bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Practical Approach to Multiwell Decommissioning
Authors: Bubulka A. , Bogaerts M. , Diarra R. , Osteen N. 
Published: April 2017

An offshore operator had seven similarly drilled deepwater wells in the Gulf of Mexico that were reaching the end of their productive lifetimes and due to be decommissioned. A consistent and practical solution was sought to abandon the seven wells while meeting the regulatory requirements laid-out by the local compliance entity. Successful implementation would offer a potential solution to similar abandonment requirements globally.
Due to the nature of abandonment work, some assumptions were required during the planning and preliminary cement design phase. Detailed well information would not be available until the rig was able to latch onto the wellhead and assess the well's condition. To address this uncertainty, and allow for flexible design, the base cement slurry for each section was designed with additives exhibiting low sensitivity to certain downhole conditions. These focused on keeping the slurry thickening time stable at a range of temperatures and slurry rheology consistent with surface to downhole conditions.
The operator was successful in abandoning the seven wells as per the regulatory requirements, with 45 cement barriers put into place. Applying similar designs from one well to the next allowed for faster cement design turnaround and improved materials management. Using innovative solutions, the challenges controlling the slurry behavior at varying conditions were overcome. Cement additive concentrations were refined over the course of the project, but the iterative approach meant that fewer changes were needed later in the project due to the increase in operational experience and design data. Contingency cement systems were prepared ahead of, and continuously updated during, the project to address probable risks, adding to the database of slurries that could be referenced for future work and potentially increasing planning efficiency. Developing this standardized process approach to well decommissioning saved an average of 11 days per well, 32% of the time, when comparing the first three and the last three wells.
Using a similar model, a more effective decommissioning plan can be created to conceivably allow for an increase in the scope of future abandonment projects to offset time savings. This process can be tailored to offshore and land wells around the world, especially where similarly behaving cement materials are locally available.
Offshore Construction – Installing the World's Deepest FPSO Development
Authors: Webb Carl M. , Vugt Marco van 
Published: April 2017

Abstract
The Stones project is located in the Walker Ridge (WR) area approximately 200 miles due South of New Orleans in ~9500 feet of water. The host facility is a Floating Production Storage and Offloading (FPSO) vessel with a disconnectable moored turret buoy (BTM) that allows the FPSO to move off site in a hurricane event. Each of the nine moorings are made up of a suction pile – chain – polyester – chain – spring buoy – top chain assembly. These connect to the circumference of the BTM at the keel. The subsea infrastructure, including 2 flow-lines, one gas export pipeline, and two umbilicals, are supported by the BTM. The pipelines and all umbilical fluids, electrics, and fiber are connected or disconnected from the FPSO via dry internal turret connection systems.
This paper provides an overview of the transportation and installation of the moorings, turret buoy.
Key challenges include water depth world record for FPSO moorings, transportation and handling of the world's largest disconnectable buoy, and project execution during an extreme eddy current event.
Lithology and Fluid Facies Identification from Post-Stack Seismic Inversion
Authors: Spikes Kyle T. 
Published: April 2017

Abstract
Use of seismic-amplitude data to indentify lithology and fluid facies typically requires use of pre-stack data, which provides an estimate of shear-wave information. When only post-stack amplitude data are available, reservoir characterization can still be performed although with potential greater uncertainty. The present study uses well data and post-stack seismic amplitudes to estimate volumes of porosity and saturation for gas and oil sands. An advantage associated with the data set used here is that P-impedance discriminates sands and shale. Gas and oil sands, however, overlap in terms of their P-impedances. These sands can be separated stratigraphically. The procedure consists of two primary steps. First is the inversion of post-stack amplitude data for P-impedance, relying on proper preservation of amplitudes. Second is the use of appropriately calibrated rock-physics models, established using well data. Statistical simulations of those models to match target distributions allow for estimating porosity and saturation from the inverted impedances. Results include multiple realizations and most likely volumes of porosity and saturation.
A Revolutionary Hybrid Solution to the Grand Challenge of Developing Deepwater Stranded Gas
Authors: Moore Richard 
Published: April 2017

