bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Intervention and Well Abandonment Resources To Increase Safety, Efficiency and Cost Savings Through an Innovative Total Service Package
Authors: Olstad Delaney
Published: May 2013

The need for an effective strategic plan to address intervention and well abandonment projects in an efficient manner requires an extensive array of multidisciplinary services and the utilization of equipment in innovative ways. The ability of an established service company to supply an inclusive project package allows the clients to focus their internal resources on further developments and provides the service company increased opportunities to innovate. This paper will review the successes realized by providing a total service package which included innovative equipment, technologies, and processes to optimize safety and increase cost savings by efficiently addressing the requirements and challenges associated with intervention and well abandonment operations.

By providing a full range of intervention and well abandonment equipment and services, a multitude of operations can be addressed by a single contractor, which greatly reduces the inefficiencies typical when utilizing multiple vendors. This unique product line consists of innovative operating systems which provide the client a range of services that result in an efficient total service package.

The most effective use of these services has been realized during operations utilizing the newly developed pulling and jacking units (PJU). The PJU have proven a safe and cost-effective alternative to conventional equipment and allow the client to address the project objectives from a single inclusive source. The units can be modified to meet the requirements of the operating system is in place, the full potential of the PJU can be realized. Evidence of the efficiencies associated with a total service package, including the collaborative efforts of experienced personnel and an array of product lines and services, are shown in both the safety record and via cost savings.

Introduction

Intervention and abandonment operations typically require a multitude of services, products and resources. Increasingly operators are requiring a total service package when addressing mature-well revitalization, late-stage intervention, and final abandonment. Operators, on a global scale, are seeking bundled services including fit-for-purpose equipment that maximizes cost saving potential while adhering fully to safety standards. Traditional late-stage intervention and final abandonment operations can be costly or could involve time-consuming methods potentially detrimental to personnel, assets, and the environment without the possibility of recouping operational costs. New technologies and resources are now available to address the intervention and well abandonment market. The ability to provide a total service package which includes innovative equipment and processes to optimize safety and increase cost savings is crucial to meeting the needs of the oil and gas industry.
Successful High-Density Cement Plugs in a HP/HT Presalt Deepwater Well in Brazil's Santos Basin
Authors: Silvestri Rodrigo , Moraes William Oda De Oliveira , Borba Robson Esteves , De Bruijn Gunnar G , Sobreira Mauro , Fagundes Luiz , Moretti Fabricio , Guerediaga Denis
Published: May 2013

Ensuring well safety during the well construction and abandonment process provided a challenge for an offshore exploration worldwide. More than ever the importance of the successful abandonment of exploration wells is critical. High quality cement plugs are required to provide a tested isolation barrier. Over the years the industry has experienced many problems in the correctly placing cement plugs. Historically, setting cement plugs in open hole at deep depths has been a difficult task. Often, several attempts are necessary to end with a proven barrier or a competent kickoff plug. Sometimes, small contaminations with synthetic drilling fluid have a detrimental effect on the physical properties of the set cement, resulting in catastrophic events. This challenging task becomes even more difficult when drilling in deepwater environments due to frontier exploration, increasing placement depth, high-pressure reservoirs, high-density drilling fluids, salt formations, and high-pressure gas reservoirs. In Brazil, the exploration campaigns are moving to pre-salt reservoirs where operators face a combination of these challenges.

An overpressured, presalt gas reservoir in the Santos basin was discovered with an equivalent pore pressure ranging from 18.5-18.7 ppg (ultra high pressure ~ 20.000 psi) at 6,136 m true vertical depth. During drilling operations in this high-pressure, high-temperature (HP/HT) deepwater well, a kick was observed after drilling a few meters below the salt. This led to the application of conventional methods of well control. Once the well was shut in, the pressure readings at the surface were stabilized at 5,600 psi, and the mud weight was increased to 19 ppg to achieve hydrostatic control of the well. Once well control was regained, the well was temporarily suspended with a sequence of cement plugs. These unexpected levels of pressures suggest a discovery. However, further research was postponed due to the current rig limitations and supplies.

A total of 392 m of 8 ½?? open hole section were abandoned using two cement plugs with a special high-density slurry of 21 ppg and high-density spacer of 20 ppg. A third cement plug was set in the previous casing string. The design included a special chemistry for formations with gas and salt. Software simulations and the analysis of placement techniques and practices help ensure the success of these operations in this challenging environment.

