bluuebunny/crossref_metadata_2025 huggingface dataset:
Extreme Wave Effects on Deepwater Floating Structures
Authors: Buchner Bas , Bunnik Tim
Published: October 2008

Extreme waves can lead to damage to floating offshore structures as a result of airgap problems, greenwater on the deck or slamming to the hull. As the physics of these problems are different, there is no single way of identifying and characterizing extreme waves.

As part of the investigations into the effect of extreme waves on deepwater floating structures, this paper focuses on the challenges of the numerical prediction of platform response due to extreme waves. This will be done by using an improved Volume Of Fluid (iVOF) method. Two case studies are presented, which both required specific extensions of the methodology. First green water simulations on a FPSO are discussed, requiring the coupling of a linear diffraction code to the iVOF method as part of a domain decomposition. Second the dynamic response of a TLP to an extreme wave is studied, requiring the integrated analysis of the wave loading and platform response.

Introduction

Hurricanes Ivan, Katrina and Rita in the Gulf of Mexico showed the importance of extreme waves for all types of offshore structures [1-5]. Extreme waves can lead to damage to floating offshore structures as a result of airgap problems, greenwater on the deck or slamming to the hull. As the physics of these problems are different, there is no single way of identifying and characterizing extreme waves:

- For airgap problems, the crest ampltidue of the waves is the most important aspect. Therefore, it is important to know the ratio Ac/Hs between Crest Amplitude (Ac) and Significant wave height (Hs). In [6] the detailed analysis of an observed extreme wave in a model basin is described. It was shown that even in a wave with moderate steepness (Hs=11.9 m, Tp=15.3 s), generated with a random phase model, extreme wave crests can be observed. The measured wave had a Ac/Hs ratio of 1.59. As a pilot study into the understanding of the occurrence of this type of extreme waves, [6] describes the spatial development of this wave in the basin, see Figure 1.

Figure 1: Spatial development of a wave in a model basin (from [6]) (Available in full paper)

It should be noted ofcourse that even for fixed platforms the crest amplitude is not the only factor, the structure itself can clearly enhance the local wave elevation [7].

- For floating structures such as TLPs, Semis and Spars the wave loading and response is even more complex, as was shown in recent tests on the Snorre TLP [8]. The dynamic response of the platform to the wave impact can be the main factor in the survivability of the platform.

Figure 2: Airgap tests on the Snorre TLP (from [8]) (available in full paper)

In [8] the important observation was made that extreme wave and airgap problems belong to the group of (what was called) ‘badly behaved’ problems. A ‘badly behaved’ problem is a problem with a step or discontinuity in the response. For a fixed platform or TLP it can for instance occur that the deck is not hit in the 100 year wave as the maximum wave crest just passes below the deck.
Integrated Approach to Deep Water North Sea Drilling
Authors: Wilson G.J.
Published: October 2008

Ever increasing costs associated with drilling operations in a hostile marine environment dictate that the ratio of actual drilling time to total time expended be increased to the greatest possible limit consistent with safety. This paper discusses equipment, materials, procedures, and personnel required to fully utilize capabilities of new generation semisubmersible rigs in achieving this goal during year-round drilling operations in deeper water in adverse environments. Criteria established for selecting basic equipment and innovative items are outlined. Procedures and auxiliary components needed to assure compatibility of subsystems and the effect of new concepts on primary drilling objectives are reviewed. Responses to the problems of resupply and support, measures conceived to promote timely and advantageous use of specific skills of all personnel and benefits resulting from shallow marine studies are presented.

INTRODUCTION

High cost of deep water drilling in a hostile environment demands the greatest possible effectiveness of all equipment and personnel. Daily costs for operating and supporting one of the new semisubmersible rigs total about $50,000. Costs are not expected to decline and will no doubt exhibit further increases as deeper water in the more open reaches of the sea is challenged. Employing inadequate equipment with an apparent savings in daily rental cost has long been recognized as false economy. The operator therefore has little recourse other than to accept greater costs. But conditions in higher latitudes of the North Sea, in the Gulf of Alaska, off Canada and in other offshore areas around the world are such that the best drilling rigs and supporting units will continue to be subjected to long periods of rough weather during which little, if any, productive work can be performed. Since all costs are ultimately borne by the operator, the operator has a great incentive to accomplish more productive work in less time than here to fore but without incurring greater per well costs.

