bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Case Study in Wax Removal From a Subsea Flowline
Authors: Bybee Karen 
Published: February 2015

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 105048, "A Case Study in the Removal of Deposited Wax From a Major Subsea Flowline System in the Gannet Field," by H.A. Craddock, SPE, K. Mutch, and K. Sowerby, Roemex Ltd., and S. McGregor, J. Cook, and C. Strachan, Shell UK Ltd., prepared for the 2007 SPE International Symposium on Oilfield Chemistry, Houston, 28 February–2 March.
The following stages were key to the successful wax-removal operation: selection and design phase of the chemical application, the environmental chemical-selection criteria, the development of the work scope, and the logistics of the chemical application. The wax-removal process was deemed successful and offered the client significant benefit in terms of increased oil production. Reduced pipeline differential pressure and increased fluid arrival temperatures also indicated that the wax restrictions in the flowlines had been removed.

Introduction
The control and mitigation of wax deposition and its concurrent problems rapidly are becoming critical challenges facing the oil- and gas-production industry as the industry explores and develops in increasingly challenging environments, such as deepwater and subarctic conditions. Wax deposits can occur widely in the production process and often are considered the organic equivalent of scale formation.

Field Description
The Gannet field is 180 km east of Aberdeen in a water depth of approximately 90 m. Since the field was originally discovered, in the 1970s, several satellite fields have been tied into the Gannet facilities. Gannet D is an oil field 16 km northeast of Gannet Alpha. Production is from five wells, with oil transported back to the Gannet Alpha facilities by two looped 6-in. subsea flowlines referred to as Riser 31 and Riser 32. The crude from these reservoirs typically is 41°API, with a wax content of approximately 7% and a wax-appearance temperature of approximately 35.5°C. The Gannet G field also is produced by this system with a single 6-in. flowline tied in at the base of Riser 32, 0.5 km from the Gannet Alpha platform. Riser 31 carries Gannet D crude only, and Riser 32 carries Gannet D and G crude topside onto the Gannet Alpha processing facilities, where the oil is commingled with other Gannet fluids before being exported to the Fulmar platform.
Overview: Reserves/Asset Management (December 2007)
Authors: Rietz Dean 
Published: February 2015

What does it mean to manage reserves and assets in the context of the oil- and gas-production business? It really means making the right decisions under significant, yet potentially calculable, uncertainty. Whether you are a small independent or a large state-owned oil company, you face many of the same problems—only the scale or magnitude is different. In our industry, we face more than our fair share of uncertainties in managing assets. Those "unknowns" are pervasive throughout the many aspects of oil and gas exploration. A few of the more significant ones are as follows:Geological (structure)Petrophysical (rock properties)Drilling successEffectiveness of completionsDrive mechanism (recovery efficiency)Political (country risk)Contractual complexities and reversionsTiming of first oil for new developmentsImpact of weatherProduct price
This set of uncertainties obviously comprises a nonexhaustive list of the many factors that should enter into the review and planning processes. In spite of the unknowns that complicate our work, we still need to make decisions—decisions that are made to maximize true asset and/or shareholder value. As engineers, we can help to make those decisions the correct ones by providing decision makers with as much relevant information as possible, along with the appropriate risks and uncertainties associated with that information. Many times, we make less-than-optimal decisions because of a lack of desired information. However, we continuously strive to make the best decisions possible on the basis of the data at hand. The papers highlighted in this segment should help illustrate some ways that others are reducing uncertainty to help make their decisions the correct ones. In addition, some of the referenced papers help provide guidance and consistency in the reserves-estimation process. Ultimately, that type of consistency will reduce the uncertainties of asset valuation and improve asset management.
Reserves/Asset Management additional reading available at the SPE eLibrary: www.spe.org
SPE 107709 "Beyond Portfolio Optimization" by L.C. Faya, Constellation Energy Commodities Group, et al.
SPE 109012 "Reservoir-Management Aspects of the Rejuvenation of the Forties Field, UKCS" by Owen Vaughan, SPE, Apache Corporation, et al.
SPE 110617 "Methods for Incorporating Costs, Pricing, Gas Shrinkage and Transport Tariffs, NGL and Inert Revenues, and Working Interest in Gas Plants and LNG Projects Into Reserves Estimates" by John McLaughlin, SPE, Ryder Scott Company, et al.
Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 107693, "The 2007 SPE/AAPG/WPC/SPEE Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!," by John R. Etherington, SPE, PRA International, and John E. Ritter, SPE, Occidental Petroleum, prepared for the 2007 SPE Hydrocarbon Economics and Evaluation Symposium, Dallas, 1–3 April.
In late 2004, a focused effort was begun to update the 1997 SPE/World Petroleum Council (WPC) Petroleum Reserves Definitions and the 2000 SPE/WPC/American Association of Petroleum Geologists (AAPG) Petroleum Resources Classification and Definitions. Evolution of the industry, driven by advancements in technology, the international expansion of the E&P sector, and the increasing role of unconventional resources in meeting global energy needs, drove the update. The 2007 system builds on previous industry efforts to provide sufficient guidance to achieve a high level of consistency in estimating resource quantities; it incorporates best practices identified in other international petroleum and minerals classification systems. Assessments may be conducted using deterministic and/or probabilistic methods. To satisfy requirements of the full range of industry stakeholders, the 2007 system introduces additional classification and categorization terminology. The resulting document is a set of technical guidelines that can be adopted by oil and gas companies to manage their business better. Moreover, it forms a standard that can be referenced by government agencies in defining reporting requirements.

