bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Multilateral/Extended Reach (May 2008)
Authors: Mason Colin 
Published: February 2015

Technology Focus
The quest to secure future reserves drives demand for increasingly complex casing and well designs. Not only is there a desire to drill longer-step-out wells, but also to drill to deeper horizons in harsh environments. This increasing trend naturally presents intense technical challenges to drilling, completion, and subsurface specialists. To help describe this growing and diverse array of well designs in a coherent and concise manner, there is a clear need for a robust classification system. This nontrivial task will help identify common requirements for new technology and improve communication and understanding across the industry.
Consider, for example, the definition of an extended-reach-drilled (ERD) well. Most readers will know that ERD wells are associated with accessing reserves at locations remote from a drillsite. Early ERD-well definitions related wells to those that exceeded some step-out/vertical-depth ratio (often 2:1). However, for most highly deviated wells in deepwater environments, this definition clearly does not fit. Some methods have evolved to categorize wells according to their stepout within different vertical-depth ranges. ERD wells then can be described conveniently as shallow, intermediate, deep, and ultradeep. Other variants are associated with operating in deep water and high-pressure/high-temperature environments. Currently, there is no generally accepted ERD-well definition.
No matter what well-design definitions prevail, it is vitally important how they are communicated, not only across the industry but especially within each organization. Experience has shown that the ERD acronym has a high profile, but its lack of definition regularly results in oversimplification and misrepresentation. The industry must address this deficiency and construct a method for characterizing all well designs that will stand the test of time.
Multilateral/Extended Reach additional reading available at the SPE eLibrary: www.spe.org
SPE 107603 • "The Use of Multilateral Technology in an Environmentally Sensitive Area: the Val d'Agri Field, Italy" by Cristiano Caproni, SPE, Halliburton, et al.
SPE 110584 • "Unique Micronized Weight Material Delivers Ultrathin NAF To Optimize ERD" by Wayne Matlock, M-I Swaco, et al.
SPE 114117 • "Modeling of the Stability of Multibranch Horizontal Open Holes" by Alberto Lopez Manriquez, University of Texas at Austin, et al.
Ormen Lange Langeled Development
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18961, "The Ormen Lange Langeled Development," by Tom Rotjer, Hydro, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
The full-length paper provides a summary of the challenges of executing the Ormen Lange Langeled project. The three main features of the project-execution phase are the Ormen Lange offshore development, the Ormen Lange onshore development, and the Langeled gas-export system including the gas-receiving facility in the UK.

Introduction
The Ormen Lange gas field was discovered by Hydro in 1997. The development of the field, 120 km off the midwest coast of Norway, is the largest industrial project in Norway. As of January 2007, the Ormen Lange Langeled project is more than 90% complete, within budget, and on schedule for gas export by October 2007. When Ormen Lange comes on stream in October 2007, the project will contribute to the increase of Norwegian gas export by 25%. The peak annual gas production from the field of 22×109 std m3 is equivalent to the total annual energy consumption in Norway. Gas from Ormen Lange will be able to meet as much as 20% of the UK gas demand. Production life is estimated to be 30 to 40 years. Ormen Lange's gas-export pipeline, Langeled, from Nyhamna in Norway to Easington on the east coast of England, is the world's longest subsea pipeline, with 42- and 44-in.-diameter pipes and a total length of 1200 km. The Ormen Lange field will contribute significantly to Norway becoming the second largest exporter of natural gas in the world.

Project Management
The Ormen Lange Langeled field-development project is organized with a multicompany integrated project team headed by Hydro. Shell is responsible for subsurface and drilling of production wells and for preparing for operations. Statoil is responsible for the execution of the Langeled project. Because of the shear size and complexity of the project, it was organized into the following three major subprojects with different focuses and challenges.The Ormen Lange offshore project consists of subsea installations approximately 120 km offshore, with templates, manifolds, and pipelines.The Ormen Lange onshore project consists of the gas-processing facilities at Nyhamna.The Langeled project consists of the 1200-km gas-export transportation system, the tie-in to the Sleipner field, and the Easington gas-reception terminal in the UK.
Hydro organized a common project for the execution of the field development and the transportation system to secure the integrity of the Ormen Lange Langeled project from reservoir to market. The Langeled-project organization has been staffed with personnel from both Statoil and Hydro.
Challenges of Waterflooding in a Deepwater Environment
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18523, "Challenges for Waterflooding in a Deepwater Environment," by Azhar Alkindi, SPE, Shell; Robert Prince- Wright, Riskbytes; and Wesley Moore, SPE, John Walsh, Lee Morgenthaler, and Cor Kuijvenhoven, SPE, Shell, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
The waterflood study team for the deepwater Ursa/Princess field evaluated various challenges affecting the surface and subsurface aspects of the development plan. The design for an optimum injection rate was a bottom-up process from the reservoir to the topside injection facilities. Reservoir-sweep efficiency and reservoir-pressure distribution dictated injection-well designs and injection-pump sizing. Subsurface risks, such as reservoir souring and hydrate formation, dictated material selection and completion design.

