bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges of Flow Assurance in the Roncador Field
Authors: Noe Gustavo , Nascimento Robson Ferreira , Silva Sidnei Guerreiro , Rodrigues Francisco Ferreira 
Published: October 2008

Abstract
Since 1987, with the beginning of the petroleum exploitation in Brazil in water depths deeper than 200 m, flow assurance has played an important role in the production of development projects. Especially in deep and ultra deep water production systems, waxes and hydrates can significantly impact the economics of the development project.
Wax deposition in production flowlines invariable lead to production losses, and cleaning operations, such as pigging and/ or chemical removal has to be properly studied and carried out in order to minimize losses and maximize profits.
This paper describes the main flow assurance problems and solutions carried out by the production of a deep water and long tie back system, the FPSO-Brasil, installed in a water depth of 1290 m, Roncador Field, since December 2002, and the prediction, prevention and remediation design criteria applied to the two new development Modules, which started production in the end of 2007. Among the problems and solutions that are described: FPSO-Brasil flow assurance production losses, practices used to mitigate flow assurance problems, use of lessons learned on the design and operation of the next Modules, hydrate and wax design criteria, and a study of an electrically heated pipe-in-pipe (EHPIP) system that combines a high passive insulation and active heating during shutdown and startup.

Introduction
The Roncador Field is located in the north area of the Campos Basin, Brazil, in an area of 111 km2 and in water depths ranging from 1500 m to 1900 m. Because of its large extension, high volume of oil in place, different fluid properties and the limited processing capacity of the production units, its development will occur in Modules: Module 1A Phase 1 (FPSO-Brasil) and 2 (P-52), and Modules 2 (P-54), 3 (P-55) and 4 (P-62).
Since December 2002 the south area of Module 1A, Phase 1, has been producing by the FPSO-Brasil. The oil presents a strong tendency to wax deposition and gas hydrate blockage. The long flowlines (11-16 km), the low temperatures and high pressures have demanded regular pigging to remove organic deposits and cases of hydrate blockages sometimes required workover operations. The flow monitoring has been allowed to actively prevent and correct in situations of hydrate and wax blockages and in the optimization of the pigging frequency. In addition, paraffin inhibitor effectiveness has been evaluated.
The Modules 1A Phase 2 and Module 2 are less susceptible to flow assurance problems, since the flowline lengths are shorter and the insulation is enough to ensure the project requirements. Operation procedures are used mainly to avoid hydrate plugging during shutdown and startup.
The Modules 3 and 4 will not be mentioned in this work because they are still in the development phase.
Extraction of Methane Hydrate Concentrated Zone for Resource Assessment in the Eastern Nankai Trough, Japan
Authors: Saeki Tatsuo , Fujii Tetsuya , Inamori Takao , Kobayashi Toshiaki , Hayashi Masao , Nagakubo Sadao , Takano Osamu 
Published: October 2008

Abstract
Aiming commercialization of methane hydrate development, the Research Consortium for Methane Hydrate Resources in Japan (MH21) has been executing geological and geophysical surveys around the eastern Nankai Trough since 2001 as a national project.
Interpretation and analysis studies based on 2D/3D reflection seismic surveys, multi-wells drilling campaign and other geological surveys revealed existences of methane hydrate concentrated zones, of which reservoirs were composed of turbidite sand layers. In the view of resource explorations, methane hydrate concentrated zones are more attractive than other methane hydrate bearing zones because they can reserve much amount of methane hydrate locally.
We developed an optimal interpretation workflow for delineation of methane hydrate concentrated zones. The workflow includes evaluation and integration of following four indicators:BSR,Turbidite sequnece,Strong seismic reflector andrelatively higher interval velocity.
It enabled in the eastern Nankai Trough to extract more than 10 methane hydrate concentrated zones and evaluate their rock volume successfully.
Geohazard Assessment and Avoidance on the GAZA Marine Subsea Development
Authors: Willis Neil , Parker Eric J. , Johnson William 
Published: October 2008

Abstract
In November 2006, a geophysical and geotechnical survey was performed in the Eastern Mediterranean as part of the FEED for the proposed GAZA Marine Subsea Development. A number of deepwater landslides and possible fault hazards were detected. This paper describes the findings of the survey, the possible impact on the development, the detailed assessment of the various features, and the strategy for achieving a stable route for the subsea pipeline.
Seabed and sub-bottom data are interpreted for the region, identifying the age and origins of the apparent geohazards. The integration of the high-resolution geophysical survey with 3D exploration seismic is a key aspect to successful geohazard assessment. State-of-the-art techniques are described for visualization of seabed topography and pipeline routing.
Seabed faulting in the area is found to be largely due to salt tectonics; the structures are not deep rooted and are not considered seismogenic. Movements on the faults are expected to be slow creep that would not affect the pipeline. Large slope failure features are also present in the field and have infrequently, but persistently formed over the last 5 million years. Adequate setback distances from the scarps were used to limit the hazard.
Fast analysis of the survey data enabled an alternative pipeline corridor to be identified before the survey vessel was demobilised, enabling further data gathering to confirm the selection. This route was 15km shorter than the route around the apparent geohazards, and the saving on pipeline and umbilical costs was considerable.

