bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Implementation of a High Temperature and Salinity Tolerant Kinetic Hydrate Inhibitor to Replace an Existing, Ten-Year Continuous Application
Authors: Webber Peter , Morales Noah , Madden Audrey 
Published: June 2014

Abstract
An operator in the North Sea has successfully employed a kinetic hydrate inhibitor (KHI) for over a decade. This operator produces through two 13 mile flowlines, separated into wet gas and fluids, to a multiphase host facility. At this host facility, the two production streams recombine in a slug catcher upstream of the separation system. The wet gas line operates continuously under conditions of hydrate stability requiring the use of a KHI. As additional wells have been tied into the subsea production stream, conditions have changed necessitating advancement in KHI technology.
The new production introduces formation water of considerable salinity into the production stream as well as increasing the temperature of commingled fluids in the slug catcher. As KHI polymers possess inverse solubility profiles with respect to temperature and salinity, gunking was frequently observed in the production slug catcher. The precipitated polymer, in addition to sand and organic solids in the system, caused frequent upsets and deferred production. Accordingly, a KHI polymer with improved solubility profile (cloud point) was targeted for this application. The KHI performance and compatibility with incumbent corrosion inhibitor were confirmed and optimized to a 50% reduction in treatment rate by autoclave experiments under the established qualification protocols. Solubility experiments confirmed the compatibility of the new KHI with the expected temperature and salinity parameters of the full production.
This paper provides a detailed history of this 10+ year application, recent qualification process, and field application of this new KHI offering.
Failure mechanism of cutting submerged frozen clay in an arctic trenching process
Authors: Liefferink D.M. , Grima M. Alvarez , Miedema S. , Plat R. , Rhee C. van 
Published: June 2014

Abstract
Pipelines in Arctic regions are at risk of being damaged by gouging ice masses(gouge depths of 5m-8.5m). As protection, pipelines can be buried in trenches. When trenching is performed in Arctic soil, subsea permafrost may be encountered. Subsea permafrost is found in the continental shelves of the Arctic seas at water depths up to 100 m. The upper units (the first 1m to 100m)generally comprise thawed layers, which act as an insulating layer to the permafrost below. Layers of thawed clayey soil have better insulating properties than those of coarser material. Consequently, more shallow subsea permafrost, which is located in the top 10 m of the seabed, is most likely to be encountered in clayey soils. Ground deformation caused by seabed ice gouges will demand that pipeline trenches be excavated up to 10 m deep. This leads to the conclusion that permafrost in arctic areas can be encountered while trenching, mainly while excavating clayey soil.
For proper design and construction of efficient subsea excavation equipment (subsea trenchers) thorough knowledge of physical characteristics of permafrost is necessary, and failure mechanisms, cutting forces and other important parameters should be assessed. A literature review identified that knowledge of excavation in permafrost is limited. Therefore Delft University of Technology and IHC Merwede joined forces to fill the knowledge gap.
The main goal of this research is to identify the governing failure mechanism of frozen clay. Knowledge of the failure mechanism of a material under certain cutting conditions leads to the ability to calculate cutting forces in similar conditions and to determine the required cutting energy per cubic meter of material, which is an essential parameters during design and operation of arctic trenchers.
This study found that frozen clay has a tensile and compressive strength comparable to soft rock. During the process of freezing, ice lenses are formed in clay, making the material inhomogeneous and anisotropic. The failure mechanism of frozen clay in an arctic trenching process is studied experimentally by means of a linear cutting test setup. Samples of undisturbed Dutch river clay were excavated, frozen and cutin submerged conditions at near atmospheric pressure. The observed failure mechanism of submerged frozen clay appeared predominately tensile brittle. Further research has been planned to obtain more accurate characteristics by using clay from Arctic areas, and conducting experiments carried under higher hydrostatic pressures.
Design Validation of the Caesar-Tonga Steel Lazy-Wave Risers using Field Data
Authors: Kumar Das Ajoy , Balch Erin , Group Kenny Wood , Fowler Sam , Yiu Flora , Beattie Michael 
Published: June 2014

