bluuebunny/crossref_metadata_2025_split huggingface dataset:
Intelligent-Well Completion in the Troll Field Enables Feed-Through Zonal Isolation
Authors: Carpenter Chris 
Published: February 2015

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 160060, ’First Intelligent-Well Completion in the Troll Field Enables Feed- Through Zonal Isolation: A Case History,’ by Bjorn Olav Dahle, Statoil, and Peter E. Smith, Geir Gjelstad, and Kristian Solhaug, Halliburton, prepared for the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8-10 October. The paper has not been peer reviewed.
Statoil, operating the Troll field in the Norwegian sector of the North Sea, wished to run a deep sidetrack from the main bore in a multilateral well that would exit through the liner in the reservoir. Several zonal-isolation methods had been evaluated, but on the basis of previous experience Statoil decided to use swellable-packer technology. Testing revealed that this type of completion would exceed the necessary requirements. The installation was performed from a semisubmersible rig ahead of plan.
Introduction
The Troll field lies approximately 65 km west of Kollsnes, near Bergen, Norway. Although the field historically has produced large amounts of oil, it is now primarily a gas producer and contains approximately 40% of the total gas reserves on the Norwegian continental shelf. The gas reservoirs, which are 1400 m below sea level, are expected to produce for at least another 70 years.
The massive Troll A platform produces gas, while Troll B, a floating process and accommodation platform with a concrete hull, and Troll C, a floating process and accommodation platform with a steel hull, produce from thin oil-bearing layers in the Troll West reservoir. The thin oil layer is between 22 and 26 m thick in the Troll West oil province and is between 11 and 13 m thick in the Troll West gas province. In order to recover oil from the thin layer, it has been necessary to develop advanced drilling and production technology. All of the more than 110 production wells to be drilled are horizontal wells. This process requires two-phase drilling.
The first phase drills down to the reservoir, 1600 m beneath the sea bottom, and then the second phase drills to 3200 m in a horizontal direction through the reservoir. Twenty-eight of the wells are multilaterals that have two or three horizontal laterals.
The well in question faced several challenges normally not seen in Troll multilateral completions, including standalone-screen completion with zonal isolation, well paths with doglegs and a completion total depth (TD) of more than 6000 m, top completion with zonal isolation and zonal control for four zones, and the need for dual pressure and temperature monitoring for all oil zones.
Technology Focus: Drilling Management and Automation (September 2013)
Authors: Cunha J.C. 
Published: February 2015

Technology Focus
Recently, while preparing to present a seminar on deepwater-well-construction optimization, I tried hard to find a word or a phrase that could be seen as “the secret” for a safe and optimized drilling performance—something very simple that would summarize what must be done to achieve success in an activity that, besides being the most visible face of the oil industry, is also simultaneously the most vulnerable and criticized.
What I was trying to do was encapsulate what is a very complex task, the successful management of drilling operations, in just a few words. This proved to be a futile exercise. After many hours of trying, I ended up not succeeding in obtaining my catch-phrase. On the other hand, that helped me a lot in obtaining the main message for the seminar. There are no quick fixes. The management of a large group of people operating very sophisticated equipment, under restricted conditions, and within a limited space is a mission filled with complexity. But it is our mission, and we should strive not only to succeed but also to improve our performance constantly. As I mentioned in my last article, a flawless operation is a result not only of good management but also of careful planning.
In the seminar, I ended up concentrating on a few points—before, during, and after the operation—that should be viewed as fundamental for the success of the job. In the planning phase, make sure that you are aware of all details involved in the operation and what the risks and possible contingencies are. Then, while executing the operation, be aware of all developments. Use your real-time data as an efficient tool to verify what is going well and what needs to be corrected and to predict what is coming. Finally, after concluding the operation, make sure to capture the lessons learned. This is at least as important as the planning process.
To emphasize the importance of using lessons learned, I would like to conclude with one of my favorite quotes, attributed to Peter Drucker, widely viewed as the inventor of modern management: “A manager is responsible for the application and performance of knowledge.”
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 163302 Intelligent Real-Time Drilling-Operations Classification Using Trend Analysis of Drilling-Rig Sensors by A. Arnaout, TDE Thonhauser Data Engineering, et al.
SPE/IADC 163510 Advanced Dynamic Training Simulator for Drilling and Related Experience From Training of Drilling Teams With Focus on Realistic Downhole Feedback by Sven Inge ødegård, eDrilling Solutions, et al.
SPE 163489 Operational Control and Managing Change: The Integration of Nontechnical Skills With Workplace Procedures by J.L. Thorogood, Drilling Global Consultant LLP, et al.
SPE/IADC 163515 Advances in Real-Time Event Detection While Drilling by R. Wong, Schlumberger, et al.
Q&A with Andy Lane
Authors: Lane Andy , Donnelly John 
Published: February 2015