The successful practices demonstrated for these plugs will be useful for other ultrahigh pressure discoveries that may be encountered. These practices may also be useful when setting cement plugs in conventional wells or wells with high density drilling fluids.
Contractors Under SEMS: Understanding Customer Requirements
Authors: Wells Ken
Published: May 2013

It is tempting to see the SEMS regulations as involving just two parties, the federal regulators who mandate them and the operators of offshore oil and gas leases. However, this misses the fact that the 120 or so operators in federal waters rely on approximately 5,000 contractor companies for offshore operations. In fact, some 90% of personnel who work on offshore facilities are employed by contractors. This is a higher percentage than is found in other industries that have adopted safety management approaches. Based on surveys, reviews of operator SEMS requirements and extensive discussions with operators, contractors and regulators, it is apparent that contractors have struggled to understand and meet operator requirements. In some cases, contractors are not familiar with the processes and requirements imposed on operators by the SEMS rules. In other cases, contractors have implemented and are following good safety practices, but find they must change their practices to conform to SEMS.

Finally, there has been a general level of uncertainty by contractors, operators and the regulating agency over how the SEMS requirements relate to existing safety practices. The root causes of these areas of concern are diverse, including contractor understanding of the new rules, operator execution of SEMS plans and a failure of the regulations to fully embrace the critical role of contractors in the oil and gas industry. In short, the industry and regulators are making a slow, painful voyage in adopting such an extensive safety management process. It has been well documented that successful implementation of SEMS will require a change in culture. What has not been fully understood is the importance of the contractor community in adopting that new cultural paradigm. The paper analyzes these concerns and steps that may help ease that transition.

Introduction

The regulations mandating Safety and Environmental Management Systems (SEMS) are often viewed as a two-way conversation between the government and offshore oil and gas companies. The regulations were written by the Interior Department sub-agency now known as the Bureau of Safety and Environmental Enforcement (BSEE) and they apply to the operators of offshore oil, gas and sulfur leases located in federal waters. The word " you?? appears 165 times in the SEMS regulations and each time it means " a lessee, the owner or holder of operating rights, a designated operator or agent of the lessee(s), a pipeline right-of-way holder, or a State lessee granted a right-of-use and easement.??
Techniques and Materials for North Sea Plug and Abandonment Operations
Authors: Khalifeh Mahmoud , Hodne Helge , Saasen Arild , Vralstad Torbjorn
Published: May 2013

Plug and Abandonment (P&A) can easily contribute with 25% of the total costs of drilling exploration wells offshore Norway. The costs of running a P&A operation on some offshore production wells may have a cost impact similar to the cost of the original drilling operation. Therefore, cost efficient P&A technology is necessary to reduce cost. In this paper, qualified technology and materials for P&A is reviewed to act as a basis for P&A planning. This paper describes in detail requirements for P&A operations offshore Norway as well as normal practices for P&A. Well construction issues related to minimising the need for later P&A operations like proper primary cementing planning is discussed. P&A techniques and materials for P&A operations are reviewed to act as background information for future P&A planning on the Norwegian continental shelf. These techniques include operations ranging from milling to washing and squeezing cement or other materials. The materials being reviewed include swollen shale, concentrated sand, metal plugs like bismuth, as well as improved conventional cement systems. This work presents an overview of the well plugging and abandonment challenges, innovative potential barriers and case histories on the Norwegian continental shelf.

Introduction

Oil and gas wells at some time in their life will be plugged and abandoned. Improperly abandoned wells can become a significant threat to the environment if they are not constructed or sealed properly. Plugging material (barrier) may fail during or after placement. Barrier failure can be caused by: natural fractures/faults, tectonic stresses, improper plug placement or materials used. In brief; isolation outside casing, collapses and sustained casing pressure are main well integrity challenges with respect to Plug and Abandonment (P&A). The quality and performance of a P&A operation may be investigated by two points of view; type of plugging material and plug placement technique. Barriers may be categorized as cementitious or mechanical barriers. It should be noted that mechanical barriers are used as temporary P&A barriers and not allowed to be used as permanent barriers. Type of material used defines the type of plug placement technique. There are several cement plug placement techniques that are used in the abandonment process (Smith 1993; Nelson 2006):Balanced method,Dump-bailer method,Two-plug method, andJet grouting.

The following tools are used for placing cement plugs:Flexible bags,Inflatable through-tubing packers, andUmbrella-shaped membranes (Nelson 2006). Local practices, government regulations, company policies and well conditions lead to variations of the above-mentioned tools and methods.
Liwan Gas Project: First South China Sea Deepwater Completions Campaign
Authors: Jennings John Charles , Triolo David Kenneth , Mosness Tracy Lee , Rezende Jorge
Published: May 2013

Husky Energy installed 14 " frac-pack?? lower completions, 10 sub-sea horizontal trees, and 7 upper completions utilizing two 6-th generation deep water semi-submersibles in Block 29/26 of the Pearl River Marine Basin (PRMB) South China Sea between June 2011 and January 2013. On average, the lower completions, tree installation and upper completions required, 12 days, 2 day and 24 days, respectively. The water depth ranged from 650 m to 1450 m.

