channel 0
Fluorescence Ratio
Fluorescence Reflection
Fluorescence Channel 1
Quartz gauge pressure,Sample line pressure
Pumpout totalflow rate
0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
Fluorescence Channel 0
Fluorescence Ratio
Fluorescence Reflection
Fluorescence Channel 1
100
80
60
40
20
0
Elapsed time, min0 10 20 30 40 50 60 70 80 90 100 110 120
100
80
60
40
20
0
10 min 30 min
The Quicksilver Probe tool design shortens time on station, and DFA technology provides engineers with critical and timely knowledge about reservoir fluids as they are captured. Both these advances have allowed operators to gather pressure and fluid sample data more quickly and with greater confidence in the results.
The Saturn probe expands the range of situa-tions and conditions in which WFTs are applicable; these include low-permeability or unconsolidated formations, heavy oil, near-critical fluids and rugose boreholes. The Saturn probe openings are configured to create a total surface flow area 1,200% greater than that of the largest conven-tional single-probe formation testers. This larger area means flow of viscous fluids is less restricted
and pressure differentials are reduced; viscous fluid flow and pressure differentials are the pri-mary constraints to testing in formerly inaccessi-ble environments.
In addition to allowing operators to take mea-surements and samples in these formations, in most cases the Saturn probe works to more quickly dispose of filtrate and contaminated for-mation fluids, reducing time on station. Constant-drawdown simulations in low-mobility reservoirs show the Saturn tool to be orders of magnitude faster than standard XLD packer probes in com-pleting cleanup. With no sump, transient flow regimes can be recognized earlier, extending the range of applicability of interval pressure tran-sient tests.
Shorter operating time is not trivial on some of today’s projects in which operating costs often exceed $US 1 million per day. The Saturn probe addresses this issue of high-cost time through higher flow rates that save operators hours and even days of operating expense. Similarly, data from the Saturn probe allow engineers to make critical completion and production decisions based on hard facts rather than estimates, and that can make the difference between success or failure, profit or loss. —RvF
42 Oilfield Review
Developments in Full Azimuth Marine Seismic Imaging
The Coil Shooting technique, in which a single vessel acquires full azimuth 3D
seismic data by sailing in circles, delivers more-accurate and reliable subsurface
images than conventional 3D methods in areas of complex geology. Recently, a
multivessel implementation of the technique has been developed to address subsalt
imaging challenges in deepwater areas.
Tim BricePerth, Western Australia, Australia
Michele BuiaEni E&PMilan, Italy
Alex CookeRio de Janeiro, Brazil
David HillEd PalmerGatwick, England
Nizar KhaledSérgio TchikanhaEnrico ZamboniTotal E&P AngolaLuanda, Angola
Ed Kotochigov Oslo, Norway
Nick MoldoveanuHouston, Texas, USA
Oilfield Review Spring 2013: 25, no. 1.Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Paul Bidmead, Gatwick, England; and Giuseppe Uncini, Eni Indonesia, Jakarta.3D GSMP, Coil Shooting, DSC, Dual Coil Shooting, ObliQ, Q-Fin and Q-Marine are marks of Schlumberger.
Traditionally, vessels acquire 3D marine seismic data by sailing in a series of straight, parallel lines over a survey area. This recording configura-tion suffers from an inherent problem: Although the source wavefront propagates in all directions, only a small proportion of the reflected wavefront is captured by the surface receiver spread, and the seismic raypaths are aligned predominantly in one direction, or azimuth.
In the presence of complex geology, ray bend-ing can leave portions of the subsurface untouched by seismic waves when only a narrow range of source-receiver azimuths is recorded (left). Attempts to solve this problem have led to the development of wide azimuth (WAZ), rich azi-muth (RAZ) and multiazimuth (MAZ) acquisition configurations (next page, top left). By “shining a light” on the formations from many directions, these methods deliver better illumination of the subsurface, higher signal-to-noise ratio (S/N) and improved seismic resolution in challenging imag-ing areas such as beneath complex salt bodies.1
Wide azimuth surveys are typically conducted using three or four vessels, each shooting in straight, parallel lines. As in conventional sur-veys, the time taken to turn vessels around between the end of one swath of straight lines and the start of the next has, to date, been accepted as inevitable nonproductive time (NPT) (next page, top right).
> Image distortion. Refraction of light through the irregular surface of a glass drinking mug (top) causes parts of a spoon to be invisible or distorted when viewed from different directions; the image changes depending on azimuth. Similarly, seismic images of a subsurface structure (bottom) offshore Angola differ depending on the source-receiver azimuth of the contributing data.
Oilfield Review WINTER 12/13 Coil Shooting Fig. 1ORWIN 12/13 1
0° to 10° 60° to 70°
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In 2007, WesternGeco began testing the Coil Shooting technique, in which a vessel sails in overlapping circles in corkscrew fashion, recording continuously, to deliver full azimuth (FAZ) data (right).2 The method provides higher fold and better azimuthal coverage than other techniques.3 FAZ surveys may be more cost-effective because data are acquired using a sin-gle seismic vessel and are recorded continuously, minimizing NPT.
The ability to successfully perform Coil Shooting acquisition is made possible by the Q-Marine point-receiver marine seismic system. Calibrated
>Multivessel line changes. The four vessels in a typical Gulf of Mexico linear WAZ acquisition configuration follow a circuitous path between the end of one swath and the start of the next, which is necessary to align the vessels for the start of the new swath and avoid collisions during line turns. This vessel movement configuration results in nonproductive time.
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> A four-vessel wide azimuth (WAZ) configuration. This acquisition arrangement—two vessels towing streamers and sources, plus two additional source vessels—has been widely used in the Gulf of Mexico. The offset-azimuth plot (inset) indicates the offsets and azimuths acquired by this configuration—in this case a 60°
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range of azimuths. Azimuth corresponds to the angle clockwise from the top of the circle. Offset corresponds to the distance from the center of the circle. Colors range from purple for a low number of traces to green, yellow and red for a high number of traces.
1. Camara Alfaro J, Corcoran C, Davies K, Gonzalez Pineda F, Hampson G, Hill D, Howard M, Kapoor J, Moldoveanu N and Kragh E: “Reducing Exploration Risk,” Oilfield Review 19, no. 1 (Spring 2007): 26–43.
2. Buia M, Flores PE, Hill D, Palmer E, Ross R, Walker R, Houbiers M, Thompson M, Laura S, Menlikli C, Moldoveanu N and Snyder E: “Shooting Seismic Surveys in Circles,” Oilfield Review 20, no. 3 (Autumn 2008): 18–31.
3. Fold is a measure of the density of seismic measurements. It is usually computed as the number of different source-receiver pairs that record reflections from a particular target layer in each of the rectangular bins (typically 25 m × 25 m [82 ft × 82 ft]) of a 3D grid over the survey area. High fold usually improves S/N.
> Coil Shooting schematic. For Coil Shooting single- vessel full azimuth acquisition, the seismic vessel sails in overlapping circles in corkscrew fashion, recording continuously. The offset-azimuth plot (inset) indicates that this survey configuration acquires complete azimuthal and high offset coverage.
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single sensors enable noise attenuation that can-not be resolved by other technologies. A fully braced acoustic network provides accurate posi-tioning of the in-sea equipment. Q-Fin steering devices accurately control the depth and lateral position of the streamers, facilitating constant streamer separation. DSC dynamic spread con-trol technology adds steerable sources and auto-matic vessel, source and streamer steering to achieve the best possible match with planned source and receiver positions. The Coil Shooting technique requires no special adaptation of the equipment used for conventional 3D surveys, and vessels can easily switch between linear and cir-cular acquisition programs.
Coil Shooting surveys have been acquired in several regions and, in areas of complex geology, the results from these circular geometry FAZ sur-veys have been superior to those from conven-tional 3D surveys and comparable to or better than WAZ data acquired using multiple vessels. This article describes recent imaging successes from offshore Indonesia, Brazil, Angola and the Gulf of Mexico.
Imaging in IndonesiaThe first full commercial survey using the Coil Shooting technique was acquired in 2008 for the E&P division of Eni SpA on the Tulip project in the Bukat production-sharing contract block east of Kalimantan, offshore Indonesia. Several unfavorable geologic conditions conspire to cause poor seismic response in the area.4 The target has low P-wave impedance contrast, thus has only weak seismic reflectivity. The seafloor is characterized by rough geomorphology, with can-yons and irregularities that cause uneven illumi-nation in the subsurface and complex 3D raypaths for surface and internal multiples.5 A bottom-simulating reflector (BSR) below the seabed gen-erates several orders of multiples that further degrade subsurface illumination.6 The presence of free gas below the BSR causes sudden fre-quency and amplitude decay of primary reflec-tions. Complex subsurface geology further complicates the scenario. Combined, these con-ditions lead to diffraction, absorption, scattering and weak transmission of seismic signal energy. Such effects have been observed in the results of conventional narrow azimuth towed streamer (NATS) 3D seismic surveys, which have delivered poor illumination of the target reservoir.
Eni sought to improve imaging through inno-vative acquisition. Engineers performed a feasi-bility study using ray tracing on an existing Tulip velocity-depth model to evaluate the potential of
various single-vessel towed streamer geometries. Multivessel WAZ and RAZ options were not con-sidered because it was important to record near offsets—data with short source-receiver separa-tion—to image the undulating seabed. The study concluded that a Coil Shooting survey would provide the best illumination of the targets. In addition, mobilizing several vessels to the survey area would have been logistically and financially challenging.
The selected survey design consisted of 145 circles of radius 6,500 m [21,300 ft] with circle centers spaced 1,000 m [3,280 ft] apart. The seis-mic vessel Geco Topaz, equipped with eight streamers each 6 km [3.7 mi] long and separated by 100 m [328 ft], acquired the 563-km2 [217-mi2] survey during August and September 2008. Approximately 260,000 shotpoints were acquired.
Acquisition of the data from the original pro-grammed circles was completed more quickly than expected, and some additional lines were acquired to fill in areas of low illumination. At the end of the survey, after infill shooting, the actual target illumination was slightly more uniform than the planned one. WesternGeco completed the Tulip field Coil Shooting survey in 49 days. By comparison, a three-azimuth MAZ survey was predicted to require 60 days, and a four-azimuth survey 75 days.
Seismic engineers began processing the Tulip Coil Shooting survey data onboard Geco Topaz in August 2008 and completed the process in
Jakarta in February 2010. The Coil Shooting method results in many acquisition and imaging benefits but introduces challenges in data pro-cessing because some standard processing work-flows were designed for data with linear geometry. Prior to acquisition of the full survey, WesternGeco geophysicists generated a subset volume of 3D synthetic data with coil geometry and processed it to verify the efficacy of the proposed algorithms and workflow.
An important step in preparing data for the processing workflow is the removal of multiples. WesternGeco has developed the 3D GSMP gen-eral surface multiple prediction process, which has proved highly effective for attenuating multi-ples while preserving the integrity of primary energy.7 Apart from stacking velocities, the algo-rithm requires no a priori knowledge of the sub-surface and can handle all orders of surface multiple in the presence of complex geology and irregular acquisition geometries.8 The 3D GSMP technique predicts the multiples at true azimuth, ensuring that the modeled multiples accurately match the multiples in the input data. The tech-nique is most effective when applied to data from a wide range of azimuths, so optimal performance is achieved when applied to the FAZ data pro-vided by the Coil Shooting approach. In the Tulip dataset, 3D multiples were predicted almost per-fectly in phase, and the algorithm reduced their amplitudes by approximately 25 dB [94%].
> Azimuthal tomography workflow. A tilted transverse isotropic (TTI) velocity model derived from time domain processing formed the starting model. The Tulip Coil Shooting dataset was divided into three azimuthal groups for prestack depth migration (PSDM). Traveltimes from the PSDM were compared with those predicted by the model using tomography inversion and ray tracing techniques, leading to an updated velocity model.