Many deepwater gas fields remain stranded in the current economic environment. Conventional surface solutions result in large facilities that are heavy and costly. Subsea solutions are challenged when confronted with long distance tie-backs. While the FLNG option initially looked promising, high CAPEX and very high OPEX have limited its potential application, with four potential FLNG projects being cancelled in Australasia in the last two years.
A revolutionary new solution, a proprietary ‘Hybrid Concept’ has emerged to solve this grand challenge of developing deepwater gas fields. It is not surface, not subsea, but the ultimate combination of both, offering fundamentally more efficient and hence lower cost processing.
The concept incorporates several principals that have been overlooked to date, namely:-
Fundamental differences in cost between surface liquids and surface gas processing
There is a key distinction and granularity between the costs for surface processing of liquids and surface processing of gas. Liquids can be processed on the surface relatively efficiently. It is the high pressure surface gas systems that have a disproportionate impact on size, weight and cost of surface facilities.
Fundamental Processing differences for liquids and gas
Cold temperatures are required for gas processing and this is efficiently found near the seabed. In contrast, liquids processing requires heat both to efficiently separate and stabilise the components.
Subsea Dehydration
Dehydration is the core unit operation to allow long distance pipeline transfer by preventing hydrates and corrosion. Dehydration has been almost universally applied to onshore and fixed platform processing facilities, thus allowing dry, single phase pipeline transfer.
Existing subsea gas developments rely on either adding chemicals or heat and insulation to avoid hydrate formation and reduce corrosion. While successful across short to medium distances, across longer distances and in deeper waters these methods prove far less efficient and much more costly.
The Hybrid Concept fully processes the high pressure gas on the seabed in two stages. The first stage includes active cooling and bulk water separation and removal. In the second stage, the gas is processed with liquids removed to achieve full subsea dehydration. All liquids are directed to a simple and compact, low pressure surface unit. This surface unit provides support to the subsea processing, reducing complexity, costs and project risk.
The result is significantly lower development CAPEX and lower OPEX, with a minimum of complexity, giving an acceptable project risk. Importantly all components are proven and require a minimum of technical development. Safety is significantly improved with no high pressure gas on the surface and a significantly reduced permanent offshore workforce required.
The details of this concept, along with its significant advantages are discussed in this paper.
Standardization of FPSO Hull with 2MMbbls Storage Capacity for West Africa
Authors: Jung J. J. , Lee I. H. , Chung B. Y. , Kim S. E. , Kim S. H. 
Published: April 2017

Abstract
Standardization of offshore platforms is refocused to reduce costs and accelerate project delivery times. Some components or modules of offshore platforms are tried to be standardized in industry. There are also applications to use a standard platform itself. This paper describes the standardization of FPSO hull with 2MMbbls storage capacity for West Africa.
The FPSO hull in West Africa is better to be standardized than ones in other sites, for most of new-build FPSOs in the world are in West Africa and many of their storage capacities are 2MMbbls. In design procedures, we focus on the selection of design basis and the design of hull configuration, tank arrangement and midship section. As a result, a standard model of FPSO hull is presented. For the standard model of FPSO hull to be competitive in West Africa, it could satisfy the requirements of this region. The past new-build FPSO projects in West Africa are investigated to premise the design basis such as the environmental conditions, topside weight and module layout, storage capacity, motion criteria, etc.
Systematic procedures for each design items are presented in this paper. Firstly, the generic topside modules and their weight distributions are suggested. Initial hull sizing is carried out in terms of hull weight and motion characteristics. Hull bow and stern shapes are designed to achieve the towing performance for resistance and directional stability. Tank capacity plan, intact/damage stability and rule scantling for midship are checked for the design of hull configuration. The design procedure for hull sizing is automated with an optimization tool which provides Pareto-solutions to designers.
Final standard FPSO hull has less weight and satisfies the general requirements in West Africa. The design procedures in this paper are applicable to early stage of field development and could correspond flexibly to various offshore fields.
Record-Setting AUV Pipeline Inspection in Deepwater West Africa
Authors: Ghis S. , Fischer E. 
Published: April 2017