Introduction
All assessments of in-place and recoverable petroleum quantities, their forecast delivery profile, and associated costs and revenues have significant inherent uncertainty. However, it is essential for future planning that governments, lenders, investors, and producers have access to consistent and reliable assessments, and that results be presented in a common format to communicate these underlying risks and uncertainties. The task of creating and maintaining the framework and language to support such communication has been assumed primarily by a consortium of professional societies: SPE, WPC, AAPG, and the Society of Petroleum Evaluation Engineers (SPEE). Their work is coordinated through the SPE Oil and Gas Reserves Committee (OGRC).
The OGRC was charged to recommend revisions and clarifications to maintain a standard for petroleum evaluations. The 2007 petroleum reserves and resources classification, definitions, and guidelines has been titled the Petroleum Resource Management System (RMS) (SPE 2007) and is hereinafter referred to as SPE-RMS or simply the SPE system; this label is intended to recognize the valuable contributions of the cosponsoring organizations (WPC, AAPG, SPEE), without whose input the resulting product would not have been generated.
Technology Integration in the Caspian
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 106858, "Technology Integration in the Caspian," by Ian Pannett and David Hodgson, BP plc, prepared for the 2007 SPE Digital Energy Conference and Exhibition, Houston, 11–12 April.
BP's Azerbaijan Strategic Performance Unit (ASPU) was developed to meet key challenges of operating within the Caspian region and to maximize business value. Key challenges include complex depletion plans; unconsolidated reservoirs; a difficult-to-drill overburden; and an integrated development, gathering, and export system. To meet these challenges, advanced seismic, intelligent completions, zonal-flow monitoring and control, and field of the future (FOF) technologies collectively address the business challenges.

Introduction
Integration is key for the Azerbaijan strategy, specifically the technology strategy. The assets and reservoirs are integrated in a variety of ways and designed to operate in an integrated way. This integration is essential to maximize reservoir recovery. As the strategy developed, increased integration could create additional opportunities for performance improvements.

Azerbaijan Assets
As shown in Fig. 1, the BP-operated assets center on development of two very large hydrocarbon reservoirs in the Caspian [the Azeri, Chirag, and Guneshli (ACG) oil fields and the Shah Deniz (SD) gas development], although it is fully expected that other assets will be added. In addition, BP operates two major pipelines through which these hydrocarbons are exported—the Baku-Tbilisi-Ceyhan (BTC) and the South Caucasus Pipeline (SCP), which originate at the Sangachal terminal, south of Baku. These pipelines are designed to take ACG and SD reserves to market with capacity to take oil and gas from other fields and operators. A fully redundant data network is in place linking all facilities with a high-bandwidth optical-fiber "ring-main" backed up by satellite data systems. Fig. 2 summarizes the ACG full-field development.

Technology Plan
The 5-year technology plan integrates all functional and asset-based activities across business areas supporting the ASPU. The strategy includes leadership in a few key areas, efficient deployment of technology in other areas, bias toward rapid application of proven technology, and healthy progression of options in selecting available technologies. This strategy has helped to focus and prioritize technologies.
The technology plan was developed in conjunction with field-depletion plans. The technology plan also was designed to improve ultimate recovery. The current ACG-development plans recover approximately two-thirds of the potential. Obtaining maximum value requires sophisticated reservoir management and application of advanced technologies such as multilateral completions and other enhanced-oil-recovery technologies.
Subsea-Data Management
Authors: Denney Dennis 
Published: February 2015

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 18744, "Subsea-Data Management," by Brian Drakeley, SPE, Weatherford International, Svein Omdal, SPE, Statoil, and Sigurd Moe, SPE, FMC Technologies, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May.
This project will contribute toward making real-time reservoir-monitoring and other downhole data avail-able every where on Statoil's network infrastructure. The goal is to resolve hurdles for implementing fiber-optic monitoring and data transmission from subsea developments. Focus is on detailed seabed-system solutions to create an open high-speed communication infrastructure, which fiber-optic technology enables. The project will develop interfaces with existing subsea systems that have only electrical low-bandwidth communication systems.

