bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Evaluation of Critical Success Factors in Deepwater Oil & Gas Project Portfolios in Nigeria
Authors: Denni-fiberesima Damiebi , Rani Nazatal Shima Abdul 
Published: May 2011

Abstract
Deepwater project portfolios are complex and high risk with a lot of uncertainty. They present unique challenges and require capital intensity to initiate projects. Most authors argue that specific factors relevant for successful competitive performance vary from business to business and industry to industry. This study focuses on investigation of the critical success factors required for successful deepwater development offshore Nigeria.
Thirteen critical success factors were established along with project delivery schedule, project budget and portfolio management strategy as impacting on project success. A sample of 200 participants within the deepwater oil and gas project environment, were identified and issued with a set of self developed item questionnaire.
With the use of the Statistical Package for Social Sciences (SPSS) tool, the findings of this research show that of the thirteen critical success factors, all are of high prevalence and importance within the deepwater oil and gas project portfolios. It also identified that some critical success factors in mega construction projects can apply to deepwater oil and gas projects. Understanding local environment was identified as a core prerequisite for project success. The research also discovered that specific competency and skill sets with increased technological expertise are required for successful deepwater oil and gas portfolio development. The results of the analysis also confirms a strong positive relational congruency between prevalence of critical success factors and organizational/project portfolio strategy.
Project management is indispensable for business results, the research would help create strategic dialogue on issues of project success that reflect the realities of capital project management in, the oil, gas and petrochemical sectors, to improve efficiency and further ensure a framework of good practices is consistently applied. It is useful for deepwater oil and gas project management practitioners in the petroleum industry who will encounter issues of cost and schedule overrun, strategy and resource allocation and therefore, can make use of the recommendations in this research study. It will also bridge existing knowledge gap and enhance further success in locating extracting and transporting oil and gas to meet global demand.
New Anti H2S Layer for Flexible Pipes
Authors: Epsztein Thomas , Demanze Frederic , Lefebvre Xavier , Jarrin Jacques 
Published: May 2011

Abstract
Flexible pipes are extensively used for oil and gas development and thus transport the corrosive fluids of the production flow. These corrosive components (water, carbon dioxide or hydrogen sulfide) do not enter in direct contact with the structural steel layers of the pipe. However, they will diffuse through the pressure sheath and may induce corrosion phenomena on the structural layers. H2S gas could thus be present in the annulus. It is then necessary to use pressure vault and armour wires made of sour service steel grades instead of sweet service steel grades.
In addition to the cost impact, the choice of these sour service steel grades with often lower mechanical performances has a direct influence on the overall design of the flexible pipe as they will result in structures with higher weight. Such a weight increase can be a disadvantage, for example in the case of ultra deep water applications.
To prevent H2S from reaching the annulus of the pipe, a new thermoplastic material was developed. Components in the sheath material react with H2S and prevent it from diffusing and reaching the annulus.
The use of this new ‘Anti-H2S’ layer will ensure a H2S free environment in the flexible pipe annulus. Considering that the steel layers will not be exposed to H2S, no degradation linked to the presence of H2S needs to be taken into account in the choice of the structural steel layers constitutive of the annulus. Consequently, the use of high steel grades layers with reduced thickness will be possible, reducing the cost and the weight of the flexible pipe.
In addition, the ‘Anti-H2S’ layer makes it possible to propose flexible pipes for applications with high H2S contents, for which no solution could be proposed otherwise.
Aging Impact on Thermal Performance of the Aspen Wet Insulated Flowlines
Authors: Meng Weihong , Shields Daniel 
Published: May 2011

Abstract
Wet insulation systems have been used in deepwater development projects in the petroleum industry for many years, with various successes and failures being observed. This paper presents a case study: the Aspen wet-insulated flowline system - the original design and the thermal performance in early days, and now after 8 years in production.
Using production flow rates from the daily reports, with temperature and pressure data provided by the subsea and topsides online monitoring sensors, OLGA simulations were performed to calculate the arrival temperatures at the host and compare them against the field gathered data. Additional simulations were subsequently performed to benchmark the model thermally and determine the effective overall heat transfer coefficient of the Aspen flowline systems. This information will help the industry to better understand the performance of an aged wet insulation system.