Tomography inversionRay tracing with actual azimuths
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High stacking fold, and therefore improved S/N, is one of the many benefits of the Coil Shooting method. However, fold can vary considerably from one bin to another, and this variation must be addressed to avoid introducing anomalous variations in the amplitude of traces after stacking them together. Using a weighting system that computed scale factors based on the spatial distribution of traces within a 3D bin, engineers applied processes to regularize fold and offset contributions within the full range of azimuths. Subsequent analysis of amplitudes at the target depth indicated that normalization was successful, rendering the dataset suitable for processes such as amplitude variation with offset analysis or inversion.
Azimuthal information also provides opportu-nities for building more-accurate models of sub-surface seismic velocity, which in turn enable more-accurate depth images of subsurface 3D structures. The models are built using tomogra-phy—an inversion process that attempts to con-struct an estimate of the 3D velocity structure of the Earth based on observed measurements of traveltimes associated with seismic reflections, often including some geologic constraints. The analysis is usually performed on 2D sections and is an iterative process that moves toward a best-fit solution between observed traveltimes and those predicted from the 3D velocity model.
As input for the azimuthal tomography work-flow, the Tulip dataset was split into three azimuth sectors, each representing a range of 60° (previous page). Prestack depth migration (PSDM) was applied to each sector and the prestack results were output on a 50-m × 50-m [164-ft × 164-ft] grid for analysis.9 The initial tilted transverse isotropic (TTI) velocity model was derived from time domain processing. Analysis of the PSDM data indicated where adjustments to the velocity model were required, and the process was iterated until the model matched the observed traveltimes. The resulting anisotropic velocity model showed a good match with interval velocities derived from a verti-cal seismic profile (VSP) that had been previously acquired in the survey area. The TTI model was also consistent with geologic boundaries and velocities observed in a well, and it identified areas of low velocity below the seabed that were probably caused by the presence of free gas.
The final Coil Shooting PSDM results show several improvements in imaging at the target level and at greater depths compared with data from a previous narrow azimuth survey over the same area (above right). In particular, the conti-nuity, visibility and sharpness of the dipping events are clearly evident.
Seeing Through Salt Offshore BrazilIn early 2010, an operator was looking for an opportunity to evaluate the coil acquisition tech-nique as a tool to improve imaging of presalt tar-gets offshore Brazil. The company invited WesternGeco to implement the technology in an oil field located in deep water in the Santos basin.10 The reservoirs in this field are up to 6,000 m [20,000 ft] below the ocean surface and
vary in thickness from tens to hundreds of meters. The overburden includes a complex dip-ping salt layer up to 2,000 m [6,600 ft] thick that consists of homogeneous halite bodies and lay-ered evaporites. The S/N in existing seismic data from the area is poor at the reservoir level. In addition, strong surface and interbed multiple energy interferes with primary reflections from the presalt target.
4. Buia M, Vercesi R and Tham M: “Coil Shooting on Tulip Discovery: Seismic Processing Challenges, Opportunities and Results,” paper SPE 134222, presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, September 19–22, 2010.
5. A multiple is a seismic arrival that has incurred more than one reflection in its travel path. Many multiples involve reflections from the seabed and the sea/air interface. Others involve reflections between subsurface reflectors. Multiples can interfere with or obscure primary reflections and usually need careful suppression during processing.
6. A bottom-simulating reflector (BSR) is a seismic reflection often seen in seismic sections from deepwater areas. Studies indicate that it is primarily caused by the acoustic impedance contrast where free gas is trapped at the base of a gas hydrate zone.
> Tulip Coil Shooting data. Comparison of an example line from a previous NATS 3D survey (left) with equivalent data from the new Coil Shooting prestack depth migrated dataset (right) demonstrates improvements in imaging, particularly in the continuity, visibility and sharpness of the dipping events in the deeper section.
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7. Moore I and Dragoset B: “General Surface Multiple Prediction: A Flexible 3D SRME Algorithm,” First Break 26, no. 9 (September 2008): 89–100.
8. Stacking is a key stage in seismic processing in which the traces in a bin are combined. Before stacking, traces require individual corrections based on their source-receiver offsets and an estimate of subsurface seismic velocities to bring them to a common time horizon before stacking, or summing.
9. Migration is a step in seismic processing in which reflections are moved from their recorded two-way traveltimes to an estimate of their true position in space based on a model of subsurface seismic velocities.
10. Cooke A, Le Diagon F, De Marco R, Amazonas D, Bunting T, Moldoveanu N, Klug S and Mattos E: “Full-Azimuth Towed-Streamer Seismic: An Exploration Tool for Pre-Salt Hydrocarbon Exploration Offshore Brazil,” paper SGS 1.6, presented at the 82nd SEG Annual International Meeting and Exposition, Las Vegas, Nevada, USA, November 4–9, 2012.
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The survey was centered on the planned loca-tion of a future well, with the objective of using the new dataset to help optimize well placement. The survey area also enclosed an active drilling rig. While this rig prevented acquisition of con-tiguous coil data over the entire survey area, it facilitated acquisition of a spiral 3D VSP dataset. Processing specialists used these measurements to validate the earth model used for depth imag-ing of the surface seismic dataset. The operator plans to merge the 3D VSP data with the surface seismic data volume, which will improve cover-age in the area obscured by the presence of the drilling rig.
Modelers conducted a survey design study to compare the expected results of several potential acquisition geometries. The expected processing sequence was applied to synthetic datasets gen-erated using 3D ray tracing through an existing earth model. The study confirmed that, compared with linear geometries, Coil Shooting acquisition would deliver improved S/N, better attenuation of multiple energy and better continuity of reflec-tions at the target level. After considering several potential coil geometries, the companies agreed on a plan to acquire 78 circles of 6.25-km [3.88-mi] radius over an area of 600 km2 [230 mi2] (below). In an effort to make the acquisition geometry slightly less regular and reduce offset clustering within 3D bins, the coil centers were randomly distributed within a pre-defined tolerance.11
The survey was acquired from November 2010 to January 2011 in water depths ranging from 2,000 to 2,300 m [6,600 to 7,500 ft]. The seismic vessel was equipped with 12 streamers, each 8,000 m [26,250 ft] long, towed 120 m [394 ft] apart. Two source arrays 60 m [197 ft] apart were fired alternately every 37.5 m [123 ft].
The seismic crew generated displays onboard to confirm the quality of the seismic data. Source and receiver position data were transferred to offices in Rio de Janeiro, where analysts pro-duced near real-time fold and illumination maps for comparison with the original plan (above). The crew made some changes to the arrangement of swaths during the survey, particularly in the area around the rig. These changes were neces-sitated by the magnitude and direction of currents
as well as an extension of the exclusion zone around the rig. The circular geometry allowed for easy operational adjustments. The vessel acquired more than 92,000 shots and conducted one less circle than originally planned.
Before acquisition began, analysts tested a workflow that included initial noise attenuation and some wavelet processing, which was subse-quently applied in near real time onboard the seismic vessel. The workflow effectively removed high-amplitude noise with no apparent impact on signal amplitudes (next page, top).
Processing specialists applied corrections to account for variations in the acoustic velocity of the seawater during the survey because of changes in temperature and salinity. Such varia-tions cause anomalies in the traveltimes of
> Brazil survey source positions. The red coils show the actual source positions. The squares represent the survey area boundary, 180° and 360° azimuth areas. The drilling rig location is indicated by the black circle.
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Area of 360° coverage> Fold and illumination. Total fold of coverage (top) calculated for 25-m � 25-m bins. The planned fold (left) and actual fold (right) are in close agreement. Target illumination, or hit count (bottom), also shows a close match between planned (left) and actual illumination (right).
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reflection events that can impact imaging, atten-uation of multiples and some other processes applied to data sorted into 3D bins. The varia-tions are likely to be most significant in deep water and in areas of rapidly changing currents, which are both features of the waters offshore Brazil. Many different coils, each with its own water column characteristics, contribute data to each bin; thus when significant velocity varia-tions occur, they must be corrected.
Water velocity corrections were applied using a layer-replacement approach.12 Because a single coil sail line with a radius of 6.25 km [3.9 mi] may sample significantly varying current regimes in the survey area, geophysicists divided each coil into separate segments and estimated the water velocity for each segment. They then applied dynamic corrections to adjust the dataset to a single water velocity function.
In this area of the deepwater Santos basin, surface multiples from both the seafloor and the complex top-of-salt horizons coincide with the arrivals of the weaker base-of-salt and subsalt reflections. Therefore, it was critical to attenuate this energy without corrupting the primary ampli-tudes. One of the characteristics of coil acquisi-tion is that it has a higher shot density than conventional NATS surveys and delivers more near-offset information than multivessel WAZ sur-veys. These features provide data that more closely meet the requirements of techniques for
attenuating multiples such as the 3D GSMP method that was applied.
Data coverage in terms of offset, azimuth and midpoint (the surface position equidistant between source and receiver) is inherently irregular over the area of a coil survey. For some data processing algorithms—such as tomo-graphic velocity model building—3D bins need to have regularly spaced midpoints, azimuths and offsets. Several methods are available for
11. Moldoveanu N: “Random Sampling: A New Strategy for Marine Acquisition,” Expanded Abstracts, 80th SEG Annual International Meeting and Exposition, Denver (October 17–22, 2010): 51–55.
12. Carvill CV: “A New Approach to Water Velocity Estimation and Correction,” paper U027, presented at the 71st European Association of Geoscientists and Engineers Conference and Exhibition, Amsterdam, June 8–11, 2009.
13. Schonewille M, Klaedtke A and Vigner A: “Anti-Alias Anti-Leakage Fourier Transform,” Expanded Abstracts, 79th SEG Annual International Meeting and Exposition, Houston (October 25–30, 2009): 3249–3253.
regularization, and various methods were used as appropriate for different parts of the data pro-cessing sequence for the Santos basin survey.
Producing regularly sampled data from irregu-larly sampled data requires interpolation. For the offshore Brazil dataset, matching pursuit Fourier interpolation produced a fully regularized dataset in offset, midpoint and azimuth for building the velocity model in the sediments (below).13 This method can efficiently interpolate in multiple
>Noise attenuation. The raw shot record (left) contains high-amplitude noise, which is effectively attenuated after onboard processing (right).
Shot Gathers: Raw Shot Gathers: Filtered
> Data regularization. This section from a common offset, common azimuth volume (top) exhibits gaps and “jitter” between traces caused by azimuthal variation. After regularization, the gaps are filled and jitter is reduced (bottom). The blue plots (inset) show the fold coverage for the offset-azimuth volume before and after regularization. The yellow lines indicate the location of the seismic sections.
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dimensions to improve the regularization of sparsely sampled data. Data are transformed from the space-time domain to the space-frequency domain by a fast Fourier transform. For each fre-quency slice, data are transformed from the spa-tial domain to the spatial Fourier, or wavenumber, domain. Once the Fourier domain has been com-puted, data can be transformed back to any loca-tion in the spatial domain—in this case onto a dense and regular grid—using an inverse discrete Fourier transform.
For depth imaging in complex geologic areas such as this Santos basin field, an accurate velocity model is essential to correctly place reflections in their true subsurface positions. With full azimuth acquisition, multiazimuth tomographic methods may be used for velocity model updating. The introduction of additional information from multiple azimuths reduces uncertainty and increases confidence in veloc-ity model updates.14
Geophysicists updated the Santos basin field velocity model in several steps: They first split the coil dataset into three azimuth volumes for tomography: 0° to 60°, 60° to 120° and 120° to 180° and their opposite azimuths. They next updated the anisotropic velocity model sequen-tially in three zones: sediment, intrasalt and pre-salt. Validation of the resulting earth model included 3D VSP traveltime analysis, in which measured and modeled arrival times were com-pared to produce an indication of confidence in the model (left).
Results of depth migration of the Coil Shooting data using an intermediate velocity model pro-vided significant imaging improvement compared with those from a previous 2D depth migrated dataset in the area (below left). The new FAZ data have delivered high-quality images of the base of the salt and are allowing confident inter-pretation of presalt structures. Further improve-ments are expected when the data are migrated using the full anisotropic earth model.