Introduction
Ursa and Princess fields are 100 miles south-southeast of the Mississippi River mouth in the Gulf of Mexico (GOM) Mars basin. The Ursa field was discovered in 1990 and has been producing since 1999. The Princess field was discovered in 2000 and has been producing since December 2003 through a subsea tieback to Ursa. The fields have common main reservoirs (the Yellow) and are in pressure communication.
Because of limited tension-leg-platform (TLP) well availability, high cost of subsea wells, and the limitations of the subsea system to handle large water cuts, the waterflood will use relatively few injectors. The proposed base plan has four water injectors: two into Princess and two into Ursa. Producing wells will include three Princess subsea wells and four Ursa TLP wells.
High injection rates are required to replace voidage and maintain reservoir pressure above bubblepoint. Initial injection rates per well (annual average) of 30,000 to 40,000 BWPD are required.
Because the original operating health, safety, and environmental (HSE) case for the asset did not include the potential threat of reservoir souring after seawater injection, well-casing and -tubular materials have limited resistance to sulfide stress corrosion cracking (SSCC). This resulted in the need to recomplete the Ursa TLP direct-vertical-access (DVA) wells with qualified tubing. Princess producers already have C100 sour-resistant casing and will not require tubing change out.

Injection Wells
The number of wells was optimized during a number of vital reviews. Sweep efficiency and return on investment were the main optimization criteria for the required total water-injection rate per day. Approximately 50% of the total project capital expenditure is related to drilling and well completion. Because economics is the dominating decision criterion for injector number, optimizing the fine details of the well bottomhole locations, well geometry, and well-completion designs retains prime importance.
Pull Your BOP Stack - Or Not? Systematic Method to Making This Multimillion Dollar Decision
Authors: Denney Dennis 
Published: February 2015

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 119762, "Pull Your BOP Stack - Or Not? A Systematic Method to Making This Multimillion- Dollar Decision," by Jeff Sattler, SPE, WEST Engineering Services, prepared for the 2009 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 17-19 March. The paper has not been peer reviewed.
Pulling the blowout-preventer (BOP) stack, particularly in deep water, is costly. While in most cases this action is proper, circumstances arise when the stack pull could be avoided. Case studies are presented in which planned stack pulls were circumvented or could have been. A systematic protocol can be developed before starting a well to define the decision-making process for stack pulls.

Introduction
Current deepwater-rig downtime costs approach USD 1,000,000/D. Pulling a BOP stack, particularly in deep water, is financially significant. This action is necessary most of the time. However, on occasions when the stack pull could be avoided, all parties to this action rightfully question how to take advantage of the unfortunate learning situation. Avoidable stack pulls occur for a variety of reasons, including:
Inadequate information about the situation or equipment
Inadequate staff training
Unclear understanding of regulatory requirements
Unclear understanding of company requirements
Lack of access to experts who could assist in the decision
The full-length paper details a systematic protocol to use before starting a well or during the drilling, if necessary, to help define the decision-making process for stack pulls for a specific program. Once a problem develops, the root cause should be identified, if possible, and necessary steps taken to analyze the situation and decide if drilling can continue safely. Often, this part of the process requires the advice and experience of one or more experienced drilling experts from within or outside the parties directly involved in the drilling operation.

Predrilling Planning
To help ensure a good decision when an abnormal BOP event occurs, preparations should be made before drilling starts. While several items presented here require time to investigate or review, often this process is not engaged because much of the information is considered to be intuitive. However, after drilling begins and because time is expensive (up to USD 700/min or more), the time required to analyze a situation fully is sometimes not allocated. Predrilling planning, as shown in Fig. 1 of the full-length paper, should include the following items.

