bluuebunny/crossref_metadata_2025_split huggingface dataset:
PROINT - Program for Excellence in Integrity Management for E&P
Authors: Ribeiro Joao Luiz Moreira , Frydman Bernardo , Jordan Paul Ricardo Daniel Rodriguez 
Published: May 2011

Abstract
With the raise of the oil prices most of production installations have their expect life extended. The aging of those installations brought to the companies a different approach regarding integrity, it has been necessary to create a management system capable to deal with this issue.
The PROINT is a Program for Excellence in Integrity Management for E&P installations. It started to be developed two years ago due to an internal diagnosis where it was founded an increasing degradation of the integrity of the production installations due to the rapidly growth in numbers of them in E&P in the last decade. The Program is based on PMBoK® Guide (Project Management Body of Knowledge) structure from the Project Management Institute. It has 15 knowledge areas with 58 work processes covering all issues related the management of the integrity. Besides procedures for each work process it has a Technical Guide to all main critical equipment which is a manufacturer manual rewritten by Petrobras technicians including the operation scenarios and the best practices in operation and maintenance. It can be applied to any installation of the Company, Petrobras has decided to start in all topside installations but it will be also implemented in our subsea installations. The main deliverable from the program is a Management System which is capable to comply with all requirements from the authorities and regulatory agencies, besides, of course, all topics related to integrity.
The Program will be implemented in the next four years in all Operations and Services Units in 14 phases. At the end, Petrobras can certify each Unit in Integrity Management, if desire.
An Example of Technologies and Methodology Applied to Deep-Water Geo-Hazard Assessment, Offshore Nigeria
Authors: Adamy Jerome , Unterseh Stephan , Grimaud Sylvie , Colliat-Dangus Jean-Louis , Lanfumey Valentine 
Published: May 2011

1 Abstract
Improving our understanding of deep-water geo-hazards requires a long-term effort, which TOTAL has sustained over the last 20 years, in particular by carrying out joint R&D projects with "IFREMER", the French Marine Sciences Institute. The successful avenue has, consistently over time, yielded significant technical advances, in terms of data acquisition and data analysis.
The involvement of a wide range of specialists remains central to a properly robust analytical investigation of the processes governing the deep-water geo-hazards. The multi-disciplinary approach is also paramount to the technical specification of the acquisition program, for a campaign at sea where non-conventional instruments are deployed.
The paper presents geo-hazards targeted by the latest joint R&D project carried out by TOTAL and IFREMER, and the set of dedicated instruments deployed during the 2008 campaign, offshore Nigeria. Some significant improvements of the technology are introduced, as well as their impact in terms of geo-hazard evaluation.

2 Introduction
This paper presents an innovative approach to conducting an intensive deep-water geo-hazard study, offshore Nigeria, during the ERIG 3D joint 3-year R&D project (2007–2009). This project was directed and carried out by TOTAL and IFREMER. ERIG 3D is the last in a series of R&D projects aiming at identifying and understanding deep-water geo-hazards, namely projects GUINESS (1992–1995), ZAIANGO (1998–2002), and NERIS (2003–2005). Those projects were all conducted in collaboration by TOTAL and IFREMER.
During the course of ERIG 3D, a complex campaign at sea was conducted in 2008 with the oceanographic vessel "Pourquoi pas???, involving a wide variety of instruments, and allowing (1) the evaluation of some new equipments, only partly available in the industry, and (2) subsequent multidisciplinary studies of the deep-water geo-hazards that were targeted by the program of ERIG 3D (depth range 600–1,200 m).
The ultimate objective of the program was to validate (or invalidate) proposed new methodologies for the identification and better understanding of the deep-water geo-hazards. Two avenues of investigation were identified:technology improvements to enhance data quality, andmethodology upgrades, addressing both the offshore acquisition phase, and the assessment process.
Late-life Field Optimization, Canyon Express - A Case Study
Authors: Wells James Curtis , Zambare Neeraj 
Published: May 2011