Introduction

In 2004 Husky Energy signed a production sharing contract with the China National Offshore Oil Company (CNOOC) for Pearl River Basin South China Sea deep water Block 29/26 which is 320 km south of Hong Kong (see Figure No. 1). In April 2006, the exploration well Liwan 3-1-1 was drilled in 1500 meters of water discovering the Liwan 3–1 gas reservoir. A 6th generation semi-submersible being built in South Korea was contracted for 3 years (plus 2 × 1-year options). Drilling re-commenced in November 2008 and by November 2011, 26 wells were drilled consisting of 10 exploration wells, 10 appraisal wells and 6 development wells. Six wells were drill stem tested. Three fields with gas-bearing sandstone reservoirs were discovered; Liwan 3–1, Liuhua 34–2, and Luihua 29–1 (See Figure No. 2)

Regional Geology

The Liwan 3–1 field is located in 1300 to 1500 m water depth within the Baiyun Sag of the Zhu 2 Sub-basin. The two nearest fields are the Panyu 30–1 gas field and the Liuhia 11–1 oil field located 64 km north-west and 102 km northeast, respectively. The PRMB lies on the northern continental shelf of the South China Sea. The Liwan structure developed during the early Miocene. The organic-rich sediments on the Wenchang formation, middle to upper Eocene, are considered to be the potential source rock for the reservoir.

The tectonic events during the Oligocene-Miocene period which affected regional sea levels led to significant changes in the drainage framework of the Pearl River, provenance of sediments and depositional environments. Following these tectonic events, thermo-subsidence occurred in the Baiyun Sag and the depositional environment changed from a continental shelf with neritic deposition to a continental slope with deep-water deposition. The main hydrocarbon bearing reservoir, Zhujiang formation, in the Liwan 3–1 Gas field is a turbidite basin-floor fan. The lithology is predominantly claystone and siltstone with local thin deep-water sand stone units.

During the Nanhai movement in Late Oligocene most parts of the PRMB were uplifted and partially eroded to form a wide regional unconformity surface. As a result of subsequent sea level rise most portions of the Baiyun sag exhibited shallow marine sedimentation. During subsequent regression, delta profradation occurred primarily in the south Uplift Belt in the southern part of the Baiyun Sag. The Zhuhai Formation, found beneath the Zhujiang formation, is characterized by excellent reservoir quality, deltaic-shallow marine sandstones.
LNG Barges: The Offshore Solution for Export of US Pipeline Gas
Authors: Price Brian , Talib Javid Husain
Published: May 2013

With the advent of increased production of Shale Gas in United States, and the continuing drop in gas prices, the possibility of exporting US gas is becoming more real. Many developers are vying to build larger capacity LNG production facilities for exporting to Free Trade Agreement (FTA) and Non-Free Trade AgreementNon-FTA) countries in Asia and Far East while smaller market exists in South America and Caribbean requiring small to midscale LNG supply volumes.

The larger on-land base load LNG export production plants require significant capital and takes 4 to 5 years to bring online. A novel LNG barge concept provides a faster way to build a small to midscale LNG production facility near-shore in protected waters and/or dockside. The focus on a simple, reliable process solution and barge structure is making this concept a reality for converting US pipeline gas into LNG for export to markets which require smaller LNG volumes than are envisioned with the large scale projects.

A barge mounted LNG production facility requires the application of liquefaction technology that is simple, space efficient and energy efficient. The technology of choice for these applications is the Single Mixed Refrigerant (SMR) process. The simplicity, flexibility and scalability of the SMR process can provide a wide range of liquefaction capacities in a unique single or multiple-train configuration on the barge. There are several system options from which any configuration can be built around depending up on the location, power availability, permitting constraints for use of water cooling and the LNG offloading/export strategy. The barge could be self sufficient or be integrated with onshore support systems at dockside. The barge and its topsides production facility can be built in United States or anywhere in the world competitively and towed to US locations.
Improving Cement Placement by Accounting for Lost Circulation and NAF Compressibility
Authors: Chaudhary Saleem , Felio Archie J , Shine Joseph Michael , Martin Robert Stroud
Published: May 2013

Most cementing simulators do not account for lost circulation events or the compression/expansion behavior of non-aqueous fluids (NAF) during cement placement. As a result, their output can be unreliable, resulting in potentially poor recommendations and operational performance - in potentially critical well-cementing situations. When isolating potential flow zones and/or performing zonal isolation in high-temperature/high-pressure (HT/HP) and/or deepwater environments for example, accounting for lost circulation and compressibility of non-aqueous fluids can make the difference between a successful cementing operation and a very expensive failure. In addition, overall reliability compared to existing simulators is improved operationally and technically assuring the objectives of the cement placement can be met while complying with new regulations as they can apply to zonal isolation.