Assess Staff Training.
Review staff experience and training to determine if additional training before drilling could reduce the risk of downtime. For example, does the subsea engineer need to be educated on the functionality of a revised circuit or control component? Would the subsea engineer benefit from a refresher on the latest variable-bore-ram capabilities and limitations?
Technology Focus: Well Stimulation (June 2009)
Authors: Hager Charles 
Published: February 2015

Technology Focus
It is important to put the role of well stimulation into perspective as key to driv-ing production and competing in the world's energy market.
Interesting information can be found in the US DOE Energy Information Agency's report Table 11.1 World Primary Energy Production by Source, 1970–2005, which is available at http://www.eia.doe.gov/aer/txt/ptb1101.html (accessed 7 April 2009). Oil last peaked as the world's primary energy source in 1973 at just more than 47% of all sources. By 2005, this number had dropped to approximately 34%, although the world's total energy production had nearly doubled over these 32 years. While coal remained fairly steady at 25 to 27% of the world's market share, natural-gas and natural-gas-liquid (NGL) usage increased from 20 to 25%. This suggests that natural gas could surpass oil and coal as the world's primary energy source within the next decade or so, unless low natural-gas prices continue. Renewable-energy sources (e.g., nuclear, hydroelectric, and geothermal) gained an increase in total market share from 7 to nearly 14%, with these sources supplying more than 63 quadrillion Btu to the world in 2005 alone. Natural gas and NGLs had not surpassed this level until 1984, just 21 years earlier. Renewable energy has doubled its market share during a doubling of the market size.
To improve recovery, well-stimulation tests, data, and interpreters need to become valuable commodities on par with the other well costs. Data and analysis provide a basis for improvement. Whether success may come from higher retained conductivity, comparing pre- vs. post-treatment buildup tests, or acquiring bottomhole treating pressures to unmask friction effects, many avenues are available to enable us to compete at the next level. We need to embrace our best practices, strive for new developments, and analyze much more data to perform at the next level.
Without measuring results, we cannot prove the improvements. Although oil may be nearing its end as the world's primary energy source, it is doing great as a source of products. To transition to natural gas as the new energy leader, well stimulations will be a key to keeping the petroleum industry as the world's best provider of clean and cost-effective energy.
Please enjoy reading the following selections representing the future of well stimulations and interesting examples of how we can compete.
Well Stimulation additional reading available at the SPE eLibrary: www.spe.org
SPE 119623 • "Acid Fracturing: The Effect of Formation Strength on Fracture Conductivity" by A.M. Gomaa, SPE, Texas A&M University, et al.
SPE 121483 • "First North Sea Application of Pinpoint-Stimulation Technology To Perform a Rig-Based Acid-Fracture Treatment Through CT" by David Barclay, SPE, Halliburton, et al.
SPE 116775 • "An Innovative Acid-Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabia—A Holistic Approach" by Surajit Haldar, SPE, Saudi Aramco, et al.
Shared Vision (July 2005)
Authors: Paccaloni Giovanni 
Published: February 2015

Attendance is up at SPE-sponsored meetings.
One obvious reason for the higher attendance is the health of our industry resulting from strong oil prices. Professionals in our industry recognize that meetings are a very efficient way to find technology solutions to meet the increasing global demand for energy and to network with E&P leaders. But there is a proliferation of E&P-related meetings to choose from, so the smart energy professional is selective about which to attend.
SPE sponsors a wide range of conferences, workshops and Forums that must compete with commercially organized meetings. We have to prove that there is a real return on the time you invest in our meetings. Here are a number of reasons I believe that SPE meetings offer the best value for you.
- SPE's member-driven planning process ensures that our meetings present focused and relevant topics. We have an incredible advantage because the industry trusts SPE to sponsor well-organized, content-rich events. Our members take pride in putting together timely, interactive programs that other members will want to attend. They find hot topics, review and select technical papers, recruit panelists and speakers, and facilitate sessions. Volunteers make our meetings happen for the good of the industry. Our Forum Series is a good example of how we develop the best possible programs. We have three committee processes ongoing simultaneously for the Forums: a committee is performing a review of the last series, while steering committees are running the Forums for this year and other committees are planning topics for the upcoming year. Our approach is quite different from commercial meetings, which tend to feature well-known speakers but lack the depth of preparation that our volunteers ensure.
- The wealth of peer-selected technical papers presented at SPE conferences contributes to the long-term health of the industry. Although other meeting organizers may permit PowerPoint presentations or abstracts, we continue to require technical papers at our meetings because they have a life well beyond the number who actually attend the conference. It is this commitment to technical excellence that has given us the SPE eLibrary. With more than 40,000 papers, the eLibrary is the only comprehensive repository of the best technology available in the E&P environment. About 1,700 technical papers are added to SPE’s eLibrary each year, and become valuable resources that can be accessed for years to come by anyone, from anywhere in the world. We are highly selective in our program-selection process—for our upcoming annual meeting, for example, we selected about 400 papers from over 1,200 submissions. I tell students and young professionals that the best thing they can do to become an expert in their field is to study a paper each day from our eLibrary.
Hibernia Extended-Reach-Drilling and -Completion Record
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 92347, "Hibernia Record Well Breaks Extended-Reach-Drilling and -Completion Envelope," by Carsten C. Elsborg, SPE, Esso Norway, and Adrian K. Power and Paul C. Schuberth, SPE, ExxonMobil Canada, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February.
In 2002, development began on the northernmost compartment of the Hibernia development project (Block A). To access these reserves, drilling and completing a 31,000-ft measured depth (MD) oil producer was proposed, with a horizontal departure and vertical depth that exceeded the industry extended-reach-drilling (ERD) limits. Successfully drilling this well required the application and extension of available technology. The project required a large monobore completion system. The trajectory required management of weak and unstable intervals across an extended 17,000-ft-MD intermediate section. To meet these challenges, existing local experiences were leveraged, and recognized international expertise was used to supplement existing practices.