Two complementary approaches can be made to obtaining more productive work which, from the operator's viewpoint, can be defined as the actions directly connected with drilling hole and evaluating horizons penetrated by the bit. First, the ratio of time spent in productive work to total rig time can be increased to the greatest limit consistent with safety. Second, the most optimum procedures can be formulated and implemented for all phases of the operation. The first approach requires investment in equipment to supplement the minimum with which the drilling goal could be reached if total time and total costs were of little importance. Even though most drilling contractors provide somewhat more than minimum equipment, in the context of this paper, basic equipment in the context of this paper, basic equipment refers to the minimum.
Marine CNG: Technically Sound, Commercially Viable, and Imminent
Authors: Young C. , Eng P.
Published: October 2008

One of the newest frontiers in the upstream energy sector is marine compressed natural gas (CNG), and the economic challenge of how to safely transport and market marine CNG on a regional or international basis. Stakeholders are working to meet these challenges head-on and are creating solutions for all aspects of development, transportation and delivery of a reliable CNG product to varied customers.

Traditional concerns surrounding technical feasibility have given way to economic considerations on a project by project basis, with increased focus on the niche capabilities that marine CNG fulfills. Proponents have succeeded in overcoming the technical challenges and have attained regulatory approvals for their designs and are in a race to be the first successful application of this technology.

The Centre For Marine CNG Inc. has been tracking the progress of all the proponents, while advocating for the technology as a whole. While research continues on the technical aspects of CNG, the gas owner/operators have recognized that the first project is imminent and are following the technology appropriately.

This paper serves to provide an industry update, describing the niche that CNG fills in comparison to LNG or other natural gas monetization strategies, identification of thetechnology proponents and the relevant regulatory approvals, as well as some basic economic models to help validate the viability of marine CNG.

Introduction

From the Oil & Gas industry perspective, one of the obstacles to a stranded gas development is that marine CNG, as a monetization strategy, is not yet in commercial operation anywhere in the world. Many owners worldwide have struggled with how to monetize their gas reserves when the conventional options of a pipeline or LNG development do not fit the characteristics of their reseroirs.

In general terms, marine CNG differs from LNG in that the natural gas is compressed, rather than liquefied for transport. Depending on the proponent, the gas is transported in a range of 1500 to 4000 psi to achieve energy densities of approximately 1/3 of their liquefied counterpart of LNG. The gas is stored in pressure vessels aboard a CNG ship that will then transport the gas to market. Depending on distance to market and the demands for non-interruptiple supply, multiple ships would be required to maintain "flow". One could consider the CNG solution comparable to a floating pipeline, with much less infrastructure required for exploitation of the natural gas reserve. Loading and unloading requirements are comparable to and adaptable from both LNG and oil transfer systems, while the transport vessel can range from a small volume barge to a large capacity LNG-sized vessel.

Given the capability of marine CNG transport as amonetization strategy, one must ask why this method has not yet been implemented. The first and most obvious answer is the hesitation of any owner to be the first to employ a new and unproven technology on a large scale development project.
A New Offshore Platform and Drilling Concept for Reduced Costs
Authors: Sybert Jack H.
Published: October 2008

A new concept has been developed and used to reduce cost of offshore oil and gas drilling platforms. Six dually completed wells were drilled from a platform in the Gulf of Mexico, using two 48-in. diameter piling as guidesthree in each pile on a spacing of 23 in. The conventional conductor guides in the platform were eliminated, reducing the design wave load, the steel required and the cost. New drilling equipment, techniques, and wellhead equipment were developed and are described. Cost comparisons are presented. Plans for expansion of the concept to a 12-well structure are described.

INTRODUCTION

Offshore platforms represent some of the world's most expensive real estate. Designers are continually trying to reduce this cost, but face higher costs with increasing water depths, material and labor costs, and regulatory action. A new concept for a platform and drilling operation has been developed, and significant saving may be realized from its use.

