bluuebunny/crossref_metadata_2025_split huggingface dataset:
Contractors Under SEMS: Understanding Customer Requirements
Authors: Wells Ken 
Published: May 2013

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.