Introduction
In 2006 INTEC (UK) executed the FEED study for the GAZA Marine subsea development in the Eastern Mediterranean. The development was included 4 subsea wells in approximately 650m water depth, manifolded to a single 16?? export pipeline to shore. The location of the onshore processing facility was not defined, with export options to Israel and to Egypt. The route described in this paper relates primarily to an option to land the export pipeline in Ashquelon in Israel. At the time of writing, this development is on hold, with no clear definition of the export route. No commercial or political inference should be taken from the contents of this paper.
Challenges to Delivering Tomorrow's Energy - Achieving a Balance Between Energy Security and Climate Security
Authors: Oglesby Ann M. , Fryklund Bob , Huang Shawn S. 
Published: October 2008

Abstract
This OTC manuscript is intended to introduce a panel discussion, " Challenges to Delivering Tomorrow's Energy - Achieving a Balance between Energy Security and Climate Security,?? scheduled for Tuesday morning, May 6th, 2008. At the time of publication of this manuscript, the planned participants of this discussion panel are:The Moderators:Bob Fryklund, Vice President, IHS EnergyAnn Oglesby, Manager of Climate Change and Sustainable Development, ConocoPhillipsThe Panelists:Fatih Birol, Chief Economist, International Energy AgencyJaleel Al Khalifa, SPE President and Saudi Aramco ManagerDavid Hobbs, Vice President and Managing Director of Global Research, CERAAmy Jaffe, Fellow, Baker InstituteKevin Leahy, Managing Director, Climate Policy, Duke EnergyRandall B. Luthi, Director of Minerals Management Service, U.S. Department of the InteriorKate Hampton, Head of Policy, Climate Change Capital
The Organizers of this panel include Bob Fryklund, Ann Oglesby, and Shawn Huang (who is serving as AIChE/OTC Subcommittee Vice-Chair and a member of OTC Programs Committee.)

Introduction
The current energy security can be characterized by expanding global connections, growing role of non-traditional fuels, and new paths to regulatory reform. Amid a matured global oil market, a global gas market is emerging through trading of liquefied natural gas cargos and through trans-national natural gas pipelines. Energy security and greenhouse gas emission reduction targets are driving the use of non-traditional fuels around the globe: biofuels, solar, wind, hydro, nuclear, and unconventional gas. The regulatory reform focuses not only on energy security and the need to reduce greenhouse gas emissions in energy consuming countries, but also on easing the tension surrounding sharing the wealth generated by oil and gas production in energy producing countries. 1
The U.S. Congress is currently considering further energy policy legislation. As debate around energy policy continues, solutions for reducing the risk of climate change are commanding increasing attention in Congress and in many states. At the federal level, lawmakers have said that they will pass an energy policy act and then a climate change bill. This sequential approach presents an obvious concern since energy policy and climate change response are difficult to consider separately. 2
Given the current landscape of energy security and climate change issues, what are the challenges to delivering tomorrow's energy? Will the prices of oil and gas continue to rise till unconventional energy sources can play a significant role in the market?
Effects of Startup and Shutdown of HPHT Wells on Wellbore Hydraulic Control Line Design
Authors: Zhao Chuntian , Notz Phillip Kent 
Published: October 2008

Abstract
The operations of a High-Pressure High-Temperature (HPHT) well may expose the hydraulic control line (HCL) in the wellbore annulus to significant pressure and temperature changes, which can cause severe pressure differential across the wall of the HCL. To prevent the associated control-line failure (burst or collapse) and high repair cost, the maximum pressure differential across the wall of hydraulic line needs to be determined at the design stage for the worst scenario, including the situation when normal operation cannot be followed. For example, the control valve of the HCL fails to open during well operation. The wellbore condition-change induced HCL failure may occur in both production and water-injection wells.
This paper provides an approach to evaluate the effects of startup and shutdown operation of a HPHT well on the design of a wellbore HCL. Note that the pressure change across the wall of a control line is the result of many coupled factors, for instance,pressure and temperature in the wellbore annulus, well profile and constraints on the HCL;compressibility of fluid in HCL;thermal expansion of the HCL;related stress-strain variation (or elasticity) of the HCL.
The proposed approach has considered the above factors. The results indicate that the HCL failure could occur during a HPHT well operation if the control line is not correctly designed or properly operated. Suggestions are provided to improve the HCL design to avoid the possible failure.