The cost reduction is achieved by drilling through the legs of the platform. In itself, this concept is not new because if has been used in platforms in Cook Inlet and off the U. S. west coast. In those platforms, large- diameter columns (diameters approximately 16 ft) contained wells drilled on spacings as close as 5 ft on centers. These wells were drilled through individual guides driven or drilled to the desired depth below the mudline. The new concept presented here is the close spacing of the wells and the absence of the individual guides for each well.

TYPICAL MULTIWELL PLATFORMS

Multiwell platforms usually have six or more pilings for support. A typical configuration for a 12-well, eight-pile platform is shown in Fig. 1. The deck section is normally trussed and provides two levels for producing and drilling operations. The wells are located in the inside bay and are drilled through 24-in.-diameter conductor pipes that are driven into the bottom and supported by the platform.

MAIN PASS 133-A PLATFORM

The Main Pass 133-A platform is located 48 miles east northeast of Venice, La., in the Gulf of Mexico. The water depth is 180 ft. It is a four-pile platform (Fig. 2) that has seven dually-completed wells. The jacket was placed over one well that was an on-bottom, suspended well drilled from a mobile drill barge. The remaining six wells were drilled from the platform.

The deck section was built with a grid of 12-ft high plate girders that are framed intercoastally. Nominal dimensions are 117 × 75 ft. The area around each well cluster is covered with floor plate, but the remainder is left without permanent decking during the drilling phase. Temporary walkways provide the needed accesses. The advantage of this arrangement is the opportunity to fabricate production facilities into units that provide decking and can be placed on the structure after drilling operations are completed.
First Jack-Up Production Platform In North Sea
Authors: Cheng Alymer P. , Keleher Jerry F.
Published: October 2008

This paper describes the platform design engineering aspects of Amoco's jack-up gas production platform which was installed in August, 1972. It is the first jack-up production platform installed in the North Sea.

The main advantage of using the jack-up platform as compared with the conventional template-type platform is that all production, storage, and living facilities can be installed, tested, and checked out in the fabrication yard prior to leaving for installation. As a result, considerable expensive offshore work is avoided, and more important, much less time is required to commission the production facilities and begin operation.

INTRODUCTION

The Oil Industry is constantly searching for new methods and systems to reduce the high cost of offshore installations. Particular interest is being shown in producing facilities required to be located offshore. These installations can vary in size from a single separator to a bulky, highly instrumented gas dehydration complex. The first step toward economy was the "skid mounted" unit which combined a principal unit with pumps, meters and instrumentation installed and possibly tested on a set of skids designed for lifting into place on the offshore platform. Later the deck sections were sectionalized. The equipment was installed integrally with the deck section pieces and then finally assembled and tested offshore. Still later the idea of "production packages" (more commonly referred to now as modules) came into use. For the larger facilities and deep water locations this method appears to be the most popular at the present time. To date, this arrangement appears to be planned for all deep water North Sea installations. For this type operation the equipment is installed in a series of structural steel boxes. The boxes are fabricated in the yard in the exact position they will occupy in their final location offshore to insure a final, correct inter-connection. The entire system can then be tested as a unit in the yard. Once installed offshore only a minimum amount of final testing is required.

One type of permanent installation that has seen limited use is the "jack-up" barge. Some use has been made in the Gulf of Mexico, but principally for storage. One such installation for large separator units is known by the writers to be in use in the Middle East.

Amoco, having used the three previous mentioned methods in the British North Sea, investigated the use of a jack-up barge, in an effort to further reduce offshore connection work and testing. The results of the investigation showed this method feasible and economical up to approximately 100 ft. water depth. The decision was made to use the "jack-up" barge concept on a gas dehydration facility to be installed in a 75 ft. water depth location in the Leman Field, British North Sea.
Installation Challenges With Lifting and Pull-in of the 20" SCR
Authors: Bouwman John
Published: October 2008

During the 1st half of 2007, Heerema Marine Contractors will install the 20 inch Export SCR to the Independence Hub Facility, using Deepwater Construction Vessel Balder (figure 1).

This 20 inch Export gas pipeline will be the deepest export pipeline installed to date and will be installed as part of the installation program of the Independence Hub Facility and SCRs.

The offshore installation of the 20 inch Export SCR requires utilization of equipment to its maximum. Technical challenges involved are among others the pick-up of the SCR that has been pre-laid on top of four SCRs (2x8-inch, 2x10-inch), transfer of SCR from A&R Winch System to the Balder crane and reduction of loads on the SCR head during pull-in. This paper describes the most important issues of this SCR installation project, including methodologies specifically developed to deal with the technical challenges of this project.