This paper will explain the theory and methods behind the advanced cementing simulator inputs and resultant outputs with case histories demonstrating some of the field validation of the new simulator's reliability. Also, existing technology in the simulator will be highlighted summarizing the robust package available to meet the objectives of cementing job placement in light of recent industry changing events.

Background

To the authors' knowledge, the existing current simulator technology on the market cannot account for losses while cementing in addition to compressibility/expansion of NAFs simultaneously during cement placement. Furthermore, the authors could not determine if the market's advanced modeling software used could simultaneously handle the same events using a dynamic wellbore temperature profile or multiple cementing fluids (i.e. drilling fluids, spacers, cements) with different densities. A compositional model to define fluid densities at downhole temperatures/pressures, multiple rheology sets for varying temperatures/pressures of the various fluids, and temperature dependence of the cementing fluids for friction pressure determination on placement ECDs is essential for proper modeling. These requirements should not be confused with riserless cementing simulations where returns are planned to be lost at the sea bed or mudline, creating a " pseudo-mudline.?? Riserless cementing does not have to consider the wellbore geometries and friction pressures in the case of cement placement with the marine riser in place.
Design Guideline Strategies for HPHT Equipment
Authors: Skeels Brian
Published: May 2013

As the need for oil and gas equipment working in hotter and higher pressure environments continues to mount, the effort to come up with an adequate set of design, material, and validation practices continues to be challenging. The higher pressures, and therefore thicker wall sections, have pushed traditional thin-wall pressure vessel design practices to theoretical limits, where their design model assumptions are becoming increasingly inaccurate in predicting design stress or present overly conservative hardware designs that are too thick or complicated to fabricate; not to mention safely pressure test in the factory. Manufacturing processes and material mechanical properties are also being pushed well beyond general practice to meet more stringent ductility requirements and to resist aggressive corrosion environments. Historically, designers simply overdesigned the equipment to provide a robust product with liberal design margins to hopefully out-muscle any unforeseen or complicated set of loading conditions. However, for the newer HPHT oilfield equipment, overdesign is less and less an option. Now the most challenging design failure mode is shifting towards fatigue and fast fracture as the equipment is taxed by very high internal pressures, while increasing temperatures are decreasing material strength. As a result, more rigorous stress analysis and design methods that more closely model fast-fracture burst conditions (rather than leak-before-burst failure) are needed to achieve safe, reliable and cost effective equipment designs. However, the effort to fully embrace the change to more rigorous design methods has been arduous. The Industry is just entering the transition zone between conventional and HPHT environs, and pressure vessel code "demarcation" on pressure ratings overlap in this region. Therefore a lengthy debate has ensued as to where does one draw the line between traditional "quasi-static" (infinite fatigue life) thin wall pressure vessel design practices and begin using a Lamé thick-walled model with fatigue and fast-fracture failure (fracture mechanics) design practice. Both have equally valid arguments in this transition region from 10 000 psi at 250F to 20 000 psi at 400F (69 MPa at121C - 138 MPa at 205C). Some of the debate on where the line of demarcation is drawn is fueled by the fear that when one crosses that line, then fatigue/fracture mechanics will drive design calculations, material performance and testing, and validation testing exponentially beyond what is expected today.

Although this Rubicon will eventually have to be crossed as HPHT conditions tax designs and materials, this paper offers some insight into some simple tests to augment HPHT design practices, building on the insights presented in OTC paper # 23621.
Photonic Sensing for the Energy Business: An Integrated Approach
Authors: Yousefi Mirvais , Pozo Jose , Elshahawi Hani
Published: May 2013

Using photons to sense instead of electrons has many advantages, which is why photonic sensing is slowly maturing from a niche into a fully-fledged mature technology. In the O&G business, photonic sensing has gained ground and in some cases is even becoming the standard. Most of these systems are fiber or free space optics based, though. So far, this has been sufficient, but future demands for high information rate at a low cost will make it very difficult for these systems to be competitive on their own. Analogous to the electronics industry, there is also a drive in the fields of photonics for integration of functionality on integrated circuits, the so-called Photonic Integrated Circuits (PIC).