Coil Acquisition Offshore AngolaThe first Coil Shooting survey acquired in the West African subsalt province was acquired in Block 33 Angola over the Calulu Predevelopment Area (PDA) for Total E&P Angola (TEPA) and its partners (next page, top right). Water depth in this block ranges from 1,500 to 2,500 m [4,900 to 8,200 ft]. The area is characterized by complex geology related to extended salt canopies that cover most of the block. The main reservoir levels are turbidite sands located in highly structured near-salt and subsalt areas.
A NATS 3D seismic survey was acquired over the area in 1999; however, the quality of the resulting data was insufficient to correctly image the complex salt tectonic structures and the steeply dipping anticlinal flanks. In addition, the presalt targets were characterized by poor S/N and poor illumination. Limited 3.5-km [2.2-mi] offsets and a restricted range of azimuths con-tributed to these unsatisfactory results.
To address these concerns, TEPA and part-ners decided to acquire two new 3D datasets: a 1,284-km2 [496-mi2] NATS survey with long off-
> Brazil survey traveltime residuals. Geophysicists validated the velocity model for seismic imaging by comparing traveltimes through the model with actual traveltimes from a 3D VSP acquired at the same time as the Coil Shooting survey in the Santos basin. The VSP was acquired with spirally distributed source positions around the rig and receivers in the borehole at the center of the spiral. Colors indicate the difference between the modeled and actual traveltimes, with aqua indicating the closest match. The magenta surface beneath and to the right of the spiral is the top of salt.
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> Seismic lines and a time slice from the Brazil Coil Shooting 3D volume. The new Coil Shooting data have delivered high-quality images of the base of salt and are enabling confident interpretation of presalt structures.
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14. Dazley M, Whitfield PJ, Santos-Luis B, Sellars A, Szabo P, Nieuwland F and Lemaistre L: “Solving Short-Wavelength Velocity Variations with High-Resolution Hybrid Grid Tomography,” paper C001, presented at the 69th European Association of Geoscientists and Engineers Conference and Exhibition, London, June 11–14, 2007.
15. Khaled N, Capelle P, Bovet L, Tchikanha S and Hill D: “A Coil Shooting-Acquisition Case Study in the Angolan Deep Offshore,” paper X027, presented at the 74th European Association of Geoscientists and Engineers Conference and Exhibition, Copenhagen, Denmark, June 4–7, 2012.
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sets—7.5 km [4.7 mi]—over the full area, and an 860-km2 [332-mi2] Coil Shooting survey over a subset of the area. The company’s objective in conducting the NATS survey was to improve the imaging of the deep Oligocene, Cretaceous and presalt sections through better signal penetra-tion, longer offsets, higher fold and a longer recording time than the 1999 survey. The new data would enable reevaluation of the deep post-salt series and a first 3D interpretation of the presalt series. The objective of the Coil Shooting survey was to improve the imaging of the deep Oligocene and Cretaceous subsalt structures to provide a better understanding of trap geometry and reduce uncertainty about the presence or absence of a reservoir. Comparison of the results of the two types of survey provided an opportunity to assess the added value of the Coil Shooting technique.
Before data acquisition, a feasibility study was performed to select the optimal Coil Shooting parameters to adequately image a 38-km2 [15-mi2] target area at the center of the survey.15 The study resulted in a survey design comprising 72 circles with centers in a rhombic pattern spaced 2,500 m [8,200 ft] apart in both inline and crossline directions (right). For the selected design, the fold of the 12.5-m × 12.5-m [41-ft × 41-ft] bins was up to 567, and the azimuthal coverage was up to 360° within the target area.
In comparison with a NATS survey of the same size acquired with exactly the same in-sea equip-ment configuration, in the coil design 95% of bins have a higher fold, and 70% have more than twice the fold. A single vessel Coil Shooting survey records more than double the data volume of a NATS survey, although the Coil Shooting survey records slightly shorter far offsets because of the curvature of the streamers (below).
> Location of the Calulu Predevelopment Area (PDA), Block 33, offshore Angola.
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> Calulu Coil Shooting survey design. The survey design comprised 72 coils (left) with their centers (red dots) in a rhombic pattern (right). The survey delivered high-fold, full azimuth coverage over the target area (red box).
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> Comparison of NATS and single vessel Coil Shooting survey fold and offsets. The histogram of fold (left) shows the constant fold of a NATS survey (red) and the variable but large fold of a coil survey (blue). In offset (right), a NATS survey offers slightly longer offsets, but a coil survey of the same size records more than double the number of traces.
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The seismic vessel WesternGeco Amundsen acquired the two surveys between February and April 2011. The Calulu PDA coil survey acquisition was completed in 21 days. On several occasions, the vessel acquired data continuously for periods longer than 24 hours with no NPT. Despite the much smaller area of the Coil Shooting survey, the size of its prestack dataset was equivalent to that of the NATS survey; each survey comprised approx-imately 120,000 shots.
Quality control of coverage in a NATS survey is usually based on the fold and range of offsets represented in each bin of the 3D grid. Seismic traces whose midpoints lie within a bin are assumed to belong to that bin. This assumption is correct for flat reflectors and isotropic velocities, which are often appropriate for the seabed and shallow geology but becomes less accurate with increasing geologic complexity. Ocean crosscur-rents cause streamers to feather, or deviate from planned positions, which may lead to gaps, or areas of bins with low fold. If the gaps are consid-ered detrimental to the imaging objective, addi-tional infill lines are acquired over these areas. Because the Calulu survey was designed to over-come illumination challenges in a structurally
complex subsalt target, QC using 3D ray trace modeling, in addition to the conventional acqui-sition QC, was performed in near real time onboard the vessel to compare the expected and actual illumination at the target reservoir level. At the end of the programmed survey, the achieved illumination proved to be essentially equivalent to the expected illumination, indicat-ing that streamer feather, vessel deviation and other factors that can lead to a requirement for infill acquisition did not impact illumination of the target (above). Based on this analysis, the team determined that no infill was necessary for the Coil Shooting survey, although the NATS survey required 6.4% more time for infill lines compared with that used for the programmed acquisition (next page, top).
Towing the streamers in a curve in the pres-ence of strong crosscurrents created high levels of acoustic interference known as crossflow noise that required special processing. Because geo-physicists needed to design a workflow for effec-tive crossflow noise attenuation during the main Coil Shooting survey—scheduled to be performed after the NATS survey—several preliminary cir-cles were acquired before the NATS survey to
assess the magnitude of the crossflow noise. The crossflow noise for this Coil Shooting survey reached levels more than 10 times those of average straight line surveys.
Q-Marine technology facilitates effective removal of crossflow noise by leveraging advances in electronics and fiber-optic networks to provide high channel count recording systems. Its single-sensor field data are sampled at 3.125-m [10.25-ft] intervals along each streamer, provid-ing adequate sampling of the signal and most noise. The first stage of the onboard processing sequence is digital group forming (DGF). In DGF, engineers apply data-adaptive algorithms to the shot records from each streamer to recognize and suppress the crossflow noise while preserving the integrity of the seismic signal. Further noise attenuation is achieved during subsequent pro-cessing stages.
Seismic engineers tested parameters for 3D GSMP processing early during acquisition to determine the optimal workflow and facilitate rapid processing turnaround. They selected parameters based on ray tracing through a TTI velocity model provided by TEPA. Various types of multiples were modeled, including some related to
> Target illumination. Expected illumination based on 3D ray trace modeling (left) closely matches actual illumination (right) at the target level. Illumination values, the number of raypaths passing through a bin, are color-coded: Low values are blue, and high values are red.
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the sea/air surface and others occurring between subsurface reflectors. The water bottom and top-of-salt horizons were defined as the most signifi-cant generators of multiples. The Coil Shooting and NATS data were processed with similar 3D GSMP parameters.
TEPA’s field evaluation schedule required rapid turnaround for the processing and prelimi-nary imaging. A raw TTI reverse time migration (RTM) prestack depth migration 3D volume was available four and five months after the last shotpoint was acquired for the NATS and Coil Shooting data, respectively. RTM is a prestack two-way wave equation migration algo-rithm suited to accurate imaging in and below areas with structural and velocity complexities. Until recently, companies considered RTM impractical because of its high computational requirements and sensitivity to velocity and reflectivity parameters. Now, large parallel com-puting clusters, coupled with new workflows able to build increasingly accurate velocity models, make RTM a more viable option in the imaging portfolio. Nevertheless, to complete the fast track processing on schedule, compromises were made. To produce the fast track images, geophys-icists selected 50% of the shots and migrated fre-quencies up to 25 Hz and 20 Hz for the NATS and Coil Shooting data, respectively. The Coil Shooting data were divided into four azimuth sectors before RTM, then the four partial-stack azimuth data sets were stacked with equal weighting. The Coil Shooting dataset provided an overall improvement in imaging, particularly in the areas of complex structures and steep dips, com-pared with the NATS dataset.
In some areas, steeply dipping reflectors appeared better imaged in the fast track NATS data than in the unweighted stack of the Coil Shooting data. In the presence of complex geology, illumination from different azimuths is likely to lead to images of varying quality. Combining datasets of different azimuths with-out consideration of image quality may lead to destructive stacking. Analysis of predicted sub-surface illumination using ray tracing showed large variations in the offsets and azimuths that would be expected to illuminate different areas and also indicated that destructive stacking was likely to occur in specific offset-azimuth ranges along specified target horizons (right).
To further investigate the variation in azi-muths required to illuminate reflectors around the salt structures, geophysicists applied PSDM
> Survey times. While prime acquisition took about the same time for each of the Calulu PDA surveys, line change and other nonproductive time are much greater for the NATS acquisition.
Primeacquisition
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e, h
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> Offset-azimuth plots. Offset-azimuth plots are shown for four locations in a target horizon (center) around a salt diapir. For each circular plot, distance from the center indicates offset, clockwise deviation from vertical represents azimuth and color represents the illumination, or the number of raypaths passing through that location, with low values in blue and high values in red. The plots indicate large variations in the offsets and azimuths required to illuminate each area. Optimal stacking results are achieved by giving additional weight to data from azimuths that provide the best image.
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to part of the dataset and split the results into 18 azimuth ranges—each of 10°—for stacking. Analysis of the 18 datasets confirmed the corre-lation observed between the seismic imaging and the illumination study (above). The images produced using data from different azimuths exhibited significant differences, indicating that a more intelligent data-adaptive stacking scheme should create a better image than an unweighted method.
Processing experts developed an iterative intelligent stacking scheme to solve the problem of destructive stacking and create an optimal image throughout the 3D volume. Localized weights for each azimuthally migrated image were derived from comparison with a reference image. If the azimuthal image was locally similar to the reference image, its weight was increased, and if it was dissimilar, its weight was decreased. Preliminary results of this iterative stacking scheme suggest that it shows promise for produc-ing optimized results from multiazimuth data (middle left).16
Initial results indicate that the azimuthal richness of the Coil Shooting technique may be beneficial for enhancing imaging in the Calulu PDA. A comparison between the Coil Shooting fast track results and the full processing results of the NATS data acquired at the time demon-strates the effectiveness of the weighting approach (left). Areas of imaging improvements include targets below salt canopies that have
> The impact of azimuth on imaging. PSDM results on a subset of the Calulu PDA Coil Shooting survey were split into 18 azimuth ranges. Each panel illuminates different features. Because ordinary stacking averages these features and enhances only those signals that are common to all panels, it could degrade signal amplitude in the most difficult-to-image areas. This observation led geophysicists to devise a data dependent weighted stacking method that would give preference to azimuths that provided the best illumination.
0° to 10° 10° to 20° 20° to 30° 30° to 40° 40° to 50° 50° to 60° 60° to 70° 70° to 80° 80° to 90°
90° to 100° 100° to 110° 110° to 120° 120° to 130° 130° to 140° 140° to 150° 150° to 160° 160° to 170° 170° to 180°
> Intelligent stacking. Variations in azimuth and offset coverage necessitate a weighted stacking scheme to deliver optimal results. In some areas, data from the NATS survey (left) were similar in quality to those from the Coil Shooting fast track processing (middle). Applying data dependent weighting to azimuth ranges prior to stacking the Coil Shooting data (right) provided an optimized image throughout the dataset.