Abstract
In deepwater environments the inspection of subsea infrastructure (including pipelines, wellheads and anchors) is paramount for assessing "life of field" and for ensuring the integrity of assets subject to geo-environmental constraints. Following the first deepwater development in the late 1990s, the number and length of pipelines has significantly increased, leading to time-consuming and costly conventional Remotely Operated Vehicles (ROV) inspections. Based on these technical and economical constrains, an Autonomous Underwater Vehicle (AUV) based solution, technology routinely used for seabed and sub-seabed geophysical data acquisition, has been considered. This paper presents the application of such methods to deep offshore fields in West Africa.
The availability of new AUV mounted high resolution sensors (Laser, subsea camera) in addition to conventional sensors (Multi Beam Echo Sounder, Side Scan Sonar, Sub Bottom Profiler) has expanded over the past years, providing Operators with a new set of tools for baseline surveys, field monitoring and inspection purposes. Through the deployment and application of these innovative sensors, already developed in the industry but never used for deep water large scale operations, this new approach was an opportunity to fill technological gaps for pipeline inspection using an AUV instead of an ROV. At an altitude of 5 to 7 meters above the seabed facilities, a detailed and accurate inspection survey conducted with subsea laser and high resolution camera was performed. Micro-bathymetry and high-resolution hydrographic data allow detailed mapping of subsea facilities and surrounding seabed as well as a large-scale overview of the developed areas.
Integrating processed data from conventional and new AUV sensors in a Geographical Information System (GIS), creates a new decision-making tool for the life-of-field integrity. It allows the Operator to establish a high resolution baseline of the installation and to identify particular points of interest requiring further detailed investigations. The quality of results far exceeds the standard methods and helps to identify equipments requiring mitigation measures or detailed investigations as requested by pipeline engineers. The final dataset could be used as a subsea engineering reference to conduct repeated AUV acquisitions and to identify/monitor changes over time. Due to its speed and limited maneuverability, AUV could not fully replace conventional ROV inspection. The combination of both methods and technologies offers a large panel of solutions to optimize pipeline inspection surveys.
The development of new sensors specifically adapted to AUV payload leads to considering AUVs not only as a site-investigation tool used for geohazard assessment prior subsea installation but shall nowadays be considered far beyond their original design, allowing a step forward to subsea monitoring and inspection surveys.
Fixed Platforms at Ageing Oil Fields - Feasibility Study for Reuse to Wind Farms
Authors: Barros J. C. , Fernandes G. C. , Silva M. Miguel , Da Silva R. P. , Santos B. 
Published: April 2017

All fixed oil platforms in the Brazilian Northeast are near their design lives presenting low productivity. This scenario will lead to a decision-making process about decommissioning. An alternative use for these platforms could be an interesting option to reduce decommissioning costs and social impact.
The Brazilian Northeast is already known for its great wind power potential. In this way, this region shows an interesting possibility of reuse fixed oil platforms under decommissioning process to generate wind power. Moreover, many of these fixed platforms are near the coast, installed in shallow waters, close to a major metropolis with significant energy demand, which could potentially reduce the cost of energy transmission.
On the wind power operator side, the use of these structures as wind turbine foundation would also reduce the corresponding construction and installation costs. Thus, decommissioning associated with wind turbine installation could be an attractive opportunity for both operators: wind and oil.
The objective of this work is to evaluate the technical feasibility of the reuse of these jacket structures for this new proposal, based on economic information already available.
On a first step, the work will involve developing a case study in a Brazilian scenario, based on a qualitative analysis of existing wind farm data in Brazil and worldwide. The second step will be to gather global market tendencies, which will be used to define the offshore turbine requirements and data to be used in the following step.
Next, the structural capacity of a representative number of jackets will be evaluated considering the wind turbine characteristics defined in the previous steps. A general evaluation will be performed in order to verify the application of the results obtained to all platforms in the field, which will determine the wind farm configuration.
Finally, the Levelised Cost of Electricity (LCOE) will be calculated and compared with worldwide values in order to determine the economic viability of the business.
This work intends to verify if it is possible to use existing Brazilian offshore oil fields, composed by fixed platforms, as offshore wind farms. For this purpose, a basic methodology to evaluate the structural capability of these structures will be established, which could be applied in other brown fields around the world in the same life situation.
Nowadays there are hundreds of ageing platforms/oil fields to be included into decommissioning processes that could be considered as potential Power Wind Farms. The present study could be used as a first approach to permit start a decision-making process, with the adequate region adjustments.
Petro-Physically Driven Quality Control of Dielectric Logging
Authors: Kouchmeshky Babak , Fanini Otto 
Published: April 2017

Dielectric logging can be used to quantify water saturation, water resistivity and textural properties of formation. Application of this log is especially useful in situations where the resistivity of water is unknown or it varies considerably at different depth. This logging is based on the contrast between the dispersive dielectric behavior of dry matrix, hydrocarbon and water as elements present in the rock. As such the real and imaginary parts of dielectric dispersion at various frequencies are used to infer the petro-physical properties of formation. The wide frequency of operation, large dynamic range of response and numerous parameters involved make the interpretation of data challenging especially in the presence of noisy environment.
This paper takes a look at a method to define quality control criteria for dielectric logging. As any other measurements the quality of recorded data should be judged based on the acceptable range of variations for inferred parameters as well as related confidence levels. These would lead to an acceptable noise level in the recorded data.
Having access to the aforementioned quality control criteria can be very useful for example when the tool response is measured in a predetermined environment and it is compared with expected values or when the response of symmetrically positioned transmitters are compared assuming that tool is facing a homogeneous medium.
In this paper a petro-physically driven quality control method is presented for dielectric logging. It uses a probabilistic Bayesian inference method in obtaining the required accuracy level for dielectric tool response. The criterion is defined in a way that guarantees the inverted petro-physical parameters will be within a predefined range around the actual values with a required confidence level. The application of method is shown through few examples.
ER: Are We Really Keeping People Safe?
Authors: Edwards Richard , Skiba Albert 
Published: April 2017

