bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dalia Subsea Production System
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 18541, "Dalia Subsea Production System, Presentation and Challenges," by J.L. Lafitte, M. Perrot, J. Lesgent, J. Bouville, and S. Le Pennec, Total E&P Angola; P. Dahl, Hydro; and S. Lindseth, AKS, prepared for the 2007 Offshore Technology Conference, Houston, 30 April-3 May.
In 2002, the Dalia subsea production system was the largest subsea order placed with a single contractor in off-shore history. The production system had 71 wells, 71 drill-through horizontal trees, nine six-slot production manifolds, two workover systems, flowline-connection systems, and a complex control and chemical-injection system. Heat conservation and hydrate prevention were paramount concerns during the subsea-production-system detailed-design and construction phases.

Subsea Production System
Fig. 1 shows the general field layout with the 71 subsea wells and nine production manifolds and the flowlines, risers, and control umbilicals that cover a subsea footprint of approximately 100 km2.
Production-Well-Cluster Layout. Various layouts were examined during detailed design to find the optimum solution. A typical production-well cluster comprises the manifold with three wells on one side and three wells on the other, all connected by rigid jumpers between the Christmas tree and the manifold. When the manifold is in the center of a flow loop, rigid spools connect production flowlines at both ends of the manifold. If the manifold is at the end of a flow loop, a pigging loop is mounted on the open side of the manifold, permitting roundtrip pigging. The control umbilical essentially is daisy chained from one manifold to the next. The rigid jumpers are not in contact with the seabed but float approximately 2.5 m above it because of attached buoyancy aids.
Advances in directional horizontal drilling and the use of simplified completions have enabled the wells to be grouped in six-well clusters, which not only facilitates batch drilling, where necessary, but also reduces the number of subsea flowline and umbilical connections.
Water and Gas Injection. Similar to Girassol, the same single-line header design is used to bring water and gas to the relevant wells. Control umbilicals are laid adjacent to the flowlines with subsea distribution units (SDUs) connecting the trees by electrical and hydraulic flying leads deployed by a remotely operated vehicle (ROV).
Wellhead, Christmas Tree, and Tubing Hanger. Horizontal-Christmas-tree technology has been selected that is compatible with a 7-in. full-bore completion and permits an efficient sequence of operations, giving the possibility of batch drilling with a minimum number of rig moves. Additionally, the trees have the drill-through capability that for a light-architecture-type well, lets the tree be run before the blowout preventer (BOP). With the tree and BOP in place, the well then can to be drilled, cased, and completed.
Building Bridges: Reflections
Authors: Cobb Bill 
Published: February 2015

President's column
My term as president ends at the SPE Annual Technical Conference and Exhibition next month. I am amazed at how quickly the time has passed. This will be my last column, and so I think it is a good time for a bit of reflection on the organizational and personal goals with which I began my term:
Promote new Petroleum Resources Management System (PRMS)—In a previous column, I talked about the development of the PRMS. An important update is that the PRMS served as a major basis for recommendations made in late June to the US Securities and Exchange Commission for rule changes to modernize their reporting requirements for oil and gas companies. Our Oil and Gas Reserves Committee is preparing comments to the Commission on their proposals that relate to PRMS. I presented a briefing about the PRMS at a roundtable session on reserves at the World Petroleum Congress in Madrid in early July.
Develop leadership in carbon capture and sequestration (CCS)—I appointed an expert committee to guide SPE in this important area and to promote technical information exchange on best practices and lessons learned relating to CCS. The committee provided an update to the Board in June on upcoming SPE events with sessions on CCS topics, as well as efforts to coordinate our activities with other engineering societies.
Support young professionals programs—Our young professionals have great momentum in organizing workshops and programs around the world. I spoke to young professionals, as well as students, in almost every country I went to. I am confident that our industry will be in good hands. I also spoke at the World Petroleum Congress on the importance of industry collaboration to ensure that we attract new talent to the industry.
Promote energy education outreach programs to pre-college students—SPE's new Oil and Natural Gas book represents a tremendous opportunity to educate teachers, parents, and students about our industry. I've given copies to company and government leaders, as well as section leaders, throughout my travels this year. We also continue our efforts to collaborate with other professional societies on career outreach, and hope to expand www.energy4me.org to offer geoscience career information as well.
Build bridges to universities to help alleviate faculty shortage—High industry demand for petroleum professionals is causing both an inflow of students and an increase in faculty vacancies in the US and elsewhere. To help address the faculty shortage, SPE has created an Adjunct Faculty Clearinghouse on www.spe.org to help academic departments publicize their faculty needs to industry. SPE also recently established 15 new fellowships for graduate students, who may choose a career in teaching.
Techbits: Marginal Fields Focus of Malaysian Workshop
Authors: JPT staff _ 
Published: February 2015