NATS Data Unweighted Coil Shooting Data Weighted Coil Shooting Data
> Comparing NATS final processing with preliminary Coil Shooting results. The fully processed narrow azimuth, towed streamer data (left) reveal a great deal of structural complexity, but the partially processed Coil Shooting data (right) show areas even more clearly imaged (green boxes). These include features that are poorly imaged in the NATS data such as layers below salt overhangs and deep reflectors that show better lateral continuity.
NATS Final Processing, 20 Hz Coil Shooting, Fast Track Processing, 20 Hz
Spring 2013 53
benefited from FAZ illumination, and deep targets that have benefited from improved S/N resulting from the higher fold. The ongoing final process-ing is focused on fully exploiting the azimuthal richness of the Coil Shooting technique.
Full Azimuth and Long Offsets in the Gulf of MexicoSome geologic environments lead to highly com-plex raypaths. In such environments, adequate illumination of the subsurface often requires not only a full range of azimuths but also very long offsets between seismic sources and receivers. This is the case in some subsalt hydrocarbon plays in deepwater areas of the Gulf of Mexico, which often present severe imaging challenges because of thick salt bodies with complex mor-phology. Multivessel WAZ methods have improved imaging in these areas, but many datasets have exhibited areas of low S/N and poor reflector con-tinuity, particularly beneath salt overhangs and where dip is steep. These areas of poor illumina-tion are often where imaging is most crucial for identifying drilling targets and performing field appraisal. Modeling studies of these areas have indicated that adequate subsalt imaging requires full azimuth coverage and source-receiver offsets of up to 14 km [8.7 mi] (above right).17
Modern 3D surveys in the Gulf of Mexico typi-cally use streamers 8 km [5 mi] long. Because deploying much longer streamers in a circular geometry would be logistically challenging, a single-vessel solution cannot meet the require-ments for long offsets. To deliver the required azimuth and offset ranges in this area, WesternGeco geophysicists designed a four-vessel coil system. It involves two recording vessels with their own sources and two separate source ves-sels sailing in 12.5-km [7.8-mi] diameter inter-linked circles (right). Each streamer vessel has 10 streamers 8 km in length and with 120-m streamer separation. This dual coil design deliv-ers a trace density approximately 2.5 times that of current WAZ survey designs, which improves S/N, further enhancing the imaging of weak sub-salt reflections. The first multivessel coil survey in the Gulf of Mexico was acquired in 2010, and today an area of more than 25,600 km2 [9,880 mi2]—equivalent to about 1,100 Outer Continental Shelf blocks—has been surveyed using the multivessel method. Survey locations have included heavily obstructed areas with cur-rents exceeding 2.5 knots [4.6 km/h, 2.9 mi/h].
The surveys are designed to have a random distribution of sources and receivers. The motiva-tion behind this is twofold: The random shot and
> Improving subsalt illumination with long offsets. Finite-difference acoustic modeling shows the effect of offset length on imaging a reflection package truncating against a salt keel (dashed yellow circles). In a commonly used WAZ recording configuration with a maximum inline offset of 8 km and maximum crossline offset of just over 4,200 m [13,800 ft], reflection truncation against the salt keel is indistinct (left). With a long-offset FAZ Coil Shooting design (right), the reflection truncation is more coherent.
Salt keel
Wide Azimuth Survey, Standard Offsets Coil Shooting Survey, Long Offsets
Reflectionpackage
> Dual coil survey design. The long-offset FAZ Coil Shooting surveys in the Gulf of Mexico have been acquired using two recording vessels with their own sources (S1 and S3) and two separate source vessels (S2 and S4) sailing in 12.5-km diameter interlinked circles.
S1
S3S2
S4
16. Zamboni E, Tchikanha S, Lemaistre L, Bovet L, Webb B and Hill D: “A Coil (Full Azimuth) and Narrow Azimuth Processing Case Study in Angola Deep Offshore,” paper X025, presented at the 74th European Association of Geoscientists and Engineers Conference and Exhibition, Copenhagen, Denmark, June 4–7, 2012.
17. Moldoveanu N and Kapoor J: “What Is the Next Step After WAZ for Exploration in the Gulf of Mexico?,” Expanded Abstracts, 79th SEG Annual International Meeting and Exposition, Houston (October 25–30, 2009): 41–45.
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receiver distribution removes any clustering or repeating pattern that may appear in the cover-age, and compressive sampling theory states that if data are undersampled, the seismic wavefield is better reconstructed if measurements are ran-domly distributed.18 Seismic data acquired in conventional NATS marine surveys are typically
undersampled for both sources and receivers and regularly distributed along parallel lines. Therefore, in any part of the processing sequence that requires interpolation or regularization, the Coil Shooting randomly sampled data will per-form better than conventional data.
One Gulf of Mexico survey was located in an area with several production and drilling installa-tions, representing exclusion zones that required consideration when planning coil locations. To acquire surface seismic data under such obstruc-tions involves deploying sources on one side and receivers on the opposite side of the restricted area—a method called undershooting. The dual coil configuration lends itself to undershooting because a four-boat coil unit can enclose an area with a diameter of approximately 9 km [5.6 mi] without modification. Careful planning of the coil locations enabled the survey crews to undershoot most of the production and drilling facilities without the need to reconfigure. For the three largest obstructions in the survey area, the coil diameter was enlarged to accommodate the exclusion zones. An automated steering and posi-tioning system accurately controlled the loca-tions of the vessels, sources and streamers, which is particularly critical when making passes close to obstructions.
Flexibility in survey design in terms of the shape of the area to be covered is another impor-tant feature of the Coil Shooting technology. While NATS surveys are generally rectangular or have other regular geometric shapes, Coil Shooting survey designs can accommodate any shape so can be optimized to address the res-ervoir or exploration target area. Also, survey areas can be easily extended in any direction after acquisition of an initial program, for exam-ple if interesting new features are identified or the initial survey is completed faster than expected (above left).
The dual coil Gulf of Mexico FAZ datasets have been processed using vertical transverse isotropy or TTI RTM schemes appropriate for the complex geology and steep dips around the sub-salt targets. Processing included 3D prestack acoustic full waveform inversion (FWI), which uses a two-way wave equation method, to build high-resolution velocity models. Full waveform inversion performs forward modeling to compute the differences between the acquired seismic data and the current model and carries out a pro-cess similar to RTM on the residual dataset to compute a gradient volume and to update the velocity model. When combined with imaging using RTM, model building with FWI improved the final product because consistent wavefield solutions were applied throughout the depth imaging workflow. Initial results from the Gulf of Mexico Dual Coil Shooting surveys show signifi-cant improvements over linear WAZ surveys in the same areas (left).
> Coil Shooting design flexibility. The source positions (red coils) of a dual coil survey in an obstructed area of the Gulf of Mexico demonstrate the ability to extend the survey area in any direction. Obstructions are denoted by yellow circles.
> Dual Coil Shooting results. Two datasets were fast track processed using the same preliminary velocity model. The linear WAZ dataset (left) and Dual Coil Shooting dataset (right) both show a strong reflection at the top of salt. The Dual Coil Shooting dataset exhibits improved imaging of the base of salt and better continuity of reflections (dashed yellow circles) beneath the salt body.
Linear WAZ Data
Top of Salt
Dual Coil Shooting Data
Base of Salt
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> Slanting the streamer. In a Gulf of Mexico test, Coil Shooting data from a horizontal streamer (top) and a slant streamer (bottom) demonstrate the broader bandwidth achievable with a slant streamer. Deep reflectors in complex structures, such as those in the yellow boxes, are more clearly imaged with the slant streamer.
Horizontal Streamer
Slant Streamer
To date, the multivessel Coil Shooting tech-nique has focused on imaging challenges in the western Gulf of Mexico; however, it is applicable in other difficult-to-image geologic environments such as where thick layers of basalt are present or where carbonates distort seismic raypaths.
Investigations are ongoing into the use of simultaneous sources to improve source sampling and productivity in multivessel seismic acquisi-tion. The four sources in the current Gulf of Mexico projects are fired sequentially at intervals 17 s apart. By firing four sources at the same time, data density is quadrupled for no extra acquisi-tion cost as long as the resulting wavefields can be recorded separately. With sources spaced at least 12.5 km apart on opposite sides of a coil, there is no overlap of the wavefields for large por-tions of a simultaneous shot record. Modeling studies and a field feasibility test have indicated
that multivessel coil data acquired with simulta-neous sources can be processed effectively.19 Further investigations are underway to confirm that simultaneous shooting can be applied on future multivessel Coil Shooting projects.
Extending the BandwidthCoil acquisition geometries deliver FAZ data and may be configured to deliver long offsets, both of which contribute to improved illumination. Improving resolution, another key objective in the quest to enhance seismic imaging, requires extending the range of usable signal frequencies at both high and low ends.
One of the limiting factors in seismic resolu-tion for marine towed streamer acquisition is the so called “ghost” effect, which results from the receivers being deployed several meters below the sea surface. The ghost effect causes attenua-tion of certain frequencies depending on the receiver depth. The attenuation is caused by interference between the upgoing seismic wave-field and its ghost—the reflection of the wave-field bouncing back from the sea surface above the streamer. Conventional towed streamer marine seismic acquisition systems typically deploy streamers at depths between 6 and 12 m [20 and 39 ft]. Shallower towing would preserve medium and high frequencies but attenuate low
frequencies. Shallower towing would also make the data more susceptible to environmental noise such as waves, swell and wind. Towing streamers at greater depths would reduce environmental noise and preserve low frequencies but would attenuate higher frequencies.
Recent developments in seismic acquisition and processing technologies have enabled the successful implementation of several solutions to address the receiver ghost problem. One solution is to tow the streamers at a slant, resulting in variable receiver depths—and thus attenuating a variable range of frequencies—from one end of the streamers to the other.20 Stacking and migra-tion combine data from different parts of the streamers, attenuating the receiver ghost. However, before these processes, attenuation of multiples and velocity model building must be performed, for which a uniform wavelet is required. To facilitate this, a new algorithm was developed that performs prestack receiver deghosting, and this is applied at an early stage in processing. The source ghost is addressed by a newly developed calibrated marine broadband family of seismic sources.
WesternGeco conducted a feasibility field test with a slant streamer configuration during the multivessel coil acquisition program in the Gulf of Mexico, in which streamers are usually towed at a depth of 12 m. Acquisition of one coil was repeated with the streamers deployed in a slant mode such that receiver depths ranged from 12 m to 32 m [39 to 105 ft]. Comparison of prestack depth migration results for horizontal streamer and slant streamer data indicated that the ObliQ slant streamer acquisition and processing technique enhanced the low frequencies while preserving medium and high frequencies (above left). The preservation of lower frequencies is important not only for imaging deep or steep targets but also for building high-resolution velocity models using FWI. To date, two single-vessel Coil Shooting surveys have been acquired using slant stream-ers, one in Europe and one in Asia. A multivessel Coil Shooting survey using slant streamers has been acquired in the Gulf of Mexico.
Since the first Coil Shooting feasibility tests in 2007, the technique has proved to be a cost-effective and efficient solution for better illumi-nation and improved seismic imaging in complex geologic environments around the world. Further improvements are expected from the implemen-tation of innovative acquisition configurations, advanced processing technologies and new work-flows that will extract more information from seismic measurements to enhance our under-standing of the subsurface. —JK
18. Moldoveanu, reference 11. 19. Moldoveanu N, Ji Y and Beasley C: “Multivessel
Coil Shooting Acquisition with Simultaneous Sources,” paper ACQ 1.6, presented at the 82nd SEG Annual International Meeting and Exposition, Las Vegas, Nevada, November 4–9, 2012.
20. Moldoveanu N, Seymour N, Manen DJ and Caprioli P: “Broadband Seismic Methods for Towed-Streamer Acquisition,” paper Z009, presented at the 74th European Association of Geoscientists and Engineers Conference and Exhibition, Copenhagen, Denmark, June 4–7, 2012.
Seraj Al-Abdulbaqi is a Service Quality Support Manager for NExT, a Schlumberger company; his NExT responsibilities include work with Al-Khafji Joint Operations in Al-Khafji, Saudi Arabia. In 2001, Seraj began his career at Schlumberger as a log data proces-sor; he became the Saudi–Kuwaiti neutral zone data delivery center manager in 2006 and assumed his current position in 2011.