Andy Lane, SPE, is Halliburton’s Chief Operating Officer, with responsibility for directing the leadership teams at both the Energy Services Group (ESG) and Kellogg Brown & Root (KBR). Previously, Lane was President and Chief Executive Officer of KBR. He also has served in a number of management, director, and vice presidential positions within ESG. In 2003, he was named Vice President of ESG’s regional organization. In 2002, he became President and Chief Executive Officer (CEO) of Landmark Graphics. Before that, he served as Global Vice President for Production Enhancement, ESG’s largest product/service line. Lane started at Halliburton in 1984 as a design engineer, specializing in well-completion products. His career in the oil and gas industry began as a field engineer for Gulf Oil, and he also worked as a production engineer in Gulf Oil’s Pipeline Design and Permits Group. Lane earned a BS degree in mechanical engineering from Southern Methodist U. He is a registered professional mechanical engineer in the state of Texas and is also a member of the Soc. of Exploration Geophysicists. He serves on the executive board of Southern Methodist U.’s School of Engineering.

Halliburton restructured operations last December, ending the practice of having separate business unit CEOs and putting both the ESG and KBR divisions under you. What effect has the restructuring had on the company?
The six divisions (four in Halliburton Energy Services Inc. and two in Kellogg Brown & Root Inc.) that make up Halliburton’s business segments have never been stronger. Halliburton is a dynamic organization, encompassing a world-leading position in the energy services industry as well as superb strength in the energy and chemicals and the government and infrastructure markets. The company continues to meet and exceed customer expectations, excel in challenging markets and opportunities, and deliver outstanding results for our shareholders.