In this paper we will present an overview of a novel sensing technology, based on Application Specific Photonic Integrated Circuits (ASPIC) that is suitable and in some cases mature to be deployed for O&G exploration. We will touch on existing and future technologies and also explain the Multi Project Wafer model that is revolutionizing commercial ASPIC development.

Introduction

Development and exploitation of oil and gas resources must overcome numerous technical challenges that only increase with time. Real-time sensing technologies are critical for optimizing production, increasing ultimate recovery, and improving profitability of these fields. Industry development of real-time sensing technologies began as far back as the 1970's, but the deep water environment presents additional challenges that have resulted in slower uptake of these technologies. The ideal advanced sensing solution will in principle:Facilitate production objectivesSimplify completions to improve overall reliabilityMinimize CAPEX/OPEXMaximize standardization between various well typesFacilitate contingency interventions and deployment of selected legacy technologiesApply intervention-less designs, technologies, and procedures to minimize interventionsEnsure compatibility with all aspects of sand face completion and interfacesFacilitate corrosion protection (chemically/metallurgically) for H2S and CO2 environmentAllow for remedial / post completion operations and work overEnsure contingency service tool compatibility between upper / lower componentsProvide friendly space out of upper completion/tubing hanger

To define which technology or combination of technologies is most appropriate for real-time sensing, one must:Define objectives of the well.Design the well design program to meet the objectives.Deploy the technologies that can provide the data and interpretation that is necessary to meet these objectives.
Full-Scale Testing of Distributed Temperature Sensing in Flexible Risers and Flowlines
Authors: Weppenaar Nick , Iversen Thomas Solfeldt , Andersen Bo Asp Moller
Published: May 2013

The scope of this paper is to present the results from full scale testing of a flexible riser equipped with embedded sensors for distributed temperature sensing. Testing includes monitoring of accessories mounted on the riser, monitoring of hot spots such as trenched sections of the riser, and finally detection of breaches of the outer sheath. Furthermore, the applications of such a condition monitoring system within Riser Integrity Management (RIM) and production optimization will be discussed. For example, the temperature may be measured along a riser (or flowline) for evaluating the annulus environment and as a supplement to the flow assurance assessment, e.g. to avoid hydrate formation.

Motivation

With the increasing use of flexible pipe technology - driven by the move of new offshore fields to deeper, more marginal and more challenging conditions - the need for systematic management of the flexible pipes is becoming more apparent. In particular, the full implementation of Riser Integrity Management (RIM) plays a vital role to ensure an efficient and safe operation. Riser condition monitoring and inspection form an important part of integrity management together with processing and analysis of the monitored data. In that respect, the recently developed technology within optical fiber monitoring offers unique possibilities for quantifying the integrity of the flexible risers during their service life. The advantage of an embedded monitoring system is the ability to continuously survey the riser condition, thus enabling operators to detect potential damages in due time. The embedded system will allow monitoring in critical areas (e.g. under a bend stiffener or inside an I-tube) where access is limited for externally mounted monitoring systems.
In-Well Distributed Fiber Optic Solutions for Reservoir Surveillance
Authors: Van Der Horst Juun , Lopez Jorge L , Berlang Wilfred , Potters Hans
Published: May 2013

Recently two new distributed fiber-optic sensing technologies, Distributed Acoustic Sensing (DAS) and Distributed Strain Sensing (DSS), have become available for use in oil and gas applications in addition to the more traditional temperature profiling with Distributed Temperature Sensing (DTS). These technologies offer a wide range of applications which include well integrity monitoring, gas lift optimization, flow profiling, and borehole seismic for geophysical reservoir monitoring.

Fiber optic sensing can be very cost-effective in deepwater environments, where wells are exceedingly expensive and non-intrusive operations are a must to avoid very costly rig time. With a permanent fiber optic installation one may monitor, on demand, in-well pressures, temperatures, flow, and casing or completion deformation, as well away from the well using time-lapse vertical seismic profiles (VSP).

The combined interpretation of DAS, DTS, and/or DSS data allows for a more robust interpretation of flow. DAS is expected to be particularly cost-effective for geophysical surveillance in deepwater as it eliminates the need for well intervention, which often precludes down-hole monitoring altogether. Typical geophysical applications include surveillance of water injectors and propagation of waterfronts near injectors or producers.