Abstract
Offshore production risers are generally designed considering a large margin of conservatism to account for the uncertainty in the design parameters and to ensure robust design. As the Oil & Gas Industry is advancing toward ultra-deepwater there may be a necessity to adopt new technologies and riser configurations to develop the field. Project teams may elect to quantify the degree of conservatism in the designs as an additional measure to improve confidence in the safe and reliable service over the life of the field. Such validation provides confidence in the design performed based on theoretical concepts and software predictions.
This paper presents a novel approach that has been undertaken to validate the design of the Caesar-Tonga Steel Lazy Wave Risers (SLWR) tied back to the Anadarko Petroleum Company (APC) operated Constitution Spar located in the Green Canyon Area of the Gulf of Mexico. These risers represent the first application of the steel lazy wave riser technology in the Gulf of Mexico, and it was the first such application tied back to a spar platform.
The procedure is based on the monitoring of motion and strain data measured at critical locations along the risers. The measured data is post-processed to identify significant riser motion events that occurred during the observation period. Met- ocean data during this time period is also evaluated to correlate back to the riser motion events. Vessel motions and current data corresponding to these identified events are used to drive a Finite Element (FE) model of the riser, and the corresponding riser motions and strains are calculated. The calculated motions and strains are compared with measured motions and strains to provide confidence in the design methodologies. The procedure as well as the results of the comparison between predicted performance and measured performance is discussed in detail in the paper. The procedure can be applied for design validation and performance and integrity assessment of newly-built or existing risers.
Design Method and LRFD for HPHT Subsea Equipment for Extreme and Survival Load Conditions
Authors: Pathak Parth D. , Taylor Samuel L. 
Published: June 2014

AbstractThe current API standards and technical reports for Subsea Equipment which fall under API SC 17; especially relevant to Subsea Trees and Wellheads; do not particularly provide the design methods for Extreme and Survival load conditions. As the industry continues moving forward with the High Pressure High Temperature (HPHT) application it has increased the attention towards safety, and design precautions have the utmost priority. Hence, the industry is redoubling its focus on the Extreme and Survival load conditions for the Subsea Equipment, especially for HPHT conditions.The recently published API TR 1PER15K-1 and in-work API TR 17TR8 address the design methods for Subsea HPHT equipment but do not specifically provide the design methods for Extreme and Survival load conditions. API RP 17G, recommended practice for completion/workover risers addresses these loading scenarios by providing the design condition factors, but suggests testing for plastic collapse load. API RP 2RD, recommended practice for Design of Risers for Floating Production Systems and Tension-Leg Platforms, recommends the consideration of these load conditions, but does not provide specific design rules.This paper posits a design method for Subsea Equipment governed by API SC 17 particularly for API 17D, Subsea Trees and Wellhead under Extreme and Survival Load conditions. The proposed method combines the Elastic-Plastic design analysis method from ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, Div. 2 and 3 and the API RP 17G Structural Resistance Methods. It combines the API RP 17G Design Condition Factors with the ASME Section VIII BPVC Div. 2 and 3, Load and Resistance Factor for Design (LRFD) to establish new LRFDs for Extreme and Survival Load conditions. Fatigue life estimation is also addressed for these conditions. An example analysis of a Subsea Tree component is reviewed, evaluating its combined load capacity for normal, extreme and survival conditions. Additionally, the review includes the fatigue life cycle estimation for this component.
Evolution of High-Pressure, Flexible-Capacity Air Compressors To Convert Smaller Vessels for Use in Marine Seismic Exploration Industry
Authors: Dorran Dan 
Published: June 2014

Abstract
The development, manufacture, maintenance and service of high-pressure compressors that can satisfy environmental, safety and reliability demands throughout offshore oil and gas discovery and production processes present manufacturers with significant challenges. Specialized, rent- and lease-ready compressors must fit the limited working environment of smaller vessels in seismic exploration applications yet have the reliability of a fixed, stationary compressor. Manufacturers are also challenged by the slow development of new acquisition technology to address air gun seismic concerns arising from marine life health issues.
Input from endusers and air gun suppliers, and commitment to the customer by the compressor manufacturer, will match forecast demand. This paper will detail the evolution of this class of compressor and the manufacturing challenges it entails.
Risks and Impact Assessment for Deepwater and Ultra-Deepwater Gulf of Mexico Resources
Authors: Rose K. , Aminzadeh F. , Ghanem R. , Thimmisetty C. , Jabbari N. , Khodabakhshnejad A. , Sim L. , Bauer J. , MacKenzie Mark-Moser , Disenhof C. 
Published: June 2014