Has there been any change in ESG’s strategy or direction since you began overseeing the group?
ESG delivers products and services through four operating divisions: Fluid Systems, Production Optimization, Drilling and Formation Evaluation, and Halliburton Digital and Consulting Solutions. ESG continues to deliver record quarterly performance in terms of revenue and operating income. We are very focused on delivering financial performance. We attribute this strong performance to our customers’ recognition that Halliburton offers superior-quality services. We also remain committed to having a strong customer focus as well as the team’s commitment to health, safety, and the environment while ensuring each and every job is completed according to our motto, “Done Right.” While ESG comprises distinct divisions, we are one company. Our shareholders invest in the strength of Halliburton, and our customers buy our products and services on the basis of the broad range of superior solutions that we offer. With an added emphasis on this “One Halliburton” initiative, we foster a culture of internal alignment and an overall teamwork approach.
Integrated Project Models To Evaluate Field-Development Options
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93554, "Using Integrated Project Models To Evaluate Field-Development Options," by M.G. Bilderbeck, SPE, and I.V. Beck, SPE, Gaffney, Cline & Assocs., prepared for the 2005 SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March.
A practical and effective development-concept evaluation and screening methodology was developed that recognizes the fundamental relationship between reservoir potential and field-development strategy. The spreadsheet-based project-modeling environment integrates reservoir models and a field-development-planning model. The reservoir models are used to account for uncertainty in reservoir performance. The field-development-planning model handles the scheduling and cost estimation of wells and processing facilities.
Introduction
Decisions to invest in oilfield development are always made under conditions of uncertainty. The future performance of reservoirs is uncertain, as is the economic climate in which investment decisions are made and the resulting projects operated. Technical and commercial analyses used to evaluate the benefits of oilfield developments, and thereby support accompanying investment decision-making processes, must account for these uncertainties.
Many types of uncertainty must be considered. Reservoir performance is affected primarily by the reservoir properties, which can never be defined fully at the point in time at which an investment decision is made. The cost of constructing and operating wells and production facilities also is uncertain, primarily because the design and use of these elements is a direct function of the performance of the reservoir.
While the future performance of an oil field is uncertain, the reactions of managers to its performance are, by definition, deterministic. Managers comprehend the reality of a reservoir as it is revealed through its performance. Therefore, development plans must have sufficient flexibility to enable managers to react to, and accommodate, the performance of a reservoir with time.
Integrated Evaluation Process
The subsurface and surface elements of an oil field are linked and must be recognized and incorporated in any evaluation process used to support investment decisions. This process requires an appropriately staffed evaluation team and use of appropriate evaluation tools.
A team with at least the following three broad technical disciplines should work together to perform an evaluation.
Fracture Characterization and Modeling of a Tight-Carbonate Reservoir
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 93557, "The Fracture Characterization and Fracture Modeling of a Tight-Carbonate Reservoir: the Najmah/Sargelu of West Kuwait," by O. Fonta, Beicip-Franlab; H. Al-Ajmi, N.K. Verma, and S. Matar, Kuwait Oil Co.; V. Divry, Beicip-Franlab; and H. Al-Qallaf, Kuwait Oil Co., prepared for the 2005 SPE Middle East Oil and Gas Show and Conference, Bahrain, 12-15 March.
The Najmah/Sargelu reservoir of west Kuwait is a tight-carbonate oil reservoir in which porosity and permeability result from the fracture network. A multidisciplinary integrated approach combined geology [borehole-imaging (BHI) logs, cores, and wireline logs), geophysics [seismic facies analysis (SFA)], and reservoir-engineering data [production, production-logging-test (PLT), and well-test] to identify the main types of fractures, to predict their occurrence in the reservoir, and to determine the hydraulic properties of the different fracture types.
Introduction
The objective of a detailed geological and hydraulic characterization of the fracture network within the Upper Jurassic Najmah/Sargelu reservoir was to identify the main geological drivers of natural-fracture occurrence, measure fracture hydraulic properties, and, eventually, use discrete fracture modeling to compute the equivalent fracture properties (porosity, permeability, and block sizes) required for reservoir simulation. This objective was achieved through integration of geological, geophysical, petrophysical, and dynamic data by use of workflows and methods implemented in fracture analysis and modeling software. The main tasks during the project were the following.
- Fracture analysis from cores.
- Fracture analysis from BHI logs.
- Integration of the 3D-seismic data set.
- 3D fracture modeling.
- Hydraulic characterization of the fracture network.
- Computation of the fracture properties in the reservoir grids.
Background
The study area was approximately 2000 km2 and covered four fields. The reservoir structures are gentle, elongated anticlines. The top-of-reservoir depth ranges from 3350 to 3650 m. The Najmah/Sargelu reservoir has a generally high degree of lateral continuity and gradual thickness changes. The formation has alternating layers defined by volume of shale, Vsh, from well logs of clean limestone (Vsh &lt;30%), shaly limestone (30%&lt; Vsh &lt;60%), and calcareous shale (Vsh &gt;60%).
Fifty wells were logged in the reservoir. Cores were available from 21 vertical wells, and BHI acoustic images were available on 18 wells; 10 wells had both cores and BHI logs available for the study. Matrix quality is generally very poor, dominated by micro-porosity (&lt;8%) with low permeabilities (&lt;0.01 md). Locally, higher matrix porosities and permeabilities may be found in Units 5 and 6 of the Sargelu limestones. Production is mostly from the fracture net-work in reservoir Units 2, 3B, 5, and 6.
Unlocking Innovation in the Upstream
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 17729, "The Key to Unlocking Innovation in the Upstream? Data Standards," by S.C. Comstock, ExxonMobil, prepared for the 2005 Offshore Technology Conference, Houston, 2-5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission.
The key to unlocking innovation in the upstream is standards. What? Does this sound backward and nonintuitive? Usually, do we not associate innovation with freewheeling, no-boundaries kinds of approaches? How can people feel free to innovate if you tell them to “do it this way?” It all depends on where you think the value comes from.
Background
Technical computing in the upstream oil and gas industry has evolved into extremely powerful, yet extremely complex, systems. Varied and coagulated connectivity networks underlie a myriad of platforms, from Unix to PC to mainframes to supercomputers…to server farms, to thin clients and Blackberries, and the list goes on. At the other end of these systems, a multitude of user interfaces becomes the most visible aspect of these complexities to the user community. At the center of such complex technical computing systems is a variety of software applications including geoscience, engineering, operations, business, personal productivity, and information technology (IT), usually supplemented out of necessity by a veritable foundry of line-coded tools, agents, or macros. These line codes are written by one, or all, of several million developers, and sometimes even by end users themselves, and in many different languages. The fuel and lifeblood for this technical computing system are data. These data come in many formats, sizes, and shapes. They come in logarithmically increasing volumes—in numbers making “a million” seem like a quaint and archaic term.
Overload
With the complications of these various elements and their interrelationships in the systems, complexity has become the enemy of innovation. Too many engineers, geoscientists, field operators, accountants, and managers (not to mention IT specialists) spend too much time dealing with the complexity and moving parts of the system, and, so far, too little time evaluating, analyzing, solving, and innovating in the environment.
While there are many targets for simplification in these technical computing systems, data are the most critical element. In the upstream environment, data are at the core of the systems—resting on the networked infrastructure and feeding the applications and user interfaces. Data are what the systems were built for and around. After all, scientific software applications without data are, in essence, just theory. And, computer infrastructure is not needed if data, or even software without data, do not exist. Data are probably in the worst shape of all the elements of the system in terms of its wild and complex nature.
Petroleum Industry 2020: People First
Authors: Al-Khalifa Abdul-Jaleel 
Published: February 2015