Abstract
Canyon Express is a subsea gas gathering system in 7,200 ft water depth. It was the longest and deepest subsea tie-back at the time of its development (2000-2002). The Canyon Express System produces 40 – 60 MMSCFD and is well beyond its originally projected life. The infrastructure consists of two 12 in, 56 mile long flowlines that transfer gas from three separate subsea fields to a shallow-water production platform 56 miles away. The real-time Production Management System (ProdMS), which was designed specifically for Canyon Express, offers advantages that were presented in OTC 2007. This paper supplements the OTC 2007 paper and discusses how the ProdMS has been an important factor in production optimization over the past 4 years.
The ProdMS is a simple to use flow assurance tool which dynamically models the whole facility from the well screens to topsides gas sales. To assist in day-to-day operations and planning, the ProdMS provides various applications including an offline planning model, online subsea virtual metering, and hydrate margin prediction at every point in the flowlines.
The ProdMS has been used to reduce the amount of methanol injection for hydrate mitigation to less than one-third of the system's original dosage rate. Planning and monitoring of line sweeps to clear liquids were accomplished using the planning and real-time modes. Since the operating conditions of the pipeline system change depending on amount of production and fluid composition from each well, the ProdMS proved valuable to provide production forecasts of future wells at different operating conditions. It has been used as a virtual metering tool for all producing wells. It has also been used extensively as a day-to-day data monitoring tool onshore which allows the production engineer to supervise and monitor production facility changes remotely.
Real time ProdMS has been used to manage production efficiently at Canyon Express, a tough and challenging ultra deepwater environment, for more than five years. The ProdMS is one of the main factors in extending the life of the subsea fields by more than four years and will continue to be a production optimization tool until the end of project life.

Introduction
The Canyon Express Pipeline System consists of two 12 in flow lines running parallel from the Camden Hills Field through the Aconcagua and Kings Peak Fields to Canyon Station, a host platform located approximately forty miles north of the northernmost Kings Peak well. Production from the fields is gas with some condensate and formation water. The wells are tied together in a " daisy-chain?? arrangement. Refer to Figure 1: Canyon Express Infrastructure.
Lateral Buckling and Pipeline Walking Mitigation in Deep Water
Authors: Perinet Dominique , Simon Julien 
Published: May 2011

Abstract
The pipelines and associated structures are major components of the subsea deep water oil and gas production. Deep water production requires the transportation of multiphase hot products under high pressure and temperature. In deep water the soil is usually very soft clay of high plasticity with high water content. Both of these elements are major aggravating factors for pipeline instabilities: lateral buckling and pipeline walking. The paper presents and illustrates practical measures which are developed by the contractors for mitigating the risks of failures associated to these instability phenomenons. The analyses which are carried out for the lateral buckling and pipeline walking are generally very conservative. Such attitude is fully understandable with regards to the risks of failure in deep water. However the mitigation measures should not be inducing unwanted effects.

Introduction
The instability phenomenon associated to the variations of pressure and temperature become more acute in deep water fields. When dealing with lateral buckling and pipe walking it is considered safer to provide mitigation measures to prevent these conditions than attempting to design the pipeline system to accommodate the loads and displacements. With time contractors have developed different techniques to mitigate the risks. The purpose of this paper is to discuss the different techniques used in the industry. It will present also the negative effects which may be resulting from some measures and will describe some techniques which are new or nor yet in usage.
The pipeline displacements induced by pressure and temperature will result in stresses in the pipeline itself and the connection spools and subsea structures. The continuous production cycles of start up and shut down result in cyclic loading and progressive movements of the flowlines. This will result in cumulative fatigue damage to the flowlines, which, if not considered in the overall design of the flowline system, can lead to failure and rupture of the flowline. Failures may occur on different types of pipe: single pipe or pipe-in-pipe as illustrated in the Figure 1. The fracture surfaces are smooth indicating a fatigue failure with a number of cycles in the range of one hundred thousand to one million.
A Global Perspective on Biocides Regulatory Issues
Authors: Bradley Gregory , Mcginley Heather , Hermsen Nanette 
Published: May 2011

Abstract

Description of the Proposed Paper
This paper will review the regulations pertaining to offshore biocide use in different regions of the world. The roles of regional and global organizations in helping to harmonize available environmental, health, and safety information will also be discussed.

Application
Many offshore applications involve the use of biocides, including drilling, production, and pipeline operations. Biocides are also vital to reservoir integrity, flow assurance, and prevention of microbial corrosion. Regulation of the use and discharge of chemicals, including biocides, must be well understood in order to protect the environment and maintain compliance.

Results, Observations, and Conclusions
Each region, and in some cases each country, has its own method of evaluating risk for chemical use. These assessments lead to varying degrees of regulation throughout the world. In some cases there are additional regulations for offshore chemical use. It should be noted that several organizations exist which aim to standardize the risk assessment process for Biocides. The Organisation for Economic Co-operation and Development (OECD) publishes test protocols for its global member countries that are widely used for determining the ecotoxicity and other environmental parameters of chemicals. Regional guidelines are also in place in some areas; for example, North Sea countries have adopted the Harmonized Offshore Chemical Notification Format (HOCNF) to ensure that each country's regulatory agency is considering the same data set. Ultimately, each regulatory body is responsible for performing its own risk assessments and enforcing its own standards.