Introduction

On July 15th 2004, Enterprise Field Services, LLC awarded the contract for the installation of the floating production facility, Independence Hub, to Heerema Marine Contractors Nederland B.V (HMC). The Independence Hub Facility (IHUB) will be installed in Mississippi Canyon Block 920, in 8,000 ft of waterdepth.

The Independence Trail Pipeline is the Export Gas Pipeline for the Independence Hub Facility. This pipeline system will initiate with the 20 inch diameter Export Steel Catenary Riser (SCR) on the IHUB.

Part of HMC's scope is the installation of eight SCRs to the IHUB. Five 8 inch SCRs, two 10 inch SCRs and the 20 inch Export SCR. All pipelines, including SCRs have been constructed and temporarily stored, pre-laid, on the seabed (figure 2). Each SCR consists of steel pipe with an integrated flexjoint and a SCR head on the pipe end. Pre-installed on the SCRs are strakes and fairings to avoid vortex induced vibrations, a flex joint protective cover, flex tool, pipe flooding valves, hang-off collar and a pick-up rigging arrangement including buoy for installation purposes. After installation of the IHUB, the SCRs will be recovered and connected to the IHUB.

The SCR installation will be done by HMC's Deepwater Construction Vessel (DCV) Balder. DCV Balder was built as Semi-Submersible Crane Vessel in 1978 and underwent an extensive life time extension and conversion program in 2001. [Ref 1] DCV Balder is specialized in installing complex deepwater field architecture and is well suited for the installation of the 20 inch Export SCR.

Some characteristics of Balder equipment used for the SCR installation are:DP Class III, with a thrust capability of 350 mTDual crane capability, with deepwater capacity of 250 mT at 3000 m waterdepth.Mooring Line Deployment Winch (MLDW), with a capacity of 310 mT. (Static wire load including 12% dynamics) [ref 1]Abandonment and Recovery Winch System (A&R), with a hoisting capacity of 650 mT. [ref 2].

For the installation of a single pre-laid SCR to the IHUB, the following phases have been distinguished:
Innovative Pipe System for Offshore LNG Transfer
Authors: Frohne Christian , Harten Friedrich , Schippl Klaus , Steen Knut Erik , Haakonsen Rune , Eide Jorgen , Høvik Jon
Published: October 2008

For more than 30 years LNG ship to ship loading has been addressed by several Gas operators. One of the main technical challenges that have been identified has been how to extend and combine the proven technologies of static small bore diameter cryogenic piping and offshore ship to ship transfer of oil to large diameter offshore LNG transfer.

In the last years the market has pushed for flexible piping suitable for LNG offshore loading systems, and the industry has responded with different technical solutions based on very different design criteria. In this paper the basic requirements for a

LNG offshore loading system are presented. As a minimum the requirement of the European code prEN 1474 - II is quoted.

Design Classification of LNG Flexible Pipes

Today there are two completely different flexible pipes designs existing on the market, both are proven in their applicationsComposite hosesFlexible metal pipes based on corrugated stainless steel pipes (sometimes called " bellows?? although not necessarily based on the bellows technology, which is in principle limited in length)

The composite hose is a proven technology for a wide range of applications, amongst others the offshore loading of all kind of ambient temperature liquids. In the LNG business they are available as emergency unloading hoses.

The flexible metal pipe has been used in smaller diameters for more than 30 years for all kind of cryogenic applications, transfer lines for Liquid Nitrogen, Helium and even Hydrogen and Oxygen.

So for both design options, the LNG ship to ship loading is a new application of a well known technology
An Evaluation of Perforating Techniques and Use of Caesium Formate Kill Pills to Optimise Productivity in HPHT Gas Wells and Minimise HSE Risks
Authors: Roy Alistair Malcolm , Twynam Allan Jeffery , Parke Jeff , Morrison Angus , Downs John
Published: October 2008

The BP Operated Rhum Field is a North Sea High Pressure High Temperature lean gas field. A key design requirement for successful development well planning and execution was to evaluate Overbalance and Dynamic Underbalance perforating techniques for their potential to optimise productivity while reducing the risk of producing hydrocarbons to surface during downhole operations.