Techbits
The Malaysian island of Langkawi was the setting for an SPE Applied Technology Workshop (ATW) titled "Development of Marginal Offshore Fields" held 21–24 April. Fifty-six participants representing 36 organizations and 11 countries discussed the challenges in developing marginal fields and the current industry trends and technology employed to deal with complex geologies, challenging drilling environments, and infrastructure constraints.
Interest in this workshop was great, as increasing energy demand continues to push oil and gas prices to new highs, forcing producers to examine fields that might have been considered economically unfavorable just a few years ago. High energy prices have brought a series of new challenges that developers of marginal fields have been forced to consider, including higher development costs due to rising commodity prices; increased environmental concerns pushing higher standards; and resource constraints in the form of a limited number of engineers, fabrication yards, drilling rigs, and construction barges. The workshop's program committee, cochaired by Azmi Mohd. Noor of Shell Global Solutions Sdn. Bhd. and Rakesh Kumar Vij of Oil & Natural Gas Corp. (ONGC), framed the content with these issues in mind.
Three keynote addresses were given, the first by Chen Kah Seong, General Manager of Project Development for Petronas Carigali Sdn. Bhd. Chen's address titled "Challenges of Developing Marginal Fields" set the stage for the workshop, and was followed by the speech "Trends in Marginal Fields" by Rajendra Marathe, General Manager and Head of the Institute of Reservoir Studies, ONGC. Garth Taylor from the Australian Trade Commission gave the final keynote, titled "Regulatory Body Influence in Marginal Fields Development."

Development Uncertainties Discussed
A series of nine technical sessions followed, with Sessions 2 and 3 discussing how to effectively manage subsurface uncertainties, including uncertainties in quantifying hydrocarbons in place, and anticipating the range of reserves recovery and production profiles. Other topics in these sessions addressed the value of information management for reducing subsurface uncertainties, how to maximize value by employing optimum reservoir recovery processes, and the appropriate evaluation and planning methods for a particular marginal development. Various methods for modeling uncertainty were also presented, followed by portfolio ranking at both the field and basin level, with examples of how risk management methods were successfully applied in various fields around the world.
Facilitating Collaboration in a High-Tech, High-Risk Environment
Authors: Benwell Tom 
Published: February 2015

Management
When most people imagine a high-tech business, they picture San Jose or Seattle, not Tulsa or Lafayette or Houston. Those who walk the hallways of the energy business know better. Oil and gas exploration and development has become a world of high technology. While drill bits, pipe, and supplies for the toolpushers are still at the core of the oil and gas business, executives increasingly must manage complex networks of new-technology providers, and of traditional oilfield services that have leapt into a new technological age.
Onshore exploration and development continues to push deeper, applying new science every step of the way. Offshore, rigs push from deep water into ultradeep prospects, demanding technological innovation. As the energy-finding climate changes and risks grow, the most successful operators and suppliers develop collaborative relationships to deploy new technologies, maintain supply chains, and gain access to technical resources. The pressure to maximize efficiency and get results is intense, even with prices at historic levels. Operators and suppliers are stretching their technical resources, forcing companies to selectively allocate their hardware, software, and personnel. When a supplier bundles services and equipment for a competitor's key project, it may contractually commit specific technical talent, making them unavailable to others for some period of time.
Resources continue to be consolidated into larger, more complex organizations through mergers and acquisitions. New corporate combinations often lose focus on the customer, becoming internally focused for a while after the consolidation. Operators are reducing the number of suppliers they do business with to reduce the expense of managing so many relationships. Some companies have adopted a policy to deal with no more than three vendors in each procurement category. Smaller suppliers and service companies weeded out in that process find it necessary to work as a subcontractor to a larger supplier in order to maintain their access to the business.
Even in its most traditional moments, the energy sector has understood the need for joint ventures and strategic partnerships, as well as the value of collaborative relationships. But as the industry evolves, so must its approach to collaboration. In a time of rapid change, companies cannot afford to have technology acquisition and application struggle through traditional internal layers of approvers, such as conventionally structured procurement groups and established operations leadership. It has never been more important for operators and sup-pliers to understand each others business, needs, processes, and potential, and find the most productive common ground. There are good reasons to begin facilitated discussions about new ways of working together.
Developing Subsea Facilities for the Roncador Field
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19274, "Development of Subsea Facilities in the Roncador Field (P-52)," by Jose Mauricio T.G. Lima, Mariele Lima Kuppens, Paulo Ferreira da Silveira, and Pedro Felipe K. Stock, Petrobras, prepared for the 2008 Offshore Technology Conference, Houston, 5-8 May. The paper has not been peer reviewed.
The second phase, Module 1A, of the Roncador field, offshore Brazil, was developed with a large semisubmersible floating production unit (FPU). This paper explains the strategies adopted by Petrobras to overcome the challenge of starting oil and gas production at a water depth of 1800 m in a short period of time, which required starting the platform construction early, almost simultaneously with the design of the riser system.