In this paper recent field trials are discussed to demonstrate the value of these novel in-well fiber optic applications. These trials highlight the benefit of integrated data interpretation and the versatility of applications that are possible using fiber optic installations in wells. The applications shown are the use of the DSS for inflow profiling in a water injector in a deepwater asset, gas flow monitoring by combined interpretation of DAS and DTS data, and the first offshore applications of DAS for borehole seismic in Shell.
Geological, Geophysical and Petrophysical Characterisation of Hydrocarbon Reservoirs in South China Sea Deep Water Block 29/26
Authors: Mi Greg Yanpeng
Published: May 2013

In 2004, Block 29/26 Production Sharing Contract (PSC) was signed between Husky Energy Inc. and China National Offshore Oil Corporation (CNOOC). The block is located about 300 km offshore Hong Kong (Figure 1), on the north east slope of the gas-prone Baiyun (White Cloud) Sub Sag of the Zhu-II sub-basin in the larger Pearl River Mouth Basin (PRMB). The water depth on the block is from 650 m to 1500 m.

A total of 27 deep water exploration and appraisal wells were drilled in the period between 2006 and 2011. Three commercial gas fields, Liwan 3-1-1, LH34-2 and LH29-1, were discovered in April 2006, September 2009 and December 2009, respectively. Several sub-economic gas accumulations were also discovered in the same period. Reservoir and hydrocarbon detection and trap delineation, were the key challenges faced by the exploration team. An integrated subsurface approach, including extensive 3D seismic surveying and high quality processing, seismic inversion, accurate structural/stratigraphic mapping, accurate depth conversion and seismic-based geomorphology, played a key role in making these discoveries. At the time of writing this paper, Block 29/26 is the only deep water block in South China Sea (SCS) with commercial discoveries, and boasts the most extensive deep water database in the region, including large amounts of seismic, conventional and side-wall cores, wireline logs, pressure and fluid samples as well as subsequent lab analyses data. Full investigation of the available information can be expected to provide the necessary guidance for future exploration and development activities in this region.

There are several types of reservoirs encountered in Block 29/26. Each type of reservoir has distinctively different log characteristics and seismic responses. This paper provides a systematic review on the applicability of AVA technology to the seismic data on the block and focuses on the challenges that need to be addressed in the future.
Study and Application of Production Relief and Blowdown on the Large-Scale Offshore Oil and Gas Fields
Authors: Zhi Xia
Published: May 2013

This paper discusses and summarizes the typical development engineering options about production relief and blowdown system, which based on the cases study of some large-scale offshore oil & gas fields in production worldwide and their features, functions and applications. The evaluation of flare system is based on safety, environment, constructability and cost effectiveness that safely minimize the flaring load. Total blowdown load could be further reduced by installation of Passive Fire Protection as fire proofing insulation but with higher CAPEX and OPEX cost. Generally, cold venting is not recommended especially for large scale offshore production due to safety concern and environment issues.

The Liwan3-1 gas field is located in the South China Sea, in approximately 1480 m of water depth, and 350 km far from the onshore. Total maximum yearly gas production gas project reaches 120×108 Sm3, and two flare systems are provided on the central platform. Various scenarios of relieving and depressuring cases are analyzed to determine the peak rate of each option. Depressuring or blowdown systems work in conjunction with the shutdown system is functioned to isolate and depressurize process systems in the event of a fire or incident where the process inventory is required to be removed. The high pressure and low pressure flare knock out drums are provided for both the HP and LP flare systems prior to gas disposal by combustion at the LP and HP flare tips. Both LP and HP flare system share a common flare boom, and high-integrity pressure protection system is applied to reduce the design capacity for the flare system. The flare radiation limit of 6.31kW/m2 is recommended and the mean wind speed is used as the criteria to be adhered to. The flare stack is designed for various orientations. The 45° inclined stack form horizontal is recommended based on safety concern as primary and cost.

According to the environmental conditions and the features of potential oil and gas structures in the South China Sea, the deepwater development engineering options of about production relief and blowdown system which will be suited for the area are proposed.
Husky Liwan Deepwater Subsea Control System
Authors: Bavidge Michael
Published: May 2013

The Liwan subsea control system located offshore China in deepwater of 1,500 meters is one of the most technologically advanced systems to be installed. The control system for Liwan is of necessity large and complex and has incorporated many current industry innovations in control and communications across the system.

This paper will present a review of the control system and the key components provided for the deepwater Liwan field such as,Subsea Control Modules (SCM) for Subsea Production Trees and StructuresSubsea Router Modules (SRM) for Manifold, Pipeline End Manifold (PLEM) and Umbilical Termination UnitsSubsea Monitoring Module for Corrosion Monitoring SystemSubsea Power and Communications Unit located on the Central Production Platform (CEP)Chemical Injection Metering Valves for the methanol (MeOH), monoethylene glycol (MEG) and Corrosion Inhibitor (CI) distribution at the subsea structures.Umbilical Termination Units for Subsea DistributionUmbilical Termination Heads for the Infield Umbilical DistributionFiber Optic Communications from Topside to the SRM'sHigh Voltage Direct Current (DC) system to all SRM's and SCM's located on all structures