Significance of Subject Matter
For chemical suppliers, service companies, and asset owners who operate globally, it is important to be aware of how regulations vary from region to region. An understanding of the science behind these regulations can also lead biocide users to make informed, environmentally-conscious decisions.
Carbon Capture and Sequestration: Ascertaining CO2 Storage Potential, Offshore New Jersey, USA
Authors: Brown Alan Lee , Berlin Eric Hamilton , Butsch Robert John , Senel Ozgur , Mills Joseph , Harichandran Arutchelvi , Wang James Tak Ming 
Published: May 2011

Abstract
The onshore area of the Northeastern United States is lacking in reservoir intervals appropriate for storing large volumes of carbon dioxide (CO2). It is proposed that the geologic conditions found offshore of the Eastern Seaboard are conducive to the safe storage of large volumes of CO2 generated from anthropogenic activities in the region (Schrag, 2009). Little subsurface investigation has occurred in this area since it was initially explored for hydrocarbons in the mid-1970s. Can newer data evaluation techniques be applied to older data to ascertain the CO2 storage potential of the Atlantic Outer Continental Shelf?
Schlumberger Carbon Services recently performed an initial site evaluation of storage potential for CO2 within the Cretaceous intervals near the Baltimore Canyon Trough utilizing vintage wireline, core, and 2D seismic data to develop a geocellular model to simulate CO2 injection and storage. The evaluation site is centered approximately on the COST B-2 well, located about 70 miles offshore of New Jersey and drilled as a stratigraphic test in 1976. The COST B-2 well and others drilled in the late 1970s and 80s penetrated a Lower Cretaceous interval abundant in channel and mouth-bar sands deposited in a wave-dominated delta-front to nearshore depositional environment. Petrophysical analysis of available wireline data indicates these sands exhibit porosity and permeability ranges adequate for the potential injection of CO2. Additonally, log analysis indicates laterally extensive and vertically thick marine shales overly these potential reservoir intervals and provide an appropriate seal across the region. This petrophysical analysis was integrated with interpretations from available two dimensional seismic lines to investigate the spatial potential of the targeted sediments to store large volumes of injected CO2.

Introduction
In order to properly assess the potential for CO2 storage of any specific geologic formation at any specific geologic site, the primary attributes for the subsurface interval being investigated must be evaluated for storage potential. We will explain analysis of the key variables associated with the construction of a subsurface model that can adequately evaluate the potential Storage Capacity, Injectivity, and Containment for CO2 storage. The site being investigated in this study is located within the United States (U.S.) Atlantic Outer Continental Shelf (OCS), approximately 70 miles east of the upper New Jersey coastline in the vicinity of the COST B-2 well (Figure 1). For this initial assessment, vintage wireline, core, and two dimensional (2D) seismic data, acquired during exploration for hydrocarbons in the late 1970s and early 1980s at or near the proposed site, were utilized to develop a geocellular earth model and reservoir simulation model so that injection rates, plume size, well design, and construction costs could be estimated.
Produced Water - Impact and Analysis Challenges in Cold Regions
Authors: Hawboldt Kelly , Bottaro Christina , Thanyamanta W. 
Published: May 2011

Abstract
Produced water accounts for the largest volume in the production stage of offshore oil and gas operations. There are very few studies dedicated to investigating impacts of produced water discharge in Arctic/cold regions. As exploration expands into these regions, the effects of the cold temperatures, high motion, ice, and extended periods of sunlight on fate and toxicity of constituents will need to be more fully understood due to environmental concerns and production costs. The fate of discharged produced water is determined by dilution and mixing, volatilization/dissolution/sedimentation, and biochemical/chemical reactions. These transport/transformation mechanisms are not well characterized in cold environments. Low temperature and motion may affect efficiency of separation equipment and reduce natural biodegradation and evaporation. As a result, the type of constituents targeted in warmer climates may not be a concern in cold regions and may be replaced by other constituents. The first part of this paper will identify chemicals of concern in produced water for cold regions and model their fate in the environment. Due to the low temperatures, many of the contaminant transformations will be governed by equilibrium. Identification of the chemicals of concern leads into the second theme of this paper. Oil and grease is monitored for regulatory purposes however, what is defined as " oil and grease?? depends on analytical/sampling methods which vary between regions. For instance, some methods measure both the dispersed and the dissolved hydrocarbons, so measurements of dispersed oil tend to be " overestimated?? when compared against limits. Comparison of analytical data between platforms or building of annual trends is also complicated. Discrete sampling, when the sample analysis is done onshore, delays mitigation or corrective actions with respect to process control and does not give an accurate temporal trend in oil in water discharge. Using the information from the " identification and fate?? section of this work we have been developing molecularly imprinted polymers (MIPs) for highly selective isolation, detection and measurement of key constituents (e.g. alkylphenols) and are working toward devices to house the MIPs for online analysis. The development of these systems will allow the non-specialist to quickly identify constituents in the field and enable extensive data collection in real time and hence the knowledge to make informed and timely decisions.
Offshore Nova Scotia Play Fairway Analysis: 2D Basin Modeling Results
Authors: Colletta Bernard , Monnier Frederic , Rabary Guillaume , Doublet Stefan , Letouzey Patrick 
Published: May 2011