Introduction
The Aspen field is located approximately 150 miles south-southwest of New Orleans, LA, in water depths of 3,100 ft in Green Canyon 243. The oil field was discovered in 1Q 2001 with BP as the designated operator and co-owners with Nexen Petroleum USA Inc.
The subsea well development (Wells AA1 and AA2) was brought online in 4Q 2002. Fluid is transported for processing at the Bullwinkle platform, located approximately 16 miles to the northwest in Green Canyon 65 in 1,353 ft of water. The original subsea production system consists of two PLEMS at the well location connected to the host with dual 7 inch flowlines and catenary risers. A rigid pigging jumper connects both PLEMs together to provide round trip pigging capability for hydrate management, paraffin removal, and production flexibility to accommodate the various production schemes and well testing requirements of the multi-well system, see Figure 1.
The subsea wells are controlled via an electro-hydraulic control system with an integrated umbilical running from the host facility to an umbilical termination assembly (UTA) adjacent to the subsea trees. Hydraulic connection from the UTA to the tree is via steel tube flying leads, and from the tree to each associated PLEM also via similar type flying leads. Dual redundant power and communication electrical flying leads (EFLs) are also connected from the UTA to the trees and from the trees to the PLEMs for instrumentation.
The flowlines and risers are insulated with 2.64 inches of GSPU (Glass Syntactic Polyurethane), which allows the flowline operating temperatures to be maintained above the in-situ wax appearance temperature and provides the required cooldown time for hydrate management. In order for the system as a whole to meet the required cooldown time, the field joints are constructed of solid polyurethane with a minimum of 4 mm overbuild so as to provide a similar U-value to the GSPU insulated flowlines. The subsea trees, well jumpers and PLEMs are insulated with pour-in-place GSPU foam while the jumper connectors are insulated with insulation doghouses.
Deep-water Archaeological AUV Surveys and Photo Capabilities
Authors: Church Robert , Westrick Robert , Warren Daniel J. 
Published: May 2011

Abstract
In January 2001, C & C Technologies, Inc. placed into full operation the first commercial deep-water Autonomous Underwater Vehicle (AUV) in the Gulf of Mexico. The application of this advanced technology was immediately beneficial to the survey industry as well as having a profound impact on deep-water archaeology. Over twenty-four shipwrecks and several additional potential wrecks have been discovered and/or investigated using C & C's AUVs. Several of those surveys resulted in new discoveries and at least, thirteen of the wrecks have been confirmed to be historic vessels. The initial primary geophysical instrument payload of the HUGIN model AUV consisted of dual frequency side scan sonar, subbottom profiler, and multibeam bathymetry. In 2009, C & C added a digital still camera to the vehicle allowing relatively quick visual confirmation of seafloor targets. The photos and photo mosaics produced from the camera surveys have further advanced deep-water archaeological investigation and mapping. This paper focuses on the archaeological application of the AUVs and in particular the photographic capabilities and utilization of those photographs.

Introduction
Autonomous Underwater Vehicles (AUVs) are built for a variety of purposes and come in many shapes and sizes with near limitless combinations of sensors and payloads. Camera systems are a relatively new addition to some of the deeper AUV systems. Currently, there are only a few companies, institutions, or government agencies (e.g. C & C Technologies Inc. (C & C), Kongsberg, Woods Hole Oceanographic Institution (WHOI), the United States Navy, etc.) that operate AUVs equipped with digital still cameras capable of survey to 1,000 meters or deeper. This paper will focus primarily on the C-Surveyor AUVs, which are HUGIN 1,000, 3,000, and 4,500 meter systems (Figure 1). All references to " AUV?? in this paper refer to one of the C-Surveyor AUVs unless otherwise specifically stated. Four AUVs have been added to C & C's fleet over the last decade as well as several payload and sensor upgrades. Although the sensor payload of each AUV may be slightly different, the basic payloads include an EM 2000 multibeam bathymetry system (Figure 2), Chip Edgtech subbottom profiler system (Figure 3), and duel frequency side scan sonar at 410 kHz and either a standard 120 kHz frequency or a 230 kHz dynamically focused sonar system (Figure 4). Three of C & C's AUVs (the 3,000 and 4,500 meter systems) are equipped with digital still cameras (George 2009a). The navigation/positioning system for the AUVs utilize a Kalman filter algorithm, which uses input data from a Simrad High Precision Acoustic Positioning (HiPAP) System, inertial navigation, and Doppler velocity speed log. The post-processed positions for the AUV are accurate to within ± 5 meters at a depth of 3,000 meters.
Dredging Technology for Deep Sea Mining Operations
Authors: Vercruijsse Paul , van Muijen Henk , Verichev Stanislav 
Published: May 2011