The development and engineering of the Liwan control system will be described within the paper from conceptual design, explaining the control system architecture due to the Liwan field layout complexity of area's Liwan 3–1 and Liuhua 34–2 and their distant geographical locations subsea. This paper will also cover the subsea control system fabrication, integration testing and finally installation and commissioning offshore in China.
Long Stroke Ram-Style Tensioner Technology
Authors: Koos John
Published: May 2013

The focus of this presentation will be to discuss and evaluate major concerns in the development of Long Stroke Ram-Style Tensioners, as an enabling technology to address the upcoming demands of the Offshore Industry as it pushes to drill and produce in ultra-deep water. The increasing demand on riser tensioners to accommodate higher riser loads with longer stroke capability in ultra-deep water is pushing technology beyond what has been currently developed in the industry.

Introduction

As Drilling and Production recovery for oil and gas expands into water depths in excess of 8,000ft, tensioner technology is being challenged to provide realistic and cost effective solutions. As riser tensioners increase in size and capacity to accommodate high riser loads, well bay configurations and tensioner interfaces have a significant impact on the design of the support vessel. Tensioner stroke lengths are increasing rapidly in response to larger vessel offsets, heave displacements and updated Regulatory requirements for survival conditions. These long stroke high capacity tensioners are influencing well bay design. Specifically, the stack up clearance between decks, number of risers, jumper hose layout, riser spacing, production tree clearance and motions, equipment maintenance and access. It takes an iterative design effort to integrate all of these elements into a cost effective workable solution.

There are two major tensioner configurations used in the industry today; the ram or push up style and the rod in tension or pull up style. Both tensioner styles have various pros and cons inherent in each configuration. Numerous factors are considered when selecting a tensioner for a particular project or vessel type such as operator preference, load ring accessibility, well bay configuration, tensioner capacity, component serviceability and cost.
Finneidfjord: a Field Laboratory for Integrated Submarine Slope Stability Assessments and Characterization of Landslide-Prone Sediments: A Review
Authors: Haflidason Haflidi , Morgan Eugene , L'Heureux Jean-Sebastien , Forsberg Carl Fredrik , Kreiter Stefan , Kopf Achim , Lecomte Isabelle , Kvalstad Tore J. , Vardy Mark E. , Longva Oddvar , Brendryen Jo , Strout James Michael , Tobias Moerz , Vanneste Maarten , Steiner Alois
Published: May 2013

Sørfjord outside the village of Finneidfjord has a history of landsliding throughout the Holocene. The 1996 landslide -the focus of this study - has many characteristics typical of submarine landslides (well-developed slip plane, outrunner blocks, peripheral thrusting and lateral spreading). Due to its sheltered and accessible location, Finneidfjord has become a natural laboratory for testing high-resolution and multidisciplinary techniques to improve our understanding of landslide development.

This study integrates multiple sediment cores, swath-bathymetry surveys, single- and multi-channel 2D seismic data (Topas, boomer, sparker, airgun), very-high-resolution 3D chirp seismics, ocean-bottom seismometer as well as free fall and traditional cone penetration testing (CPTU). The cores have been subjected to both geological and geotechnical laboratory analyses. Of particular interest is the correlation of the regional slip plane as a high-amplitude package of reflections in the geophysical data with the results of the sediment and in situ measurements.

Comparison of 3D traces with synthetic seismograms based on multi-sensor core logs show that the most prominent slip plane lies within a thin clay unit sandwiching a sand seam. The slip plane is difficult to identify from CPTU data alone. The top part of this composite unit has in places been eroded under the 1996 mass-transport deposit (MTD). This composite unit's formation is associated with turbidite deposits from terrestrial quick clay landslides and possibly river floods in the catchment of the fjord. While the MTD is extensively deformed, different flow facies are identified within the landslide body revealing a complex, multi-phase failure. The seismic data were also used to infer physical properties (mean grain size, gas saturation from P-wave attenuation). Interestingly, shallow gas adjacent to the landslide appears not to have played a role in the landslide development.