Introduction
The Hibernia development project is in 265 ft of water, 200 miles offshore Newfoundland and Labrador, Canada’s easternmost province, in the Grand Banks region of the Atlantic Ocean. Reservoir access is provided by use of an iceberg-resistant gravity-based-structure (GBS) platform (Fig. 1) with 64 well slots. Two fully equipped and independent drilling rigs service the wells. Drilling was initiated from the structure in 1997. From the beginning, the project was envisioned as an ERD development that would extend the technology and experience limits as the platform matured.
The reservoir is a series of thick-layered sandstones separated by intermediate shales. It is subdivided into large compartments or blocks by a series of faults that run bidirectionally across the reservoir (Fig. 2). These faults are highly sealing in nature and, hence, form the independent subreservoirs or fault blocks that make up the larger reserves. In 2002, the operator began accessing Block A, the largest undeveloped reserves block in the project. The block also was the farthest from the platform (approximately 4.5 miles). At the time, several extended-reach wellbores had been drilled to more than 20,000 ft MD.
Careful evaluation was made of drilling a subsea-satellite well vs. use of ERD technologies and knowledge gained on similar Hibernia wellbores. The team recommended the ERD option to drill what would become Hibernia B-16 36 (OPA1), the longest well in the world at this true vertical depth (TVD). The reward for success would be significant from a cost-savings perspective if the incremental risks from a drilling and completion standpoint could be mitigated.
Strategic Direction for Reducing Fatal Oil and Gas Industry Incidents
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 94416, "Upstream Onshore Oil and Gas Fatalities: A Review of OSHA's Database and Strategic Direction for Reducing Fatal Incidents," by C.K. Curlee, SPE, Marathon Oil Co.; S.J. Broulliard, ConocoPhillips; M.L. Marshall, U.S. Dept. of Labor - Occupational Safety and Health Admin.; T.L. Knode, SPE, Halliburton; and S.L. Smith, Chevron Corp., prepared for the 2005 SPE/EPA/DOE Exploration and Production Environmental Conference, Galveston, Texas, 7-9 March.
According to the U.S. Dept. of Labor—Occupational Safety and Health Admin.(OSHA) database for the period 1997 through 2003, one fatality occurred every 10 days in the U.S. upstream oil and gas industry. These data were studied to determine trends and provide insights into the safety failures and to study potential interventions to eliminate the high frequency of fatal incidents. This review provides oil and gas industry operating managers, safety professionals, trade associations, and others a way to improve programs and set priorities for reducing onshore oilfield-related fatalities.

Introduction
Each year, the U.S. Bureau of Labor Statistics (BLS) releases a Census of Fatal Occupational Injuries (CFOI) report. These reports indicate that the mining sector, which includes the oil and gas extraction subsector (i.e., all upstream E&P activities), typically experiences one of the highest fatality rates of all major industries. In the BLS report of 2003 data, 34.5 fatalities occurred for every 100,000 workers in the oil and gas extraction subsector, or one fatality every 4.3 days. This fatality rate is more than 8.5 times the average for all U.S. industries.
An industry-review team (IRT) was formed, consisting of professionals representing operating companies, drilling and well-servicing companies, and industry trade associations, as well as OSHA. The IRT examined the OSHA fatality information, with emphasis on validating the OSHA database. Once the database information was understood, the IRT determined trends to provide insights into the safety failures associated with E&P-industry fatal incidents.