Abstract
There is little doubt that the tremendous increase in capacities of equipment is the most eye-catching development within the dredging industry. A general misperception however is that the reduced dredging costs over the last decades are simply a result of an increase in capacity only. Other equally important factors are the increase in efficiency as well as a reduction of down time resulting from a sound design philosophy in combination with the continuous improvement of key subsystems and individual components like excavation tools, high efficiency dredge pumps, robust submersible drives and integrated automation systems.
Deep sea mining operations by nature are performed (or planned) in challenging environments. Another typifying characteristic of deep sea mining operations is the relatively high investment cost. This combination challenges engineers to design configurations able to mine the desired production rate in an efficient way. As design choices made for individual systems impact other parts of the system, it is vital to follow an integral approach to establish the one optimal overall system.
Based on what is considered to be a ‘proven technology’ in the dredging industry and more particularly in dredge mining it will be illustrated how design choices made regarding the excavation and hydraulic transport system impact on other parts of the overall system. Ultimate goal hereby is to establish the desired output at minimum Capex and Opex.

Introduction
Dredging and especially dredge mining learns that the excavation system, the slurry transportation system and the processing plant cannot be considered as individual sub-systems. These systems in any ‘traditional dredge mining’ operation interrelate to such an extend that they must be developed towards an integral solution. The nominal production, peak production and variability of these figures must match for all sub-systems in the overall mining system to optimize the mining efficiency. We call this the ‘game of capacities’.
Section 1 of this paper describes two ‘traditional dredge mining’ operations. This to illustrate that dredge mining indeed shows many similarities with a deep sea mining operation. Given the lessons from dredge mining, section 2 will discuss design considerations regarding a deep sea mining configuration comprising a Seafloor Mining Tool, Hydraulic Transport System and Surface Support Vessel equipped with a (pre-) processing plant. Revealed will be how the design choices made for individual systems impact other parts of the system. This to substantiate our statement: an integral approach is vital to establish the one optimal overall system.
Asphaltene Management in GOM DW Subsea Development
Authors: Montesi Alberto , Pinnick Robert Andrew , Subramanian Sivakumar , Wang Jianxin , Creek Jefferson Louis 
Published: May 2011

Abstract
The asphaltene management philosophy for Chevron's Blind Faith subsea development has evolved during the project and operations phases to incorporate additional experimental data, modeling results, and field observations. Initially, the project was designed with the philosophy of asphaltene mitigation via downhole injection of dispersants. After start up, operations identified the opportunity to halt asphaltene dispersant injection to wells operating outside of the asphaltene onset pressure (AOP). Based on field data analysis - both pigging returns & temperature sensors drift relative to model predictions - it was established that the asphaltene instability trend, ASIST, (Wang and Buckley, 2001; Buckley et al, 2006; Creek et al, 2009) model provides the most accurate representation of the asphaltene tendencies for the Blind Faith produced fluids, and its predictions are currently used to manage asphaltenes. The chemical cost per barrel for the field was reduced by approximately 25% due to the reduction in asphaltene dispersant consumption. During the second half of 2010, the operating conditions for some of the wells reached the predicted onset of asphaltene precipitation. Drifting of subsea temperature sensor, plugging of level bridles on topsides vessels, and accumulation in strainers occurred as a result, providing insight into the lack of effectiveness of asphaltene dispersants to mitigate these operational issues.

Introduction
The Blind Faith development is composed of four subsea wells from two oil reservoirs in Mississippi Canyon Blocks 695 and 696 in approximately 7,000 ft of water depth. Wells 3 & 4 produce commingled fluids from two zones within the Pink reservoirs. Wells 1 & 2 produce from the Lower Peach reservoir. The wells are commingled into a subsea manifold with two 5 mile production flowlines tied back to a host facility located in Mississippi Canyon Block 650 in 6,500 ft of water depth. The field is jointly owned by Chevron (75% WI), and Anadarko Production Company (25% WI) with Chevron as the operator.
The Blind Faith reservoirs contain high pressure, undersaturated oils (28° to 33° API). From the discovery well, four sands were identified as potential production zones within the Pink and Peach reservoirs. Table 1 summarizes the fluid properties. Additional details and field schematic are available in a previous SPE paper. (Subramanian et al, 2009)
Accelerated Production and Increased Recovery of Remote (Offshore) Mature Fields Through Novel Methods to Design and Operate Surface Production Facilities
Authors: Swanborn Rombout , Egwim Rising Chidiadi 
Published: May 2011