Introduction
In June 2005, Statoil requested technical and commercial proposals relating to the development of integrated fiber-optic systems (an integrated subsea communications system) and reliable downhole sensors.
There are two key project areas:Downhole-sensor (DHS) sand monitoring (identification and quantification), multiphase flowmeter (for intelligent-well applications), and distributed pressure and temperature measurementsIntegrated fiber-optic subsea system (IFOSS) containing subsea well-sensor interrogation solutions, a subsea-control system, a subsea telecommunication and transmission system, and an integrated fiber-optic system
Fig. 1 illustrates the scope of the project and how these key project areas fit into the total integrated system.

DHS Real-Time Reservoir Monitoring
Essentially, in-well monitoring systems are required that deliver high-quality measurements throughout the life of the well without the need for routine maintenance or intervention. With no downhole electronics in existing fiber-optic systems, sensing systems are intrinsically more reliable than electronics-based systems.
With increased demand for more data on reservoir and well performance, communication systems must have that significantly improved signal performance, data density, and trans-mission distance, which leads to a fiber-optic solution.

Existing Downhole Fiber-Optic Sensors
Currently, there are four types of optical sensing systems.
Pressure/Temperature (P/T). Many P/T fiber-optic gauges have been installed and are very reliable.
Distributed Temperature Sensing (DTS). DTS systems are the most widely used fiber-optic sensing system. These systems provide a continuous temperature log of the well along the entire length of the fiber [e.g., a production (or injection) thermal profile of the well] and can be used to identify well problems; water, gas, and steam breakthrough; gas lift valve and system performance monitoring; and paraffin and hydrate formation monitoring. Measurement points are at 1-m intervals, and temperature resolution can be on the order of ±0.1°C.
Comments: Rig Boom
Authors: Donnelly John 
Published: February 2015

Editor's column
Despite the current global financial crisis and recent steep decline in commodity prices, the market outlook for drilling rigs remains strong. Demand for deepwater units, in particular, remains healthy. Even with a global recession, world energy demand is projected to rise in the medium term and companies are moving to deeper waters and frontier areas to secure new production.
Mobile offshore drilling rig demand in almost all of the world's major drilling centers have been posting 90%-plus utilization rates, and strong demand and tight rig supply have contributed to strong dayrates. A rig that may have brought in USD 200,000/day a few years ago can now earn USD 500,000/day and recent contracts for deepwater rigs have topped USD 600,000/day. A surge of interest in new drillships, semisubmersibles, and high-end jackups has occurred the past several years and some of those are now entering the market. The best markets for floating rigs have been Brazil, west Africa, the US Gulf of Mexico, and southeast Asia.
In addition, 181 rigs are currently being built or on order, including 85 jackups, 54 semisubmersibles, and 42 drillships, according to Citigroup energy analysts. Of these 181, more than half are currently under contract. While about 69% of the floaters (drillships and semisubmersibles) have contract commitments, only about a third of the newbuild jackups do, so it is unclear how many will become operational.
Some of that newbuild interest is turning toward rigs that can operate in particularly harsh conditions, such as the Arctic, or in ultradeepwater. Rigs in the Barents Sea—where Gazprom, StatoilHydro, and Total are developing the world-class Shtokman gas field—will need to withstand unprecedented harsh climatic conditions and vast icebergs. Shtokman will require three of the largest platforms in the world, ice-resistant and capable of withstanding 25 m waves. Three seabed pipelines will carry the gas to shore to terminals in Teriberka in the Murmansk region, where an LNG plant will be located.
Buoyed by recent discoveries and ambitious development plans, Brazil has emerged as the dominant leader in the drilling rig market. Utilization rates there are at 100% with 31 semisubmersibles and nine drillships in the region under contract. State oil company Petrobras is reportedly in the market for as many as 40 deepwater rigs, even though it has already contracted the majority of the existing ultradeepwater fleet. That indicates that there is still a shortage of deepwater rigs worldwide, even if the global economy and oil demand soften. West Africa rig utilization is nearly as strong, at 97%. And China's offshore deepwater oil and gas development has also set off rig construction activity.
The global credit crunch is limiting the ability of companies to get financing and may slow the pace of newbuilds significantly, however. Higher steel and equipment prices combined with the tighter finance market already appear to have cooled off the speculative newbuild market.
The Coming Shootout at the LT Corral
Authors: Lovie Peter 
Published: February 2015