In this paper we present a case history focussing on the evaluation of the available perforation techniques with the aim of matching or exceeding the flow performance achieved on the Appraisal Well DST. The selection of drill pipe conveyed dynamic underbalance perforation, using the Schlumberger PURE technique provided the best compromise in terms of minimising HSE exposure and maximising productivity, with the main potential downside being the potential for large cost over-runs from utilising Caesium Formate brine. The re-completion of a Rhum appraisal well provided a rare opportunity to obtain a direct comparison of well productivity from standard Underbalanced and Dynamic Underbalanced perforating operations in the same reservoir interval.

Operational issues forced the Rhum team to utilise a third perforation technique, on-balance perforation via electric line, and the paper will present the productivity achieved using this technique also.

The paper progresses sequentially through the following items;An overview of the Rhum Field and Reservoir;Design and Planning of the perforation techniques utilised on Rhum Development wells to overcome challenges such as Hard Rock Perforating and Sand Control requirements;The detailed design and core flood testing of two different types of Caesium Formate Kill Pills, aimed at identifying the least-damaging formulation.

Operational data is presented to demonstrate the success of dynamic underbalance in maintaining a full fluid column, effective gas suppression in clear brine and tight fluid loss control. Field production and pressure data showing the filter cake clean-up over time is examined to evaluate the actual performance of the chosen kill pill after extended exposure at downhole temperature.

The paper concludes with a comparison of the flow performance achieved on a single well in an identical reservoir interval when shot with ;standard underbalance during the original appraisal DST operation anddynamic underbalance for the development completion operation (original perforations cemented off).

These results are compared with the flow performance of a second well shot on-balance using electric line.
Mitigation of Ice Risk to Subsea Infrastructure
Authors: Morgan Vincent , Phillips Ryan Douglas , Randell Charles , Freeman Ralph
Published: October 2008

A review of the current capability within the industry is given for assessing the iceberg environment and iceberg keel / seabed structure interaction, with emphasis on operations relevant to the east coast of Canada. Consideration of calculating contact frequency and ice loads for iceberg keel impact is discussed, for both freely floating and gouging icebergs. Available environmental data for the Labrador Shelf and Grand Banks of Newfoundland are summarized. An overview of the operational experience of placing subsea production facilities in glory holes to provide protection from iceberg keels is provided, along with a review of studies related to the development of alternative solutions. Studies have been performed to investigate the feasibility of design and construction of cased (or silo) glory holes, external protection structures such as rock berms and steel or concrete structures, and the effects of direct impact scenarios such as the use of caisson wellhead systems.

Ongoing efforts to improve the knowledge base, analytical capability and engineering solutions to predict the effect of iceberg keel loading on subsea oil and gas facilities are described. Obstacles to safe and economic development are identified, along with a discussion of methods that can be used to overcome these and provide practical solutions for future development.

Background

Over 25% of the world's petroleum reserves are believed to be in arctic regions and other offshore, ice frequented environments. As world energy demand increases, development of oil and gas resources in harsh ice environments is being increasingly considered by industry. The advancement of safe, cost-effective and reliable engineering solutions for subsea infrastructure in ice environments is a key requirement for sanctioning stand alone and marginal field developments. Subsea infrastructure requiring protection from ice keel contact includes components such as wellheads, production trees, manifolds, umbilicals, flowlines and pipelines.

This paper describes an ongoing joint industry project that was initiated to address uncertainties and develop approaches to mitigate the risks associated with oil and gas development in ice-prone regions. The project comprises two components that address differences in approach for issues related to pipelines in Arctic regions, and subsea production facilities in sub-Arctic regions. It is funded by a combination of the Atlantic Canada Opportunities Agency through its Atlantic Innovation Fund and a number of large oil and gas operators. Project collaborators include private companies, government agencies and academic organizations.
Challenges of Flow Assurance in the Roncador Field
Authors: Noe Gustavo , Nascimento Robson Ferreira , Silva Sidnei Guerreiro , Rodrigues Francisco Ferreira
Published: October 2008

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

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

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

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

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'Brien Patrick , Dines Brian
Published: October 2008

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

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

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

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.