Abstract
Today, the application of advanced (compact) processing technologies is becoming increasingly popular in de??bottlenecking the production of mature fields. Compact processing technologies have shown to provide powerful possibilities to efficiently treat the increasing water production, to prevent flaring of low pressure waste gas or to reduce the backpressure of the processing system. Their application can lead to an increase of reservoir recovery rates, accelerated production, lower CAPEX and OPEX figures and generally to improved HSE conditions. However, these applications have taken place rather component wise than system wise. Till now only a relatively small number of examples exist of processing facilities that fully consist of advanced, compact technologies. Two reasons explain why this has not happened on a larger scale:process robustness (turn down, control characteristics under transient conditions etc.) of current equipment is generally considered insufficient andtechnology characterization and qualification takes place generally under scaled down or non??realistic conditions and leaves considerable uncertainties with respect to performance to be expected under actual operation.
It will be shown in this article how the current drawbacks to a larger scale deployment of this emerging and promising technology have been tackled 1) by initiating the independent development and qualification of a number of processing components to fill the existing technology gaps and 2) by initiating the creation of a large scale high pressure three phase full hydrocarbon flow loop capable to simulate the conditions of most mature fields at actual scale.
To demonstrate the potential of compact processing facilities a project will be described, currently in preparation, that will de??bottleneck remote mature fields in the Niger Delta with miniaturized process systems.
Overcoming Black Sea Ultra Deepwater Drilling Challenges
Authors: Rocha Luiz Alberto Santos , Arduino Edgard Gurgel , Gozzi Danilo Signorini , Duarte Sandra Buzini , Azevedo Gabriel Henrique , Siarez Luis Alfonso Nieto , Bruno Jose Carlos , Pereira Bruno Murta , Pessoa Patricia Oliveira Americo 
Published: May 2011

Abstract
The objective of this paper is to describe the well management process which includes the design methodology and the well execution procedures utilized by Petrobras International to drill its first ultra deepwater well in a remote and challenging area of the Turkish waters in the Black Sea.
Ranked as a well of the highest complexity level, the drilling of this wildcat deepwater well has faced a number of expected hazards such as the presence of shallow gas zones, long abnormally pressurized intervals, low fracture pressure gradient sections, loss circulation zones due to the presence of fractured limestone, great potential for false kicks (breathing formation and ballooning) and the possibility of having gas migration to the riser.
In addition to the risks listed above, the well location, in the middle of a remote area of the Black Sea, has been also considered a great challenge in terms of operational logistics. This came from the fact that Petrobras had to plan all its operations from scratch, including moving a huge semi-submersible drilling rig under the bridges located on the Bosphorus Strait.
In this work it is also presented the Well Classification Methodology developed by Petrobras. Such method takes into account several factors that includes water depth, number of well drilled in the area, the existence of abnormally pressurized formations and a number of other obstacles. The main idea of this procedure is to establish the proper well design robustness and to define operations actions which should be used to mitigate operational problems that could arise.
Despite of all these challenges, the well was executed according to its original plan indicating that the methodology was successfully applied and can be repeated in other wells. A number of lessons learned during the planning and execution phases of this project are also discussed within the scope of this work.

Introduction
The depletion of old oil fields has made operators to seek for new opportunities in areas previously unexplored. The challenges of these new frontiers and the high cost of drilling rigs usually result in very expensive wells. In turn, these high costs may induce some operators to be tempted to seek for a dangerous cost reduction already in the first wells. These cuts lead to underestimated well design whose outcome is often the loss of the well and the reconstruction of another one. Thus, the cost reduction expected at the beginning becomes at the end in a huge and unexpected increase in costs.
How an Innovative Method of using Field Proven Diverless Pipeline Repair Equipment Opened Up New Ways for Connecting New Deepwater Pipelines onto Existing Producing Pipelines
Authors: Keijser Edgar , Povloski Bo 
Published: May 2011

1) ABSTRACT
Over the last decade, the oil and gas industry has expanded rapidly worldwide into deep and ultra deep water. Virtually all deep water field developments are dependent on pipelines.
Failure of a pipeline due to corrosion, defect or an external event can lead to loss of production and, in the worst case, can cause pollution. However, the technology to repair pipelines both in shallow and deepwater in an efficient and cost effective manner has been greatly improved and the equipment and procedures that are presently available can be considered field proven.
The cost of installing export pipelines can have an impact on the economical feasibility of a project. For certain (marginal) fields, the economics may be greatly enhanced by the proximity of existing pipelines and the ability to share and utilize these existing pipelines for the export of the newly discovered gas or oil.
However, connecting new pipelines onto existing pipelines generally implies that the existing pipeline is prepared, during the design, with a connection link to receive the new pipeline connection.
For a specific case, an existing producing pipeline network was available nearby a new oil field discovery that could potentially shorten and significantly reduce the costs of the export pipeline.
However, since the existing nearby pipeline did not have any pre-installed pipeline connection points to receive the new export pipeline, the oil company chose to install, as an industry ‘first’, a connection point in the existing pipeline subsea using equipment and procedures that was previously used only for diverless pipeline repairs.