Guest editorial
The traditional pipeline infrastructure in the US Gulf of Mexico (GOM), perhaps the most efficient in the world, faces new challenges as fields lie further and further from shore, in deeper and deeper water, and increasingly in mountainous seabed terrain. The apparently obvious tanker solution is not so easy in US waters with the Jones Act requirement to use higher-cost US-built and -manned tankers, often at economics and availabilities different from international trade. Only last year were the contracts signed for the first shuttle tankers in the GOM, for operations starting in 2010 at the early production system (EPS) being used for the Cascade/Chinook development (Petrobras operated with Devon and Total as partners).
The stakes are high, with transportation contracts in the billions of dollars, whether for pipeline or shuttle tankers. A "shootout" threatens to become immediate, with the export mode to be decided in the next year for longer-term, full-field developments: Jack/St. Malo (Chevron operated) and Kaskida (BP operated). I work for Devon, which has large minority interests in both of these developments plus many other Lower Tertiary (LT) prospects—some Devon operated (such as Bass, now drilling) and some not. Each time our company runs the numbers, we see how the economic prize on the export negotiating table is huge and how the traditional pipeline solution is challenged like never before.
These two different transport modes have battled it out in the GOM intermittently since 2001. So far, the pipeliners have prevailed over the tankermen.
The laws of physics and economics will soon be tested in the marketplace as pipeliners and tanker companies square off on transporting crude oil production from the remote locations of LT prospects in the GOM. What is different this time is the combination of distances, water depths, and the scale of investments. When it stretches the technical and economic limits of the pipeliners, the tanker people just steam a little further out. And if the field plays out early, the tankermen just go somewhere else with their vessels.
During 2000 and into mid-2001, deepwater export was the theme of a low profile but intense competition for exporting production from BP's coming developments. It went down to the wire: bids and counter bids, pipe vs. storage vessel, and tanker export. The regulatory picture was not clear back then—US government approval of the Minerals Management Service (MMS) Environmental Impact Study approving floating production, storage, and offloading (FPSO) vessels and shuttle tankers in the GOM was not given until December 2001. And use of tankers would have prevented a steady income from partial or complete oil company ownership of a pipeline. The prize went to the pipeliners in what is now the Mardi Gras system. Pipeliners 1, Tankermen 0.
Techbits: Nigeria Annual Conference Draws International Crowd
Authors: Moon Ted 
Published: February 2015

Techbits
More than 1,500 oil and gas professionals from around the globe converged on Abuja, Nigeria during 4–6 August of this year for the SPE Nigeria Annual Conference and Exhibition. With a theme "Innovating to Meet the Challenges of Global Energy Demand," the conference explored key industry issues such as finding sustainable solutions for the increasing worldwide energy demand and developing innovative ideas and technologies that will produce hydrocarbons more efficiently.
"Even though this conference was held in Nigeria and was organized by the SPE Nigeria Council, it was very much an international conference," said Charles Akhigbe, Drilling Fluids Specialist with Shell Nigeria's Wells Technology and Expertise Support Team and Chairperson of the Conference. "Of the 1,500 attendees, we had many expatriates from Asia, other parts of Africa, and Europe. The vast majority of these attendees were businessmen, representatives of Nigerian government regulatory agencies, banks, technical experts and industry professionals from all major oil and service companies, as well as some research institutions and universities."
The technical sessions began on 4 August and were sponsored by British Gas Exploration and Production Nigeria. Each technical session had two cochairs—managers and higher-level executives from major petroleum companies, some of whom are also members of the SPE Nigeria Council. "Participation in the Nigerian council cut across all of the oil companies and many service companies in Nigeria," Akhigbe said. "We had participants from Shell, ExxonMobil, Addax Petroleum, Total, Schlumberger, Halliburton, Afren, Agip, Chevron, Sapetro, Baker Hughes, Nigerian National Petroleum Corporation (NNPC), Oando, Nigerian Petroleum Development Company (NPDC), Platform Petroleum, Global Energy, and Midwestern Oil and Gas."
The technical sessions included 48 papers spanning all upstream disciplines, from drilling and completions to geosciences, HSE, and management. "There were also case studies, and most focused on wells and field experiences outside of Nigeria. The feedback I received was that the technical sessions were all of high quality," Akhigbe said. In fact, in a survey after the conference, 68% of responders considered the technical content of the conference to have been very good or excellent.
"As is typical for our conferences, we gave an award to the best technical paper based on recommendations of the Technical Paper Committee," he continued. "The technical paper session chairs assess each presentation in their session and pass the assessment on to the Technical Paper Committee, who then investigates each assessment and determines the winner. The award this year went to Chukwuma Uguru, Shell Nigeria Regional Petrophysics Discipline Lead, who presented a paper titled "A Simple Analytical Model for Vertical Permeability Prediction."