Fjordbed stability is strongly influenced by shallow subsurface structure, with geotechnical properties and lateral continuity of stratified beds acting as primary controls on slide plane depth and failure mechanisms. This study can well form a template for near-shore areas prone to landsliding. Currently, a long-term pore pressure monitoring programme is in progress, after the installation of several piezometers close to the depths of the slip plane close to the shoreline in September 2012.
Gaps and Advancements for Deepwater Production and Remote Processing: Large Diameter Riser Laboratory Gas-Lift Tests
Authors: Schoppa Wade , Zabaras George J , Menon Raghu , Wicks Moye
Published: May 2013

An experimental program was carried out to support the application of riser-base gas injection for deepwater production risers. The experimental equipment consisted of a 40 ft-tall, 11?? ID vertical riser connected to a 25 ft-long flowline section of the same inside diameter. The motivation for this work was the significant uncertainty that exists as to the behavior of vertical gas-liquid flow in large diameter pipes. Scarce published information exists for such flows and no known records of flow regime observations are available from the published literature.

Riser-base gas-lift has been identified by various deepwater project teams as a key operability element that can address three major project objectives:flow assurance requirements necessitate the evacuation of the riser during an extended shut-down by using injection gas. As a result of riser evacuation, the hydrostatic pressure at the base of the riser is reduced to a level below the pressure required for hydrate formation at the ambient seawater temperature of between 37 and 40 F,production economics for many deepwater projects relies on riser-base gas-lift as an artificial lift method and,riser-base gas injection will be necessary for alleviating severe slugging problems in deepwater flowline-riser systems.

In order to verify the ability of gas-lift to fulfill the stated objectives for large diameter risers, a variety of air-water flow tests were carried out in the 11?? transparent riser system built at Shell's Houston Technology Center. The flow tests included transient and steady-state gas-liquid flow and flow regime visualization. Measured riser pressure drop data were used to compare with 1-dimensional flow model predictions. Serious model limitations were found as the models failed to accurately capture " churn flow" effects that appeared to dominate over the range of conditions studied. Steady-state pressure drops were underpredicted by more than 25%. Riser evacuation predictions indicated continued liquid removal whereas the data showed that liquid is expelled as an initial slug with no additional carry over.

To overcome the shortcomings of 1-dimensional models, rigorous analyses using Computational Fluid Dynamics (CFD) simulations were performed. A full 3-dimensional CFD model of the flowline-riser system was used in FLUENT with the volume of fluid (VOF) method to predict both steady-state and transient behavior. In all cases simulated, CFD results compared well with the experimental data.
A Simplified Approach to Modeling Long-Term Monopile Serviceability with Finite Element Analysis
Authors: Edgers Lewis , Bradshaw Aaron S. , Ebin Daniel
Published: May 2013

Monopile foundations for offshore wind turbines are subject to many cycles of large horizontal loads and overturning moments. This paper describes the foundation analysis of a wind turbine foundation typical of 3 to 5 MW units that have already been constructed in the southern North Sea and are being proposed offshore in the northeastern United States. The foundation consists of a 5.1 m diameter monopile driven 26 m below the seafloor into medium dense sand. The environmental loads were highly idealized, represented as a 6 MN vertical force and a 4 MN horizontal force applied 30 m above the seafloor. The effects of one cycle of monotonic loading and up to 107 cycles of long-term cyclic loading were computed. The analyses were performed using a widely available three-dimensional finite element program, incorporating an implicit method to model the soil modulus degradation and increased strain as a function of the number of loading cycles. The computations showed that the monopile displacements and rotations accumulate with additional cycles of loading, almost doubling after 107 cycles. This suggested that a monopile that rotates within tolerances after one cycle of load, approximately 0.25°, may accumulate unacceptably high deflections and rotations over its design life. The paper demonstrated the use of commercially available software as part of a method to model the response of a wind turbine monopile foundation to long-term lateral cyclic loading.

Introduction

A monopile is a large-diameter, open-ended pipe pile driven into the seafloor, connected to a wind turbine tower by means of a transition piece. The tower supports the turbine nacelle and the rotor. Monopiles must withstand the forces from wind, waves, ice, currents, and vessel impacts over the life of the turbine, which can be up to 50 years. The design of the monopiles must consider the response of the supporting soil to the long-term applied cyclic loadings. As such, an accurate method to calculate the lateral deflection and rotation of the pile due to cyclic loading, including the effects of changes in properties of the supporting soil, is needed. This study is concerned with the effects on offshore wind turbine foundations of high cycle, low amplitude loading that will induce small strains. It is assumed that the cyclic loading has low strain-amplitude, less than 10-3 (Whichtmann et al., 2010), with as many as 107 cycles over the lifetime of the offshore wind turbine (OWT), consistent with the observations by LeBlanc et al. (2010).

Monopiles are generally installed in water depths of less than 30 m (Malhotra, 2010). At greater depths, they become excessively large and uneconomical. Critical elements of their design include the loadings and performance requirements or limit states. One of the serviceability limits conditions is that a monopile cannot exceed a permanent rotation typically of 0.5° at the mudline level over its design life (Malhotra, 2010).