Abdulaziz Alobaydan is the Superintendent of Career Development in the Training and Development Department for Al-Khafji Joint Operations (KJO) in Al-Khafji, Saudi Arabia. He is responsible for career development and special training and development projects. Abdulaziz became an electrical engineer in fire and safety maintenance in 1992 with KJO and has since held various positions with the company. He earned a BS degree in electrical engineering from King Fahd University of Petroleum and Minerals, Dhahran, Saudi Arabia.
Aimen Amer, based in East Ahmadi, Kuwait, is a Principal Geologist for Schlumberger working as a Fracture and Petroleum Systems Specialist. He has served in this capacity for the past 15 years in the Middle East, Africa and the US. He holds a US patent for a new concept of structural dip computation in the subsurface and has taught basic and advanced geology courses in the US, Brazil, Oman, Algeria and Libya. He has performed numerous outcrop studies on modern and ancient depositional environments. Aimen obtained a BS degree in geology and geophysics from Benghazi University, Libya, and an MSc degree in basin and petroleum systems dynamics from Jacobs University Bremen, Germany.
Cosan Ayan is a Reservoir Engineering Advisor and Reservoir Domain Champion for Schlumberger Wireline; he is based in Paris. Previously, he held res-ervoir engineering positions for Schlumberger Testing Services and Data & Consulting Services. He joined the company in 1990 to work with Schlumberger Reservoir Characterization Services in Dubai. Later, he held reservoir engineering positions in Cairo, Aberdeen, Houston, Jakarta and Abu Dhabi, UAE. The author of many papers on well testing and reservoir engineering, he was an SPE Distinguished Lecturer for 2005/2006 and served as executive editor of SPE Reservoir Evaluation & Engineering from 2007 to 2010. Cosan earned a BS degree from Middle East Technical University—where he currently serves as Associate Professor—and MS and PhD degrees from Texas A&M University in College Station, USA, all in petroleum engineering.
Tim Brice is a Principal Geophysicist for WesternGeco in Perth, Western Australia, Australia. He began his career with Schlumberger in 1991 as a field geophysi-cist and has since held multiple positions with the company; he has been involved mainly in survey design and acquisition geophysics. Before this, he worked at Horizon Exploration, Robertson Geologging and Gearhart Industries. Tim has a BS degree in geology from the University of Leeds, England, and an MS degree in geophysics from Imperial College, University of London.
Michele Buia is Geophysical Senior Advisor for the Eni SpA E&P Africa Region and is based at headquar-ters in Milan, Italy. Since 1992, he has held various technical positions in data processing, participated in four-component survey planning, acquisition and pro-cessing projects and managed an R&D project to inte-grate seismic and nonseismic geophysical methods. From 2003 to 2008, he led the Eni seismic processing group. Michele obtained a degree in geology with a specialization in rock mechanics from the University of Bologna, Italy.
Ravi Chhibber is Exploration Systems Advisor at Schlumberger Information Solutions in Houston. He joined the company in 1989 as a processing geophysi-cist in New Delhi, India, and since then has worked in Mumbai, Dubai and Houston. He has been involved in field operations, field studies, software deploy-ment, workflow optimization and marketing. During his career, he has worked on projects for national and international oil companies as well as regional and small companies throughout the world. Ravi earned a bachelor’s degree in science from Punjab University, Chandigarh, India, and a master’s degree in geophysi-cal engineering from the Indian Institute of Technology in Roorkee, Uttarkhand.
Filippo Chinellato, based in Milan, Italy, is Well Placement Domain Champion in charge of geosteering and geology LWD applications for Schlumberger opera-tions in continental Europe. He joined Schlumberger Drilling & Measurements in 2006 as a field engineer in Ecuador. Since 2007, he has worked as a well place-ment engineer and borehole geologist in South America and Europe. He geosteered more than 70 wells worldwide in conventional and unconventional plays for more than 20 operators. Filippo recently par-ticipated in a joint ENI SpA and STOGIT underground gas storage field campaign in Italy and assisted with the first shale gas well placement in Poland. He has an MSc degree in geology from Università di Padova, Italy.
Steve Collins, based in Dallas, is a Petroleum Geologist with Chief Oil & Gas LLC. He began his career in 1982 with the Pitts Energy group as a geolo-gist in the Fort Worth basin in Texas. In 1998, he joined Tejas Western Corporation, a pioneer in the Barnett Shale play in Texas. In 2003, he joined Chief Oil & Gas as a member of the company’s Barnett Shale horizontal drilling development team. In 2007, Chief Oil & Gas began focusing on the Marcellus Shale play in Pennsylvania, USA, and Steve is involved primarily with the Marcellus Shale development team today. He holds a BS degree in geology from Western Carolina University, Cullowhee, North Carolina, USA.
Alex Cooke is an Area Geophysicist with WesternGeco in Brazil. His responsibilities focus on the technical aspects of data processing operations in Rio de Janeiro. He began his career as a geophysical analyst with Western Geophysical in London, working on offshore 3D projects. Then he supervised land, shallow marine and marine processing departments and most recently was the data processing service manager in Gatwick, England. Alex received a BS degree in geophysical sciences from the University of Lancaster, England.
Pierre-Yves Corre is a Schlumberger Engineering Project Leader in Abbeville, France, where he leads the development of high-performance, high-tempera-ture inflatable packers for the MDT* and Saturn* probes. Since beginning his career with the company 18 years ago, he has held various positions, including design engineer, project leader and project manager. Pierre-Yves has a degree in engineering from Université de Technologique de Compiègne, France.
Jean-Michel Denichou is the Schlumberger Well Placement and Geology Domain Head in Sugar Land, Texas, where he is responsible for advising customers in the planning and execution of well placement oper-ations and the development of new well placement solutions. He started his career with Schlumberger in Nigeria as a log analyst in 1996 and two years later focused on well placement, holding positions such as well placement engineer, well placement coordinator, team leader and domain champion. During the last 15 years, he has served in Nigeria, Algeria, Tunisia, Norway, the US and China. He has coauthored several SPE papers and is a member of the AAPG, the SPWLA and the SPE. Jean-Michel obtained his MSc degree in geology from the Institut Catholique de Paris.
Isabelle Dubourg is a Tool Physicist for Schlumberger Drilling & Measurements in Clamart, France. She began her career with Schlumberger in 1988 working on pressure gauges and then helped with the develop-ment of electrode-based formation evaluation tools for openhole, cased hole and LWD logging systems. She has been involved in the physics and interpretation of images from the MicroScope* tool. Her primary areas of responsibility have been physics of measurement, response modeling and answer product development for these tool systems. Isabelle holds a PhD degree in atomic and molecular physics from the Université Paris-Sud, France.
Mauro Firinu is a Project Manager and Geology Operations Team Leader for Eni E&P in Ravenna, Italy. In his 25 years of experience in the oil and gas indus-try, he has served as wellsite geologist, petrophysicist and subsurface geology manager in Europe, Asia, Africa, and the US. Author of several technical papers, Mauro earned a diploma in geology and mining engi-neering from the G. Asproni Technical Mining Institute in Iglesias, Italy.
Germán García, who has more than 17 years of oil-field experience, is the Reservoir Domain Champion for Schlumberger Wireline for Mexico and Central America and is based in Mexico City. He previously was domain champion and provided wireline techni-cal support in the Middle East, the North Sea and in South America. Germán received a BS degree in petroleum engineering from the National University of Colombia in Medellín and has a master’s degree in petroleum engineering with project management from Heriot-Watt University in Edinburgh, Scotland.
Contributors
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Roger Griffiths is the Petrophysics Domain Head for Schlumberger Drilling & Measurements in Petaling Jaya, Malaysia. He joined the company in 1987 as a wireline field engineer and has worked in Asia, the Middle East, Europe, Africa and North America in field, management, engineering and technical posi-tions. He is a Technical Advisor in petrophysics and well placement, has written two books, coauthored numerous technical papers and holds several patents related to petrophysics and well placement. Roger received a degree (Hons) in mechanical engineering from The University of Melbourne, Victoria, Australia.
David Hill, Europe and Africa Technology Manager at WesternGeco in Gatwick, England, joined the company in 2000. He is responsible for geophysical support for the WesternGeco Europe and Africa region. Previously, he worked with Amoco UK for 10 years as an opera-tions geophysicist and designed, acquired and pro-cessed seismic surveys to meet the objectives of exploration and development asset teams. He also held various positions for Western Geophysical from 1978 to 1990, gaining experience in data processing and in geophysical software development. David received a BSc degree (Hons) in physics and geophysics from the University of Liverpool, England.
Abul Jamaluddin is NExT Business Manager for North America and a Schlumberger Flow Assurance Advisor in Houston. He joined Schlumberger in 1998 and has worked in business development and operations man-agement in the Americas, Middle East and Asia. Previously, he served as the NExT unconventional pro-gram director, reservoir sampling and analysis opera-tions manager for the Middle East and Asia, and fluids business development manager for North and South America. He is the coinventor of eight patented pro-cesses and has coauthored more than 100 technical papers. He was named an SPE Distinguished Member in 2012. Abul, who has more than 22 years of industry experience, obtained his PhD degree from the University of Calgary.
Jeffrey D. Johnson is a Consulting Geophysicist and Geology and Geophysics Instructor for NExT in Tulsa. He has 35 years of experience in the oil and gas industry, including technical, supervisory and senior management positions in exploration, reservoir char-acterization and geoscience technology management. Until his retirement from Schlumberger in 2010, he was geology and geophysics curriculum director for NExT, where he designed, coordinated and taught in many NExT training and development programs and projects worldwide. Before joining Schlumberger, he spent 15 years with Amoco as an exploration geophys-icist and technical manager and nine years as gen-eral manager of Amoco geology and geophysics research and technical services. He has BS and MS degrees in geophysics from Stanford University in California, USA, as well as additional technical and business school education.
Nizar Khaled has been a Geophysicist with Total since 2008. From 2010 to 2012, he was in charge of seismic acquisition for Total E&P Angola. Nizar earned an engineering degree from Ecole Polytechnique de Tunisie, Tunis, and an MSc degree in petroleum geosci-ences from Ecole Nationale Supérieure du Pétrole et des Moteurs, Rueil-Malmaison, France. He is based in Luanda, Angola.
Randy Koepsell is a Schlumberger Geology Advisor in Denver. He began his career with Schlumberger in 1980 as a wireline field engineer in Graham, Texas, and has since held various positions within the com-pany, including field service manager, district manager and principal geologist. Randy has coauthored numer-ous papers presented at AAPG, SPWLA, SPE and SEG conferences. He holds a BS degree in mining engineer-ing from the University of Wisconsin-Madison, USA.
Ed Kotochigov is Manager of Marine Global Operations Support for WesternGeco in Oslo, Norway. Previously, he was a marine marketing manager in Gatwick, England. He joined Schlumberger in 1998 as a marine seismic acquisition engineer, working on sev-eral seismic vessels in London and Houston. In 2003, Ed was cross-trained as a reservoir stimulation engi-neer, and in this role he was a DESC* design and eval-uation services for clients engineer for Chevron and BP in Houston. He returned to WesternGeco in 2006 as operations manager in the Arctic and in South America. Ed earned an associate’s degree from the American Institute of Business and Economics, Moscow, and an MS degree in geology and geophysics from the Lomonosov Moscow State University.
Morten R. Kristensen is a Senior Reservoir Engineer with Schlumberger in Abu Dhabi, UAE, where he works on new technology development and deploy-ment for enhanced oil recovery (EOR). He started working for Schlumberger in 2008 developing ECLIPSE* modeling software at the Schlumberger Abingdon Technology Center, England. He specializes in modeling and simulation of advanced recovery pro-cesses and been involved in chemical and CO2 EOR projects in the Middle East. Morten received both MSc and PhD degrees in chemical engineering from the Technical University of Denmark in Lyngby, where he focused on thermal EOR processes.