Abstract
Over the last 40 years there have been a number of high profile disasters in the global oil and gas industry that have left a permanent scar on the sector's psyche.
While the US oil and gas industry has been vigilant in developing programs to improve the safety of the drilling and completion process, it has yet to completely embrace the International Offshore Emergency Response (ER) Framework that is widely used by other oil and gas producing regions around the world for handling major emergencies.
It is absolutely right that industry works as one to ensure all risks are identified but with recent industry studies suggesting up to 80% of accidents in the offshore sector are the result of human error – and an acceptance that it is impossible to entirely eliminate human fallibility –are we gambling with people's lives by not giving the same commitment towards ensuring workers know what to do in the event of an emergency?
The ER Framework was created to ensure all personnel travelling or working offshore are trained to respond appropriately in the event of an emergency. Underpinned by competency based training with specific learning outcomes, it provides the safeguard that all personnel regardless of employer, discipline or experience, know what to do and when to do it.
This presentation will look at how the framework was developed by the oil and gas industry for the oil and gas industry, how the lessons learned in other hydrocarbon hubs around the world helped shape them and the perceived barriers that exist in the US.
It will consider the interconnection between standards and examine how basic training like H2S or Tropical Helicopter Underwater Escape Training are essential for all workers travelling offshore; and explore the impact of the gap between operators and contractors in the training and management of specialty roles such as helicopter landing officer in effectively controlling an emergency.
It will also consider how advances in technology and changing environmental factors are influencing the continual review and development of industry standards.
The standards are driven by the needs of employers to help create a safe and competent workforce. They help major employers and SME's around the world prepare for, respond to and maintain control throughout the development or escalation of an emergency situation.
The presentation will conclude that while significant strides have been taken, for a country which has led the world in so many ways we lag far behind others in the use of common industry standards.
The question every oil and gas leader must ask themselves is: If the worst happens, don't you want to know that you have prepared every one of your people to the highest level you possibly could?
Design and Installation Monitoring Experience of Large Diameter Monopiles for Offshore Wind Farm in Highly Variable North Sea Soil Conditions
Authors: Thumann V. M. , Yetginer-Tjelta T. , Van Foeken R. J. 
Published: April 2017

Abstract
This paper elaborates on (main) conclusions from pile advanced monitoring data, regarding the quality of the monitoring data under the specific circumstances, the modelling and validation of pile driving resistance in subject extreme soil conditions, and the effectiveness of pile design features such as internal- and external driving shoe. Results are expected to be of added value to near-future offshore wind farm developments in areas having soil conditions similar to this area of the North Sea.
Statoil on behalf of partners Masdar and Statkraft are developing a large offshore wind farm (OWF) in the central part of the North Sea. The OWF consists of 67 wind turbines and one transformer substation platform. The wind turbines have been installed on monopiles foundations, whereas the substation has been founded on suction piles. Total area of the site comprises around 50 square km. The monopile foundations dimensions are typically 6.3m diameter at the pile top and 7.0m, 7.2m and 7.4m diameter at the embedded section of the pile, length varies between 53m and 72m. Mass of largest monopile is around 1000 metric ton. Seaway Heavy Lifting has been main contractor for installation of the monopiles. The monopiles have been installed by means of hydraulic impact hammers with rated energy up to 3000 kJ. The hammers were equipped with a 6.5m diameter pile sleeve as to suit the top of the monopile. Total weight of the hammer assembly was around 580 metric ton.
During design phase as well as during preparation of the offshore campaign, it became clear that the soil conditions would have a major impact on the project. This was due to presence of a wide variety of soil types and strength that existed within the OWF site. Site investigation had revealed presence of very weak chalk layers with potential risk of dropfalls during installation, but also high strength clay layers and rock-type soils were encountered with potential risk of pile driving refusal conditions. To mitigate the risks related to installation of the monopiles, a number of measures were taken. These included good regular engineering and evaluation of field experience from nearby installed OWF, but also a pile driving test-program on application of internal- and external driving shoe to reduce the pile driving soil resistance was included.
It was decided to use advanced pile monitoring during pile driving operation for a selection of monopiles for confirmation of engineering design. Monitoring was performed by subcontractor GeoDrive. Due to limitations originating from pile design and from offshore operations, the monitoring sensors had to be placed on the inside of the monopile. This is not common practice since experience has revealed some uncertainty regarding reliability of the monitoring data under these circumstances, but was considered feasible in this case.