Introduction
Campos basin is offshore Rio de Janeiro State, southeastern Brazil. It covers approximately 100 km2 ranging from 20 to 3400 m water depth (WD). Roncador field lies in 1500 to 1900 m of water in the basin and was discovered in 1996. Development of Roncador field was planned with four production modules. Module 1A comprises two phases of exploitation: Phase 1 began production in 2002 with floating-production-storage-and-offloading (FPSO) vessel Brasil moored in approximately 1300 m WD, to operate some of the wells temporarily. By the end of 2007, the second phase of Module 1A (Phase 2) started to produce to the FPU P-52, which has a total displacement 80,000 t, moored stage of development and knowledge, operational issues, and available resources (e.g., installation vessels). The semisubmersible platform was selected to mitigate the risks of riser development. However, the desire to start Phase-2 production 4 years later required designing and contracting platform construction before the riser system was defined.
Problems faced during qualification testing of flexible-pipe flowlines and risers for Phase 1 raised concerns about the capability of this traditional riser solution for applications in ultradeep water. Therefore, other riser concepts were assessed. The steel catenary riser (SCR) was determined as appropriate technology for the design WD. An in-house technical feasibility study confirmed the SCR as the primary gathering system, while the flexible riser remained an alternative requiring approval in a prequalification program.
The SCR system and flexible risers, after prequalification of the latter with full-scale offshore tests, were both included in the subsea bid for the construction phase. Even though some changes were necessary in the FPU to allow the use of flexible risers, all the provisions for SCRs were kept operational for contingency purposes in the future.
REACH and the HSE Case for Formate Brines
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper IPTC 11222, "REACH and the HSE case for Formate Brines," by Ylva Gilbert, SPE, Gaia Consulting; Adrian Nordone, Cabot Corporation; John Downs, Cabot Speciality Fluids; and Anu Vaahtera, Piia Pessala, and Tuomas Raivio, Gaia Consulting, originally prepared for the 2007 International Petroleum Technology Conference, Dubai, UAE, 4-6 December. The paper has not been peer reviewed.
Europe's largest single piece of legislation, Registration, Evaluation, and Authorization of Chemicals (REACH), went into effect on 1 June 2007. REACH requires manufacturers, importers, and users of chemicals to demonstrate that their products are safe to use for humans and the environment. There will be increasing pressure to substitute less-hazardous materials for chemicals perceived as potentially harmful. The legislation is expected to have a significant effect on the management and application of chemicals used by the oil industry in Europe.

Introduction
The new European chemical legislation, REACH, represents a major revision of European chemicals management, replacing some 40 existing European Union (EU) Directives and Regulations. An objective of REACH is to place the responsibility of demonstrating the safety of chemicals on the manufacturers, importers, and users of the chemical. At the same time, the aim is to minimize the use of animal testing and encourage the substitution principle. The legislation encompasses all chemicals or chemical substances, including oilfield chemicals such as drilling and completion fluids. The full-length paper details the effect that REACH will have on management decisions and compliance procedures related to ensuring safe use of chemicals.

Methodology
The work presented in the full-length paper is based on a review of the literature and legislation as it applies to oilfield well-construction operations using formate brines as example chemicals throughout the discussion. Where comparisons with traditional brines are made, the data mainly have been sourced from open literature, and there are many gaps. For the formates, the authors also have had access to previously unpublished test results from the manufacturers. The findings from the literature have been complemented with information on the practical challenges of meeting REACH requirements, gleaned from discussions with four major operators.
To set the scene, the following section introduces the case-study chemicals. This is followed by a brief overview of two means of ranking chemicals on the basis of regulatory data. REACH and its processes as well as the time frame of implementation are then presented, followed by an overview of data requirements to support REACH. The findings then are discussed from a management point of view, as illustrated with formate brines.
Reservoir Fluid Properties Measured Downhole
Authors: O'Keefe Michael 
Published: February 2015