Stig Lyngra is a Petroleum Engineering Consultant with Saudi Aramco in Dhahran, Saudi Arabia. He began his career in 1987 with Conoco, Inc., where he spent 10 years as a reservoir engineer, commercial coordinator and in various joint asset management positions in the US, Norway and the UK. He then became the discipline leader for petroleum engineer-ing for Danop in Denmark. In early 2000, after this company was taken over by DONG, The Danish National Oil Company, he became asset manager. In his 12 years with Saudi Aramco, he has coauthored 25 publications on topics ranging from completions tech-nology, reservoir and fracture characterization and reservoir simulation and microgravity to electromag-netic R&D on interwell saturation surveillance tech-niques. Stig has an MS degree in petroleum engineering from the Norwegian Institute of Technology, Trondheim, and a degree in business administration from the BI Norwegian School of Management in Stavanger.
Catherine MacGregor is President of Schlumberger Wireline. After joining the company in 1995 as a field engineer with Sedco Forex, she held diverse manage-ment and marketing positions throughout Europe, Asia and the US for Schlumberger Drilling & Measurements. In early 2007, she became Schlumberger personnel director and later that year was appointed vice presi-dent personnel for Schlumberger Limited. She was named to her present position in 2009. Catherine holds degrees in general engineering and aerospace engineer-ing from Ecole Centrale de Paris and a diploma in advanced studies of energetics and heat transfer. She is based in Clamart, France.
Philippe Marza is a Schlumberger Principal Geologist in Aberdeen. He began his career in 1997 working as a borehole geologist in West Africa, North Africa and the North Sea until 2005. After holding a technical support position, he was in charge of the design of the eXpandBG* software, a Petrel* plug-in dedicated to structural analysis and modeling based on borehole images. In 2012, he returned to the North Sea region to develop advanced structural interpretations of LWD measurements. Philippe teaches courses on structural analysis and modeling based on borehole image inter-pretation; he received a PhD degree in geology from Montpellier University, France.
Nick Moldoveanu started his career with Schlumberger in 1989 and has had various assign-ments in data processing, software development, geo-physical support for acquisition and processing, seismic survey design and the development and com-mercialization of seismic acquisition and processing technologies. Currently, he is the Global Geophysical Advisor for Seismic Solution Design and Modeling in Houston. Before joining Schlumberger, he worked for the Geological and Geophysical Oil Prospecting Company (IPGG), Bucharest, Romania, as a field geo-physicist, seismic interpreter, seismic technology ana-lyst, data processing manager and technical director of the IPGG seismic computer center. He earned a degree in geophysics from the Romanian Oil, Gas, and Geology Institute, Faculty of Geology and Geophysics, Bucharest, and a degree in mathematics from the University of Bucharest. Nick has more than 60 pub-lished technical papers, holds 10 patents and has 12 patent applications under review.
Lynn Murphy is the Manager of the NExT Technical, Management and Software Customer Training Business in Houston, a position she has held since 2010. Lynn began working for Schlumberger in 2000 and has served in a variety of Schlumberger GeoMarket* business management roles. Previously, she spent 20 years at numerous large and medium independent oil and gas operators in Houston. Lynn holds a bachelor’s degree in geology and environmen-tal science from Thiel College in Greenville, Pennsylvania.
Spring 2013 57
Murat Zeybek is a Schlumberger Reservoir Engineering Advisor and Reservoir and Production Domain Champion for the Middle East. His work focuses on analysis and interpretation of wireline for-mation testers, pressure transient analysis, numeri-cal modeling of fluid flow, water control, production logging and reservoir monitoring. He has written more than 50 technical publications and has served on a variety of SPE technical review committees. Murat earned a BS degree from the Istanbul Technical University, Turkey, and MS and PhD degrees from the University of Southern California in Los Angeles, all in petroleum engineering. He is based in Dhahran, Saudi Arabia.
1998, he ran the first LWD quad combo job in India. Since 2001, he has worked in interpretation of LWD measurements and has introduced new technology, mainly in Saudi Arabia and India. These new technol-ogy introductions include the first well placement ser-vices using real-time images for Saudi Aramco, the first seismic-while-drilling application in India, first deployment of EcoScope* multifunction LWD in India and the introduction of the PeriScope* electromag-netic (EM) boundary mapping tool to India; most recently, he has overseen the introduction of a new deep EM LWD tool in Saudi Arabia. He has published widely in many professional journals, mainly on LWD applications. He has served on the board of directors of SPWLA India. Bob teaches courses in geosteering and interpretation of LWD measurements and their applications. He holds a BSc degree in geology from the University of Edinburgh, Scotland.
Sérgio Tchikanha is a Processing Supervisor Geophysicist for Total E&P Angola in Luanda, a posi-tion he has held since 2010. Sérgio earned a BS degree in physics engineering from the University of Lisbon, Portugal, and an MS degree in geosciences from the Institut Français du Pétrole, Rueil-Malmaison, France.
Chris Tevis is a Product Champion with Schlumberger at the Houston Pressure and Sampling Center in Sugar Land, Texas. Before this, he was a field engineer, an engineer in charge, a field service manager and quality operations support manager in China, Southeast Asia and the US. Chris obtained a BS degree in mechanical engineering from Columbia University, New York City, and is pursuing an MSc degree in oil and gas industry management from Heriot-Watt University, Edinburgh, Scotland.
Kalyanaraman Venugopal is a Project Manager for NExT in Houston and manages the NExT shale gas training program for Saudi Aramco. He started his career in 1995 as an MWD and LWD engineer with Drilling & Measurements (then known as Anadrill) in Al-Khobar, Saudi Arabia. In 18 years with Schlumberger, he has held a variety of managerial positions with Drilling & Measurements, Oilfield Services and Data & Consulting Services in worldwide locations. He has an integrated dual degree in electri-cal and electronics engineering and an MSc degree in mathematics, both from the Birla Institute of Technology & Science, Pilani, Rajasthan, India.
Enrico Zamboni is a Geophysicist at Total E&P Angola in Luanda and began his career with the company in 2008. He has more than 12 years of experience in the industry; he has also worked as a geophysicist at Eni SpA and as a research geophysicist at the University of Milan, Italy. Enrico received an MA degree in physics from the University of Milan.
Luigi Zappalorto is a Senior Operations Geologist with Eni Norge SA in Stavanger. Prior to his current position, he was an operations geologist in Italy and Tunisia. Luigi holds a BS degree in geology and an MS degree in EU environmental policy for sustainable development from the G. d’Annunzio University of Chieti-Pescara, Italy.
Doug Murray is LWD Domain Champion and Petrophysics Advisor for Schlumberger in Abu Dhabi, UAE. Since joining Schlumberger in 1982, he has held various positions in the field and in management, engi-neering and formation evaluation. His career includes assignments in Canada, Algeria, Nigeria, Saudi Arabia, Trinidad and Tobago, Argentina, Japan and China. Doug has a BS degree in electrical engineering from Lakehead University, Thunder Bay, Ontario, Canada, and an MA degree in management from the University of Hull, Yorkshire, England. He is a member of the SPWLA, the SPE and SEG.
Michael O’Keefe is Principal Reservoir Engineer for Schlumberger Global Accounts in London, where he provides technical advice and customer support on exploration and appraisal projects across Africa and Europe. Since joining the company as a wireline field engineer in Austria, he has held positions in interpre-tation, product development, marketing and wireline operations in locations around the world. He is the author of more than 22 technical and industry articles and holds seven granted patents. As a member of the Quicksilver Probe* development team, he received the Hart’s Meritorious Engineering Award in 2006. He has been awarded two Performed by Schlumberger Gold Medals, was an SPWLA Distinguished Lecturer in 2010 and is a 2013/2014 SPE Distinguished Lecturer. Michael holds a bachelor’s degree in electrical engi-neering from the University of Tasmania, Australia.
Ed Palmer is a Solution Design and Modeling Manager for WesternGeco in Gatwick, England. He manages the solution design and modeling business in Europe and Africa. He began his career in 1976 with the Republic of South Africa Department of Minerals and Energy, collecting and interpreting geophysical data for groundwater, diamond and mineral exploration proj-ects. In 1979, he returned to England to work for Geophysical Service Inc. (GSI) in seismic data pro-cessing. As GSI evolved into Halliburton Geophysical Services, Western Geophysical and then WesternGeco, Ed gained experience in supervising 2D, 3D and 4D marine data processing projects and, more recently, advanced integrated projects around the world. He earned a BSc degree (Hons) in physics and geophysics from the University of Liverpool, England.
Thomas Pfeiffer is a Senior Reservoir Domain Champion for Schlumberger Wireline in Stavanger. He joined Schlumberger as a wireline field engineer in 2002 and has worked in the North Sea, Europe and the Gulf of Mexico. As a subject matter expert, Thomas provides technical support to wireline forma-tion testing services and integrates the acquired data in reservoir engineering workflows. He is a coauthor of seven publications on downhole fluid analysis and a coinventor of a US patent application. Thomas received BS and MS degrees in electrical engineering from the Technical University of Munich, Germany, and an MS degree in petroleum engineering from Texas A&M University in College Station.
Iwan (Bob) Roberts is a Schlumberger Drilling & Measurements Principal Geoscientist in Dhahran, Saudi Arabia. He began his career in 1988 with Schlumberger as a mud logging geologist and then became an MWD and LWD engineer in Aberdeen. In
58 Oilfield Review
An asterisk (*) is used to denote a mark of Schlumberger.
Spring 2013 59
NEW BOOKS Coming in Oilfield Review
Multistage Stimulation. Liquid-rich shales are delivering on their early promise as high-volume sources of new oil. But these ultralow-permeability formations can be accessed and produced only by stimulating many intervals along lengthy horizontal wellbores. New multistage stimulation technology allows operators to improve comple-tion efficiency even as they drill longer wells and the number of intervals to be treated increases accordingly.
Routine Core Analysis. The nature of subsurface exploration forces oil and gas companies to investigate each reservoir remotely, primarily through well logs, seismic surveys and well tests. Cores, however, provide operators with physical samples of rock and fluids that can be measured directly to yield valuable information. Careful testing and analysis of these samples allow operators to determine whether the rock contains fluid-filled pores, whether those pores contain hydro-carbons, and if so, whether those hydrocarbons can be produced. The process of routine core analysis helps answer these questions and more.
Workflow Software for Stimulations and Completions. Schlumberger engineers have created workflow software for designing, simulating and analyzing hydraulic fracture stimulations and comple-tions. A completion advisor tool enables a systematic, engineering design approach that improves stim-ulation effectiveness and increases well production. Advances in hydrau-lic fracture simulation software enable integrated fracture design and evaluation. The workflow allows completion engineers to close the completion design loop, from reser-voir characterization to stimulation plan, monitoring and calibration and, finally, production evaluation.
Lynn Margulis: The Life and Legacy of a Scientific RebelDorion Sagan (ed)Chelsea Green85 North Main Street, Suite 120White River Junction, Vermont 05001 USA2012. 224 pages. US$ 27.95 ISBN 978-1-603-58446-3
Lynn Margulis, who passed away in 2011, was best known for her work on the origins of eukaryotic cells, the Gaia hypothesis and symbiogenesis as a driving force in evolution. This collec-tion of essays about her, edited by her son and collaborator, reveals her life and legacy through descriptions of her scientific collaborations and the application of her intellectual energy and interests.
Contents:
Tale of Tales; Erudition; As Above, So Below; On Lynn from a Close Friend and Colleague; Gaia Is Not an Organism: Scenes from the Early Scientific Collaboration Between Lynn Margulis and James Lovelock
The Passionate Lynn Margulis; Lynn Margulis and Stephen Jay Gould; Too Fantastic for Polite Society: A Brief History of Symbiosis Theory; Kingdoms and Domains: At Work on the Linnaean Task; The Battle of Balliol; Science, Music, Philosophy: Margulis at Oxford; Neo-Darwinism and the Group Selection Controversy
Sippewissett Time Slip; The Cultural Dimensions of Lynn Margulis’s Science; Lynn Margulis on Spirituality and Process Philosophy; A Ferocious Intelligence; Fishermen in the Maelstrom: Big History, Symbiosis, and Lynn Margulis as a Modern-Day Copernicus
Gaiadelic: Lynn Sagan and LSD; Two Hit, Three Down—The Biggest Lie: David Ray Griffin’s Work Exposing 9/11; No Subject Too
Sacred; Next to Emily Dickinson; Jokin’ in the Girls’ Room; An Education; There Should Be Other Prizes; With Love and Squalor
. . . this is a captivating read for anyone interested in what powers great scientists.