Introduction
The HCL considered in this paper is a small diameter tube in the wellbore annulus used to deliver hydraulic power for adjusting the downhole sliding sleeves to a reservoir zone. This type of control lines are applied in both production and water injection wells.
If the hydraulic fluid in the control lines is isolated by closed valves, the wellbore temperature change combined with resultant annulus pressure change could cause severe pressure differential across the wall of a HCL, leading to over-pressure (burst or collapse) of the control lines. So far, the importance of the HCL design has not been emphasized as much as other technology gaps in the HPHT field development that is moving toward to reservoirs of 20 to 30 ksi and 400 to 500°F (Maldondao, 2006). The purpose of this study is to determine if there is a safety concern in the design of a HCL in a HPHT wellbore, and if so, to aid in the design of a reliable HCL.
A Systematic Appraisal of Thrulife Integrity Management and Life Extension of Deepwater Subsea Systems
Authors: Saunders Chris , O&apos;Brien Patrick , Dines Brian 
Published: October 2008

Abstract
Based on practical / field experience and lessons learnt in providing integrity management to a number of worldwide operators, the paper will present and show through examples the common issues experienced in providing subsea integrity management (with particular reference to deepwater applications).
The paper will present examples relating to systematic / procedural issues and recommend practical solutions that an operator may adopt to improve subsea integrity management. This will include discussion on data collection, analysis, storage and reporting.
Emerging new technologies being developed in the industry will also be discussed relating to monitoring and inspection techniques. In particular, this will concentrate on the benefit that can be gained from early adoption in terms of the value the generated data can provide to increased system knowledge and reduced operational costs.
The complex riser systems used in deepwater applications are an area under constant development and several JIP's are coming to conclusion. The SCRIM (Steel Catenary Riser Integrity Management JIP (including Hybrid towers)) and Flexible Pipe Technology JIP are two such projects which the paper will use to highlight current industry thinking.
Favourable economic conditions also mean that operators are looking at the potential to push the field life of some assets past the original design requirements. Without sufficient data gathered during service, determining fitness for purpose in these cases can be difficult. The paper will close by presenting typical data requirements to determine if life extension is feasible.
With subsea projects being developed in increasingly deeper and more demanding locations, the challenge associated with the inspection, repair and ongoing integrity assessment of these assets is getting harder. As a result it is more important than ever for the subsea industry to re-evaluate integrity management if safety and operability are to be ensured without escalating costs.

Introduction
The process of integrity management of subsea systems has been adopted by the industry for a number years where there has been a local legislative or corporate requirement to do so. Clearly some geographical regions are further advanced with this process and as a result deal with integrity in a more comprehensive style but, the remaining developing regions are quickly playing catchup and identifying the relevant worldwide best practices to adopt. However, those regions where integrity management is well established are not standing still and significant investment is being made in developing and improving the process, technology and systems used.
Trend Braking Completion/intervention Methods
Authors: Erlandsen Sigurd Myge 
Published: October 2008

Abstract
An important focus area in StatoilHydro's IOR strategy is ‘efficient drainage of reservoirs’. As the oil industry struggles to improve ultimate recovery and to make marginal projects economical, wells must provide cost-effective means to gather reservoir information and produce them efficiently. This paper describes the challenges associated with uneven inflow into the well bore causing increasing water cut and/or gas-oil-ratio with corresponding decling oil rate.
As well construction becomes more and more advanced it is increasingly important to ensure optimal inflow along the entire reservoir section of the well, whether it is a long horizontal section or a multi lateral well. For some applications mechanical sliding sleeves can be an effective way of shutting off poor performing zones. Fixed inflow control devices (ICDs) has also proven to be a valuable way of equalizing inflow for maximizing oil production from thin oil rims. Remotely operated ICV's enables choking or shutting-off zones from surface if they experience high GOR or water cut. Different applications have different fit for purpose solutions.
Autonomous valves represents the next step for inflow control as it enables choking of zones with excessive water cut or GOR without any use of control cables. In order to fully utilize advanced well construction, it is also cruisial to ensure adequate reservoir monitoring. The paper also describes this by means of fibre optics.