Technology Update
Over the years, oil companies have started recognizing that a disturbing number of reservoir- and production-management problems could be traced back to a single root cause—inadequate understanding of reservoir fluid properties. After performing detailed analyses and calculations, scientists and engineers were able to quantify the cumulative economic effect of these shortcomings in reservoir knowledge. This provided encouragement to pursue a solution, but the process was difficult.
Although it may seem obvious, a prerequisite to accurate reservoir fluid analysis is the ability to acquire a representative sample of downhole fluids. In the late 1980s, a promising piece of the puzzle was developed—a pumpout module that could be incorporated in modular formation-dynamics testing tools. Until this time, highly contaminated fluid samples had been the norm because previous formation-testing tools were a closed system, whereby invaded mud filtrate was produced into a segregated sample chamber before an unknown quantity of formation fluid could be sampled. The pumpout module enabled the field engineer to pump undesirable fluids from the formation—via the sample probe—directly into the borehole, ensuring sample acquisition was performed after the produced fluid had been cleaned up to lower levels of contamination.
However, a breakthrough came in 2006 with the introduction of a focused probe tool that consistently provided a formation fluid sample virtually free of contamination from the invaded drilling mud filtrate. By using dual pumps to withdraw both the reservoir fluid and the surrounding mud filtrate simultaneously into separate flowlines, the mud filtrate could be diverted into the borehole, while the relatively pure stream of formation fluid could be obtained for measurement and collection by the field engineer in real time.

Variety of In-Situ Measurements Enabled
Once it became possible to acquire a pure sample, representative of formation fluid in reasonable time under downhole conditions, a variety of real-time measurements became feasible. Advanced instrumentation was packaged by Schlumberger into its modular formation-dynamics testing tool to perform nine separate field-selectable measurements, characterizing and describing produced fluid to enable real-time downhole analysis. The technology package, called the InSitu Fluid Analyzer system, can measureHydrocarbon fluid composition (C1, C2, C3–5, C6+)Reservoir fluid gas/oil ratio (GOR)Reservoir fluid CO2Reservoir fluid densityReservoir fluid viscosityReservoir fluid pHReservoir fluid colorReservoir fluid fluorescenceReservoir fluid resistivity
Drilling Failure Costs Quickly Add Up
Authors: Berry Cliff 
Published: February 2015

Management
Annual downtime during drilling or running casing is only marginally better than it was 20 years ago. Operators’ estimates suggest that drilling efficiency is approximately 50% when taking into account all rig activities from spud to completion, including running casing tubing.
Trying to estimate the cost of this is not straightforward, but if 50,000 wells are drilled each year worldwide, ranging in day-cost from USD 135,000 on land to USD 450,000 for a semisubmersible, or a drillship at USD 1 million, then the average daily cost could be approximately USD 250,000. For wells that encounter trouble, the average time lost per well is probably approximately 6 days, which would give average downtime costs of USD 1.5 million for each well. Stuck drillstrings are one of the major contributors to drilling downtime, and a common cause of sticking downhole is a failed centralizer. A conservative estimate is that, annually, 400 wells worldwide (less than 1% of active drilling operations) are affected by centralizer problems, at a probable cost of 400 times USD 1.5 million, or USD 0.6 billion.
With downtime attributed to centralization problems reaching that amount, industry improvement in this area is essential. Centralizers are relatively cheap, but when they fail because of damage, breakage, or simply getting stuck in hole due to insufficient fitting at the correct intervals, then they assume a consequential cost out of proportion to their price. Losses at this level would not be tolerated in other industries, such as the automotive, marine, or aeronautical industries. Why should the oil industry be different?
Most centralizer failures are caused by using an incorrect unit for the job. Every day someone, somewhere, is pulling casing and leaving debris in the hole for the simple reason that the wrong type of centralizer was used. The oil industry seems surprisingly tolerant of these failures.
Centralizers since the early 1950s have been of multipart design and construction, being either welded or interlocked and having hinges and pins to hold them together. That design has remained largely unchanged to this day. With vertical wells, this type of construction is ideal as the string is in tension and no radial loads are applied. However, these units were oversized to the borehole, had high start and drag forces, and were weak in restoring force. This type of centralizer is still a regular choice in the industry but it is the single largest contributor to downtime and overspend.
As the industry developed, and well trajectories and types changed, the demands on centralizer technology increased. Some wells now have extremely close tolerance casings, some are under-reamed, and many are horizontal. The gravity effects on casings in angular and horizontal wellbores have made radial and axial forces crucial factors.