Publishers Weekly
In this thoughtful and expertly curated collection, Margulis’s son and long-time collaborator, Dorion Sagan, calls her ‘indomitable Lynn.’ . . . In other essays, Margulis’s complex personality beguiles, frus-trates, charms, and elevates various writers, resulting in a stunning portrait that no single remembrance could have captured. . . . Taken as a whole, Sagan’s collection is a fitting tribute to a woman whose life and legacy have touched so many others.
ForeWord Reviews
https://www.foreword
reviews.com/reviews/lynn-margulis/ (accessed
January 11, 2013).
The Million Death Quake: The Science of Predicting Earth’s Deadliest Natural DisasterRoger MussonPalgrave Macmillan Ltd,a division of St. Martin’s Press LLC175 Fifth AvenueNew York, New York 10010 USA2012. 272 pages. US$ 27.00
Seismologist Roger Musson describes the tectonic forces driving earthquakes and tsunamis and highlights locations that are vulnerable to these geologic forces. Musson also explores what scientists and engineers are doing to prepare our most populated places for future earthquakes.
Contents:
Screaming Cities; What Is an Earthquake, Anyway?; Journey to the Center of the Earth; Tracking the Unseen; How Big? How Strong?; The Wave That Shook the World
Prevention and Cure; Next Year’s Earthquakes; Twenty-Five Seconds for Bucharest; Earthquakes Don’t Kill People, Buildings Do; The Probability of Disaster; Stay Safe
. . . an excellent read presenting the levelheaded detachment of an academic expert in the entertaining guise of a popular science book.
Engineering and
Technology Magazine
. . . people with no background in Earth sciences can understand every word of it; its author is the head of seismic hazard for the British Geological Survey and writes with authority. . . .
The Guardian
Musson provides a lay-reader-friendly guide to seismology funda-mentals, from early theories about earthquake origins to the workings of contemporary plate tectonics. . . . Musson demonstrates why his exper-tise is much in demand in the wake of each new quake by keeping readers absorbed with clear explanations and colorful anecdotes about one of nature’s most calamitous forces.
Booklist Online
Lynn Margulis
The Life and Legacy of a S C I E N T I F I C R E B E L
E D I T E D BY D O R I O N S A G A N
Oilfield Review60
Seismic Imaging and Inversion: Application of Linear Inverse TheoryRobert H. Stolt and Arthur B. WegleinCambridge University Press32 Avenue of the AmericasNew York, New York 10013 USA2012. 416 pages. US$ 125.00ISBN: 978-1-107-01490-9
Intended as a resource for working geoscientists, programmers and theo-retical physicists, this book is the first volume in a proposed two-volume series. The authors present an overview of modeling, migration, imaging and inversion and the relationships between these technologies. Also included is a discussion of linear inverse scattering theory to extract information from seismic data.
Contents:
The prevailing view of imaging and inversion technologies is that they are separate and unrelated. A key contribution of this new volume is to demonstrate the relationship that exists between the two through inverse scattering theory. . . . I believe this series represents an important contri-bution to geophysical literature.
The Leading Edge
Global Environment: Water, Air, and Geochemical Cycles, Second EditionElizabeth Kay Berner and Robert A. Berner Princeton University Press41 William StreetPrinceton, New Jersey 08540 USA2012. 460 pages. US$ 85.00ISBN 978-0-691-13678-3
The updated edition of this textbook takes a global approach to geochemistry and environmental problems involving water. The new edition, which intro-duces basic concepts of meteorology, surficial geology, biogeochemistry, limnology and oceanography, is intended for students and those doing research on global geochemical and environmental issues.
Contents:
This excellent book is a compre-hensive treatment of the entire field, intended as an advanced under-graduate or early postgraduate text. With its broad scope and extensive references, it will also be useful to researchers working in the many related areas. . . . It is well organized, clearly written and presented, effec-tively illustrated, and thoroughly referenced to the primary literature. Without doubt, it will be a standard text for years to come.
The Leading Edge
Reverse Innovation: Create Far from Home, Win EverywhereVijay Govindarajan and Chris TrimbleHarvard Business Publishing60 Harvard WayBoston, Massachusetts 02163 USA2012. 256 pages. US$ 30.00
Innovation no longer travels only from developed to developing nations say the authors, who claim the concept of reverse innovation is on the rise and that implica-tions for global emerging markets are profound. The authors follow companies such as General Electric Company, Deere & Company and PepsiCo to illustrate how these corporations have used reverse innovation in emerging markets.
Contents:
The Future Is Far from Home; The Five Paths of Reverse Innovation; Changing the Mind-Set; Changing the Management Model
Logitech, and the Mouse That Roared; Procter & Gamble, Innovating the “Un-P&G” Way; EMC Corporation, Planting Seeds; Deere & Company Plows Under the Past; How Harman Changed Its Engineering Culture; GE Healthcare in the Heart of India; PepsiCo’s Brand-New Bag; Partners in Health’s Radical Model for Care; A Call to Action
. . . Vijay Govindarajan and Chris Trimble make a compelling argument for companies to not just widen their lens, but shift it to a completely different context—that of developing economies.
strategy+business
. . . a book that offers provocative insights into the quickly changing dynamics of the global economy.
The Wall
Street Journal
Solved Problems in GeophysicsElisa Buforn, Carmen Pro and Agustín UdíasCambridge University Press32 Avenue of the AmericasNew York, New York 10013 USA2012. 264 pages. US$ 50.00
The authors offer a collection of nearly 200 problems in geophysics and solve them, showing steps in the solutions, the equations and the assumptions made. The equations, which are com-monly used to solve geophysical prob-lems, are applied to a series of exercises addressing classical areas of geophysics.
Contents:
Gravity; Geomagnetism; Seismology; Heat Flow; Geochronology
Terrestrial Geoid and Ellipsoid; Earth’s Gravity Field and Potential; Gravity Anomalies, Isostasy; Tides; Gravity Observations
Main Field; Magnetic Anomalies; External Magnetic Field; Main (Internal), External, and Anomalous Magnetic Fields; Paleomagnetism
Elasticity; Wave Propagation. Potentials and Displacements; Reflection and Refraction; Ray Theory. Constant and Variable Velocity; Ray Theory. Spherical Media; Surface Waves; Focal Parameters
Heat Flow; Geochronology
Although not a textbook in its own right, it does make an excellent companion to any quality geophysics textbook, with its nearly 200 solved problems in which theory and advanced mathematics are kept to a minimum. Clear, simple explanatory figures accompany most of the prob-lems. . . . Given this reviewer’s own struggles to comprehend complex geophysical phenomena when he was a student, he would have found this book of considerable value. Highly recommended.
Choice
Spring 2013 61
Digital Wars: Apple, Google, Microsoft and the Battle for the InternetCharles ArthurKogan Page Limited1518 Walnut Street, Suite 1100Philadelphia, Pennsylvania 19102 USA2012. 272 pages. US$ 19.95ISBN: 978-0-7494-6413-4
In 1998, Microsoft was on the verge of becoming the highest-valued company in the world, Apple was quite small by comparison and Google a startup. In 2012, Apple was worth more than Microsoft and Google combined. This book examines what happens—starting with the 1998 antitrust case in which Microsoft was accused of abusing monopoly power on its computers— as these three technology companies wrestled to control what was evolving into the network connecting the world.
Contents:
does more than rehash familiar stories of these industry giants, instead focusing on overarching narratives complete with an accounting of the victories and losses of each. . . . is a must-read for a view of [Steve] Jobs’ doppelganger, Apple, and the other companies that waxed and waned in no small part due to his genius.
New York Journal of Books
Great Inventions That Changed the WorldJames WeiJohn Wiley & Sons, Inc.111 River StreetHoboken, New Jersey 07030 USA2012. 360 pages. US$ 49.95ISBN 978-0-470-76817-4
Inventions from the stone axe to the internet, author James Wei posits, have been spurred by basic human needs such as food, health and security. Wei examines the role of inventors and their work and the impact these creations have had on society, our lives and the environment. The book looks at how inventions have not only solved prob-lems but also created problems such as climate change and bioterrorism.
Contents:
Inventors and Inventions; Innovation, Development, Diffusion; Changing the World
Tools and Methods; Energy and Power; Materials
Food, Clothes, and House: Food; Clothes; House
Prevention; Diagnostics; Therapy; Reproduction
Natural Threats; Economic Threats; Human Violence: War
Land Transportation; Water Transportation; Air and Space Transportation
Observation; Records; Communication; Information Tools
Party and Play; Luxury; Arts
Future Needs and Opportunities; Future Sources of Inventions
James Wei . . . has written a remark-able and wide ranging work that spans human development from the stone age to the computer age. Every page contains information that made me admire the breadth and depth of his knowledge. . . . undoubtedly a major work that is nothing less than superb.
Chemistry
World
Henri Poincaré: A Scientific BiographyJeremy GrayPrinceton University Press41 William StreetPrinceton, New Jersey 08540 USA2013. 616 pages. US$ 35.00
Math historian Jeremy Gray explores the life of Henri Poincaré, whose theorem about the characterization of a 3D sphere remained unsolved for nearly 100 years. The author looks at Poincaré’s accomplishments in math-ematics, physics and the philosophy of science as well as the debates sparked by his investigations and the impact his discoveries have had on society.
Contents:
Views of Poincaré; Poincaré’s Way of Thinking
Poincaré and the Three Body Problem; Poincaré’s Popular Essays; Paris Celebrates the New Century; Science, Hypothesis, Value; Poincaré and Projective Geometry; Poincaré’s Popular Writings on Physics; The Future of Mathematics; Poincaré Among the Logicians; Poincaré’s Defenses of Science
Childhood, Schooling; The Ecole Polytechnique; The Ecole des Mines; Academic Life; The Dreyfus Affair; National Spokesman; Contemporary Technology; International Representative; The Nobel Prize; 1911, 1912; Remembering Poincaré
The Competition; Fuchs, Schwarz, Klein, and Automorphic Functions; Uniformization, 1882 to 1907
Flows on Surfaces; Stability Questions; Poincaré’s Essay and Its Supplements;
Poincaré Returns
Rotating Fluid Masses
Theories of Electricity Before Poincaré: Maxwell; Poincaré’s Electricité et Optique, 1890; Larmor and Lorentz: The
Electron and the Ether; Poincaré on Hertz and Lorentz; St. Louis, 1904; The Dynamics of the Electron; Poincaré and Einstein; Early Quantum Theory
Function Theory of a Single Variable; Function Theory of Several Variables; Poincaré’s Approach to Potential Theory; The in Göttingen, 1909
Topology Before Poincaré; Poincaré’s Work, 1895 to 1905
Number Theory; Lie Theory; Algebraic Geometry
Thermodynamics; Probability
Poincaré: Idealist, Skeptic, or Structural Realist?
Elliptic and Abelian Functions; Maxwell’s Equations; Glossary
. . . Jeremy Gray’s biography stands out because it is so long, drenched in mathematical and biblio-graphical detail, and offers several chronologies from diverse disciplin-ary perspectives. . . . It is a compre-hensive but uncluttered guide to Poincaré’s extensive oeuvres that is technical, even though it omits techni-calities, and deep, even though it raises more questions than it answers.
Science Magazine
It would be petty to find faults in a work of this caliber, but some reference to Louis Bachelier would have been welcome. He was the visionary of the Black–Scholes options pricing formula of modern financial theory . . . and one of Poincaré’s handful of doctoral students.
On the whole, however, this book is an achievement in its own right. Gray keeps the tone light and embeds each of the equations in explanatory text. . . . Fortunately, Gray also tells it like it was, warts and all.