Introduction
In most oil fields with declining oil production it is caused by uneven inflow along the wellbore giving early gas and/or water break through. Inflow control by mechanical sliding sleeves, fixed inflow control devices (ICDs) and remotely operated ICVs (smart completions) have given valuable increased production due to limitation of unwanted production of excessive gas or water. Future challenge will be to find cost effective completions for the advanced well architecture that is robust enough.

Mechanical sliding sleeves
Mechanical sliding sleeves have been used for decades for selective zonal shut-off of unwanted water production or excessive GOR. It has proven to be a robust solution, but there are some limitations. In addition to the economic aspect of well intervention to shut or open a sleeve, it is limited to open or shut and has does not enable choking.
Investigation of Riser Seafloor Interaction Using Explicit Finite Element Methods
Authors: Clukey Edward , Jacob Paul , Sharma Partha Pratim 
Published: October 2008

Abstract
The seabed response due to riser loading and the trench formation phenomenon are of great significance for safe and economic riser design. This paper summarizes an investigation of seabed response and trenching due to riser loading using explicit finite element methods and Arbitrary/Lagrangian and Eulerian meshing schemes. Results are compared to laboratory tests in order to understand the impact of active and passive failure mechanisms in the soil with vertical travel of the riser. The impact of strength degradation is discussed in the conclusion of the paper.

Introduction
Seabed response in the touch down zone is known to have a significant impact on the fatigue life of steel catenary riser systems. Current industry practice is to characterize the seabed response using either linear/nonlinear soil springs or rigid surfaces. This is primarily due to the requirements of existing software tools for riser design. This approach of representing the integrated response ignores the complex individual mechanisms that comprise the riser-soil interaction problem.
In the global analysis of riser systems, it is also common to represent the seabed as a flat surface. However, ROV observations of existing risers and mooring lines have shown the formation of trenches in touchdown region. In some cases, trenches were formed only a few months after installation. It is known that with the right environmental conditions a riser resting on relatively weak soil may dig a trench in the seabed due to repeated motion. The trench formation will impact fatigue damage accumulation and, depending on the system could result in higher top end loads that impact the host system performance.
This paper discusses the use of explicit finite element methods to simulate riser seafloor interaction, including the interaction with the surrounding water, a key factor in the trench formation process. An Eulerian solution (fixed grid) procedure is used to adequately capture gross deformation in the soil due to riser loading. The Eulerian finite element formulation also facilitates multi-material interaction between the riser cross section, the soil mass and the surrounding water. Simulation results were compared to test data for the interaction of planar pipe sections and kaolinite material. Results under investigation were the global load deflection curves, when the riser cross section was subjected to a single vertical displacement cycle comprising of a downstroke followed by an upstroke and finally ending with a downstroke. The impact of soil strength degradation is discussed in the conclusion section of this paper but was not investigated numerically in this study.
On the Performance of Class 2 and Class 3 Hydrate Deposits During Co-Production With Conventional Gas
Authors: Moridis George J. , Reagan Mathew T. , Zhang Keni 
Published: October 2008

Abstract
Recent numerical studies have provided strong indications that it is possible to produce large volumes of gas from natural hydrate deposits at high rates (in excess of 10 MMSCFD) for long times by depressurization-induced dissociation of hydrates. Of the various factors that can adversely affect the production potential of hydrates, low temperatures have one of the strongest negative impact. These can be caused by low initial temperatures, increasing stability of the hydrate (as defined by the deviation between the temperature of the deposit and the equilibrium temperature at the reservoir pressure), and by an advanced stage of dissociation (a strongly endothermic reaction) when substantial amounts of hydrates remain. The reasons for the production decline include a reduction in the rate of the hydrate dissociation at lower temperatures and the evolution of flow restrictions in the vicinity of the well caused by the formation of hydrate and/or ice in the vicinity of the wellbore. The latter is caused by continuous cooling, and is the reason why large amounts of gas that may have been released in the reservoir in the course of earlier dissociation cannot be easily recovered.
We investigated the possibility of alleviating the problem of low production at low temperatures in Class 2 and Class 3 deposits by means of co-production with gas from conventional reservoirs. Large-scale numerical simulations involving injection-production multi-well systems indicate that, by routing some of the pressurized hot conventional gas through Class 2 hydrate reservoirs at rates that do not exceed 50% of the total production rate, it is possible to achieve a significant increase in hydrate dissociation and gas production. This occurs mainly because of the enhanced relative permeability of the gas phase and the increased effective permeability of the hydrate interval, which facilitates gas flow and further dissociation. The thermal effect on dissociation appears to be limited. Co-production appears to confer no benefits to the performance of Class 3 deposits when the production well is kept at a constant pressure.