Abstract
This paper presents part of the modeling results obtained in the Play Fairway Analysis project launched in 2009 by OETRA that consists of an integrated geosciences approach in a collaborative program between academy and industry institutions. A 210 km long depth-migrated seismic line (NovaSPAN 1400) was interpreted in age, paleo-environments and lithology. The structural evolution was reconstructed to constrain the backstripping. Two major source rocks, Late Jurassic marine type II and Early Cretaceous terrestrial type III were identified from pyrolysis analyses. A third type II source, of Early Jurassic age has been inferred from the presence of Gammacerane biomarkers in the Venture B13 condensates, which were correlated with Pliensbachian source rocks and oils from the conjugate margin in Morocco and Portugal.
The interpreted section displays 3 structural domains: the little deformed shelf area, the strongly disturbed bathyal domain with complex salt tectonics structures and the flat lying strata domain of the abyssal plain.
Modeling results show that the Early Jurassic and Late Jurassic sources are presently in the gas and oil window respectively. Early cretaceous is immature. Expulsion and entrapment occurred lately and first significant accumulations appeared during the Cretaceous (about 80 Ma ago) and are still active today. Three potential plays can be considered for exploration:Late Jurassic carbonate bank with a risk of biodegradation due to low Present temperature (around 60°C);Early Jurassic carbonate ramp along the northern salt basin boundary,Hypothetical turbiditic sands in the Early Cretaceous (Logan Canyon equivalent)
A Super-Giant Offshore Field Development Plan Change from Steel Structures to Artificial Islands
Authors: Modavi Cyrus Abdulla , Al Muflehi Abdul Hakeem , Taemoom Ihaab , Al-Khateeri Bakheet S. , Noman Adil M.A. 
Published: May 2011

Abstract
The offshore giant oil field covers an aerial extent of approximately 1200 square kilometers. The field development to date has been based on pattern producer and water injection wells drilled from numerous Well Head Platform Towers (WHPT's) located through-out the field; these are connected via subsea pipelines to satellite platforms and an in-field central complex.
The field operator has a mandate to increase the production rate by 40% in the near future. If the current steel platform development plan were to be continued, numerous new WHPT's, additional thousands of kilometers of subsea pipelines, and significant facilities upgrades on existing satellites and the central processing platform would be required. The increasing complexity and cost of such an expansion motivated a major change of the development plan through construction of artificial islands and use of extended reach and long horizontal completions. The location of the field in water-depths ranging from 5 to 15 meters, allows cost effective construction of artificial islands. Also favoring application of artificial islands for the subject field is its long expected operating life (nearly 100 years) that exceeds the life of the existing steel platforms. The island concept provides enormous flexibility in managing future subsurface and surface uncertainties. The islands-based development will provide a low cost foundation for phased installation of facilities and allow space for future requirements, such as facilities for Artificial Lift, Gas Injection and other EOR applications. In short, for the case presented, artificial islands as drilling/production centers provide the following advantages:Provisions for cost-effective/phased facilities installationsEnhanced field operability, at lower OPEXReduced downtime lossesFlexibility to capture up-side potentials during field life cycleEnhance possibilities for future EOR applicationSignificant development cost reduction
In conclusion, where environmentally and economically viable, building artificial islands as drilling and production centers, offers numerous advantages over steel-base structures, which could even justify island construction within existing brown field infrastructures.

Introduction
The field is located 84 km offshore Abu Dhabi, as shown in Figure 1. It was discovered in the early 1960's and covers an aerial extent of approximately 1200 square kilometers. A simplified field cross section is shown in Figure 2.