Nature
Oilfield Review62
Earthmasters: The Dawn of the Age of Climate EngineeringClive Hamilton Yale University Press302 Temple StreetNew Haven, Connecticut 06511 USA2013. 264 pages. US$ 28.00ISBN 978-0-300-18667-3
Giving arguments both for and against climate engineering, the author explores the technologies being devel-oped in the field of geoengineering—the manipulation of Earth’s climate systems to address the effects of greenhouse gas emissions. The author also discusses the interests that link researchers, venture capitalists and corporations and explores the public’s discomfort with the concept of geoengineering.
Contents:
Clive Hamilton . . . provides a thorough, frank and, at times, chilling account of the technologies, the key players, ethical implications, poten-tial benefits and disturbing risks.
Engineering and
Technology Magazine
Hamilton has put together a smart, timely book. In places it has a philosophical detachment but overall it is more an activist’s work, a kind of soft polemic.
I doubt that he will win over many of geo-engineering’s adherents because he gives his own arguments the benefit of the doubt rather more than theirs.
Times Higher
Education
Atmosphere, Clouds, and ClimateDavid RandallPrinceton University Press41 William StreetPrinceton, New Jersey 08540 USA2012. 288 pages. US$ 75.00ISBN: 978-0-691-14374-3
The author, a professor of atmospheric science, gives an overview of atmo-spheric processes, how they work and how phase changes of water influence weather and climate. One in the series of Princeton Primers in Climate, this book is intended for students, research-ers and those with an interest in the Earth’s climate.
Contents:
This small-format book is short . . . and called a primer. This should not be taken to suggest that it is some form of ‘Climate change for dummies’—the physics is rigorous . . . and as with the atmosphere, many of the physical concepts are complex and often counter-intuitive. The book . . . assumes no background in atmospheric physics. . . . [T]his primer does exactly what it sets out to do—provide a concise but rigorous introduction to a complex subject that affects us all on all scales.
The Leading Edge
. . . Randall provides readers with an impressively thorough conceptual understanding of the atmosphere’s central role in climate.
Science Magazine
Interop: The Promise and Perils of Highly Interconnected SystemsJohn Palfrey and Urs GasserBasic Books, a member ofThe Perseus Books Group387 Park Avenue SouthNew York, New York 10016 USA2012. 304 pages. US$ 28.99
Technology experts John Palfrey and Urs Gasser explore the importance of standardization and interoperability as our world becomes more connected and show how the concept of interoperabil-ity is a critical component of any successful system. The authors also consider the negative effects of interop-erability but argue that despite the inherent negatives, global technology integration and innovation can flourish with a stable foundation of interoperability.
Contents:
The Technology and Data Layers; The Human and Institutional Layers
Consumer Empowerment; Privacy and Security; Competition and Uniformity; Innovation; Systemic Efficiencies; Complexity
Getting to Interop; Legal Interop; Interop by Design: The Case of Health Care IT; Interop over Time: Preservation of Knowledge; Architectures of the Future: Building a Better World; Conclusion: The Payoff of Interop as Theory
will serve as a construc-tive and motivating resource for policymakers, citizens, and practitio-ners interested in the outcome of
emerging, hyperconnected areas such as smart-grid energy infrastructures, cloud computing, and eHealth sys-tems or in ensuring our ability to preserve digitally stored culture and knowledge for generations to come.
Science
Palfrey and Gasser have a record of taking up a concept early and writing about it accessibly and informatively. . . . [They] are at their best when discussing how regulation and legislation can promote interop-erability. . . . This issue, the authors stress, is not about making systems the same, but about maintaining diversity while identifying key areas of contact: an important point well made.
Nature
Drilling fluids serve many functions: controlling formation pressures, removing cuttings from the wellbore, sealing permeable formations encoun-tered while drilling, cooling and lubricating the bit, transmitting hydraulic energy to downhole tools and the bit and, perhaps most important, main-taining wellbore stability and well control. Often referred to as mud, drilling fluid was first introduced around 1913 for subsurface pressure control. The 1920s and ’30s saw the birth of the first US companies specializing in the distribution, development and engineering of drilling fluids and compo-nents. In the decades that followed, drilling fluid companies introduced developments in chemistry, measurement and process engineering that led to significant improvements in drilling efficiency and well productivity.
Drilling fluid compositions vary based on wellbore demands, rig capa-bilities and environmental concerns. Engineers design drilling fluids to con-trol subsurface pressures, minimize formation damage, minimize the potential for lost circulation, control erosion of the borehole and optimize drilling parameters such as penetration rate and hole cleaning. In addition, because a large percentage of modern wellbores are highly deviated, drill-ing fluid systems must help manage hole cleaning and stability problems specific to these wells.
Drilling Fluid SystemsDrilling fluid systems have a continuous phase, which is liquid, and a dis-continuous phase comprising solids. On occasion, they also have a gas phase—either by design or as a result of formation gas entrainment. The continuous phase may be used to categorize drilling fluid types as gas, aque-ous fluids or nonaqueous systems. These fluids are a blend of liquid and solid components, each designed to modify a specific property of the drilling fluid such as its viscosity and density.
Aqueous drilling fluids, generally referred to as water-base muds, are the most common and the most varied of the three drilling fluid types (above right). They range in composition from simple blends of water and clay to complex inhibitive, or clay stabilizing, drilling fluid systems that include many components. In recent years, engineers and scientists have focused on improving the inhibitive and thermal performance of water-base systems in efforts to compete with the nonaqueous fluids typically used in challenging drilling environments.
In nonaqueous drilling fluids, commonly referred to as synthetic-base muds, the continuous phase may consist of mineral oils, biodegradable esters, olefins or other variants. Although typically more costly than aque-ous drilling fluids, these systems tend to provide excellent borehole control, thermal stability, lubricity and penetration rates, which may help reduce overall cost for the operator.
In fractured rock or environments where the borehole will not support a column of water without significant fluid loss to the formation, drillers use air, mist or foam systems to help remove cuttings from the hole and main-tain wellbore integrity.
Basic FunctionsDrilling fluids are formulated to carry out a wide range of functions. Although the list is long and varied, key performance characteristics are the following:
Controlling formation pressures—Drilling fluid is vital for maintaining control of a well. The mud is pumped down the drillstring, through the bit, and back up the annulus. In open hole, hydrostatic pressure exerted by the mud column is used to offset increases in formation pressure that would otherwise force formation fluids into the borehole, possibly causing loss of well control. However, the pressure exerted by the drilling fluid must not exceed the fracture pressure of the rock itself; otherwise mud will escape into the formation—a condition known as lost circulation.
Removing cuttings from the borehole—Circulating drilling fluid carries cuttings—rock fragments created by the bit—to the surface. Maintaining the fluid’s ability to transport these solid pieces up the hole—its carrying capacity—is key to drilling efficiently and minimizing the potential for stuck pipe. To accomplish this, drilling fluid specialists work with the driller to carefully balance mud rheology and flow rate to adjust carrying capacity while avoiding high equivalent circulating density (ECD)—the actual mud density plus the pressure drop in the annulus above a given point in the borehole. Unchecked, high ECD may lead to lost circulation.
Cooling and lubricating the bit—As the drilling fluid passes through and around the rotating drilling assembly, it helps cool and lubricate the bit. Thermal energy is transferred to the drilling fluid, which carries the heat to the surface. In extremely hot drilling environments, heat exchangers may be used at the surface to cool the mud.
Transmitting hydraulic energy to the bit and downhole tools—Drilling fluid is discharged through nozzles at the face of the bit. The hydraulic energy released against the formation loosens and lifts cuttings away from the formation. This energy also powers downhole motors and other hard-ware that steer the bit and obtain drilling or formation data in real time. Data gathered downhole are frequently transmitted to the surface using mud pulse telemetry, a method that relies on pressure pulses through the mud column to send data to the surface.
Maintaining wellbore stability—The basic components of wellbore sta-bility include regulating density, minimizing hydraulic erosion and control-ling clays. Density is maintained by slightly overbalancing the weight of the mud column against formation pore pressure. Engineers minimize hydrau-lic erosion by balancing hole geometry against cleaning requirements, fluid carrying capacity and annular flow velocity. The process of clay control is complex. Clays in some formations expand in the presence of water, while others disperse. To some degree, these effects can be controlled by modify-ing the properties of the drilling fluid. Regardless of the approach used, controlling the fluid’s effect on the formation helps control the borehole and the integrity of the cuttings and leads to a cleaner, more easily main-tained drilling fluid.
Spring 2013 63
DEFINING DRILLING FLUIDS
Drilling Fluid Basics
Oilfield Review Spring 2013: 25, no. 1.
Copyright © 2013 Schlumberger.For help in preparation of this article, thanks to Daryl Cullum and Sonny Espey, Houston; and to Ole Iacob Prebensen, Sandnes, Norway.
Don WilliamsonContributing Editor
> Bentonite drilling fluid being mixed and agitated.
Oilfield Review64
DEFINING DRILLING FLUIDS
Drilling Fluid Life CycleDrilling fluid design and maintenance are iterative processes affected by surface and downhole conditions. These conditions change as the well is drilled through deeper formations and encounters gradual increases in tem-perature and pressure and the mud undergoes alterations in chemistry brought about by different types of rock and formation fluids (above). Onsite fluid specialists and staff engineers use continuous process engi-neering to fine-tune the drilling fluid in response to changing borehole con-ditions then evaluate fluid performance and modify fluid properties in an ongoing cycle.
Initial design—In the planning phase, fluid experts select mud system types and designs for each borehole section. The systems are designed to meet several specifications, including density requirements, borehole sta-bility, thermal gradients, logistics and environmental concerns. Drilling may begin with a simple fluid system. Water is often the first fluid used for drilling to the initial casing point. As the borehole deepens, increasing for-mation pressure, rising temperature and more-complex formations require higher levels of mechanical wellbore control and hole cleaning capacity. Simple fluid systems may be displaced or converted to weighted water-base inhibitive mud, followed at greater depths by nonaqueous drilling fluids.
Circulation—The drilling fluid’s character constantly evolves. In one circulation cycle, the fluid has expended energy, lifted cuttings, cooled the
bit and hole and then released waste at the surface. This requires engineers and fluid specialists to continuously evaluate and recharge the system with fresh fluids and other additives.
Measurement and redesign—The drilling fluids specialist measures certain properties of the returning mud. The specific properties measured are generally a function of the fluid type that is used, but typically include density, rheology, filtration rate, continuous phase content and ratios and solids content and classification. The fluid is further analyzed for pH, hardness, alkalinity, chlorides, acid gas content and other parameters specific to certain fluid types. The specialist then designs a treatment pro-gram for the next 12 to 24 hours. The driller, derrickman and fluids spe-cialist constantly monitor borehole conditions and characteristics of the returning fluid then make adjustments to the mud as hole and drilling conditions dictate.
A Century of Continual Development From humble beginnings about 100 years ago, drilling fluids have evolved as a science, an engineering discipline and an art. Scientists and product developers create new fluid designs that address the many demands placed on modern drilling fluids, while engineers and fluid specialists in the field continue to find new ways to monitor, measure, simulate and manage the drilling fluid life cycle.
Standpipe
Flowline
Rotary table
Shale shakerBlowout preventer
The mud is pumped from the suction tank, up the
standpipe, down the kelly and through the
drillpipe on its way downhole to the bit.
The mud returns up the annulus degraded by downhole conditions,dehydrated and loaded with formation solids.
At the surface, the mudflows down the flowline to the shale shakers where larger formation solids are removed. Further cleaning occurs as the fluid flows through the mud tank system.
At the suction or mixingtank, fresh additives aremixed into the system, the continuous phase is replenished and mudweight adjusted, preparingthe fluid for its trip backdown the hole.
Shear and temperatureaffect the mud as it
is pumped to the bit athigh velocity and pressure.
Additional shear effectsoccur as the mud passes
through the bit jets andimpacts the formation.
Bell nipple
Kelly
Drill floor
Drillpipe
Annulus
Cementedcasing
Bit
Suctiontank
Shakertank
Mudpump
> Drilling fluid life cycle. Throughout the circulation cycle, the mud is subjected to a number of processes that alter its physical parameters. The drilling fluid treatment plan must evolve to keep pace with these changes.