There is a mounting global perception that the petroleum industry is nearing a peak and that its sunset is inevitable within the foreseeable future. New discoveries fell short of total global production in the past two decades, while demand continues to climb. The lack of full transparency in reporting reserves and field-by-field performance has added to the perception of our industry's decline. Anti-industry sentiments have recently proliferated in the media and political arenas, further impairing the industry's image and leading to a new round of restrictive legislations. Policy makers seriously debate the sustainability of petroleum resources and the urgent need for alternative energy sources. This situation calls for immediate action at both the personal and corporate levels. A collaborative industry-wide effort is urgently needed to develop a Year 2020 vision that truly reflects the growth, reliability, and sustainability of the petroleum industry. SPE plans to facilitate a workshop in early 2007 for senior industry leaders to articulate this vision, with strong emphasis on people and technology. The SPE Board has recently approved a new magazine, titled Talent & Technology, to be published quarterly commencing March 2007. All SPE members will receive this publication with their JPT.
Clearly, the challenge is to extend the life of the industry through improving the success of finding new discoveries in frontier and remote basins as well as increasing the ultimate recovery from existing fields. However, this is only the tip of the iceberg. This tip is underlain by the unseen parts—technology in the middle and people as the foundation. People strive hard to fire innovation and develop new technologies, which in turn help to discover new reserves and improve ultimate recoveries. Therefore, people are the first and the most important element of the Petroleum Industry 2020 vision, where 10- to 15-year staffing plans have to be considered. Short-term human-resources plans that span 1 to 2 years can be very detrimental to the long-term objectives of the petroleum industry. Long-term plans would ensure that the industry retains a critical mass of talent, irrespective of cyclic market conditions. This will maintain expertise, reaffirm the positive image of the industry, and honor the loyalty of the people. This will also ensure a balance between the short-term financial and operational pressures and the long-term strategic objective of extending the life of the industry.
Overview: Tight Reservoirs (October 2006)
Authors: Mayerhofer Michael J. 
Published: February 2015

High oil and gas prices provide a major boost to the development of tight and unconventional reservoirs. While most of this activity is in North America, tight and unconventional reservoirs are becoming more popular throughout the world. During the last year, I probably have seen more than a dozen conferences in North America on shale plays and unconventional reservoirs with increasing interest and participation from major operators. Success in unconventional reservoirs sometimes can be achieved only with "unconventional" thinking and approaches. The mix of "empirical" and "high-tech" engineering continues to provide an interesting and challenging work environment for engineers.
A significant challenge in tight reservoirs is the proper completion of layered reservoirs. In some areas, operators are completing very thick, highly layered formations. The challenges begin with formation evaluation—What is actual pay? How do we optimize hydraulic-fracture staging and completion strategies to ensure coverage of all pay zones while minimizing cost? How do we evaluate which zones are contributing to production, and are we recovering all the reserves efficiently? In some areas, water-producing formations are interspersed with pay zones. How can these formations be avoided without sacrificing hydrocarbon production?
There is one persistent question in tight reservoirs that continues to haunt engineers. How do we distinguish between completion effectiveness and reservoir performance? If a well underperforms, is it the result of a poorly performing hydraulic fracture, or is it just poorer-than-anticipated reservoir quality? This question is of high importance because it has major implications for well-completion optimization and infill-drilling strategies. More focus on the importance of gathering appropriate rock, reservoir, and hydraulic-fracturing data and application of advanced technologies hopefully will give us better answers to those questions.
Tight Reservoirs additional reading available at the SPE eLibrary: www.spe.org
SPE 100572 "A Study of Fracture-Initiation Pressures in Cemented Cased-Hole Wells Without Perforations" by G. Rytlewski, Schlumberger, et al.
SPE 96104 "Optimal Stimulation Treatments in Tight Gas Sands" by S.A. Holditch, Texas A&M U., et al.
SPE 100434 "Field Study of Completion Fluids To Enhance Gas Production in the Barnett Shale" by G.S. Penny, CESI Chemical, et al.