Abstract
Recent natural and anthropogenic events, such as Hurricanes Katrina and Rita and the Deepwater Horizon oil spill, have identified significant gaps in our ability to predict risks associated with offshore hydrocarbon production as well as our capabilities to respond to deleterious events of varying scope, magnitude, and duration. As offshore hydrocarbon development in the Gulf of Mexico continues to push into new territory, there is a need to develop computational tools that enable the rapid prediction of outcomes associated with unexpected hydrocarbon release events from deepwater and ultra-deepwater systems in the Gulf of Mexico. To date, no comprehensive system-wide tool exists that can simulate the complexities of engineered-natural systems and provide the baseline data that is required to drive the simulations.
To address this gap, we are developing the Gulf of Mexico Integrated Assessment Model (GOM IAM), the first coordinated platform that will allow for independent, rapid-response, and science based predictions providing the capabilities to assess risks and potential impacts associated with deep and ultra-deep water drilling in the Gulf of Mexico. This predictive model and its analyses allow for the assessment and quantification of risks and environmental impacts from deepwater and ultra-deepwater oil and gas drilling and production, as well as provide a robust tool and database that can provide crucial information necessary for the response and recovery following future loss of control events. Once the GOM IAM is developed, it can be utilize to:identify potential risks;identify technology gaps,improve our understanding of the degree of uncertainty relative to key systems and interactions associated with deep and ultra-deep water offshore hydrocarbon development to promote safer development and operations, and iv) run scenarios to serve as a baseline rapid response tool for any future oil spill events.
Pumping Hydrate Slurries in the Arctic: A Different Perspective
Authors: Abulnaga Baha , Prescott Neal , Mantha Aishwarya 
Published: June 2014

Abstract
The formation of hydrates in oil-dominated production systems is a hazard that may potentially lead to the plugging of pipelines in deepwater and Arctic environments. Anti-agglomeration additives have been used in the field as a mitigation strategy to prevent hydrates from growing into plugs. Studies have dealt with the ability of certain crudes to form stable water in oil emulsions. These stable emulsions have been proposed to be made in-situ with or without chemical additives. In recent years, an emphasis has been made to understand the mechanism of formation of stable hydrates that can be transported in a slurry form. In order to achieve this in the field, extensive work has been done to mathematically model hydrate formation and agglomeration with the aim to understand transportation of hydrates as a slurry mixture without plugging. One critical aspect to the slurry mixture is the complex slurry rheology which is dependent on the volume concentration of solids, that can include both hydrates and precipitated asphaltenes, but is further complicated by the crystallization of hydrates by contact with a water droplet, and the growth into hydrates aggregates by agglomeration.
The mining industry has been able to transport complex mixtures and operate without plugging in pipelines covering over distances from a few kilometers to 1000 km. The viscosity for non-Newtonian laminar flows is often dependant on the shear rate and volume concentration of solids. The yield stress for a Bingham mixture is controlled by additives. In recent years, the oil sands industry has developed better knowledge of the pumping of oil, bitumen mixtures often called "oil sand froth". Learnings have included velocity induced lubrication of pipe walls by forming a water layer or "self-lubricated" pipe flow, achieving lower friction than predicted by traditional models of viscosity mixing between two liquids.
While the mechanisms of hydrate formation and agglomeration are different from traditional mining slurry, there are numerous practices from mining that can be applied to the pumping of stable hydrates; such as control of additives, control of shear rate, transition from a laminar to a turbulent regime, and self-lubrication of water-oil mixtures. In this paper the authors review some of the issues of hydrate formation, explore some efforts by researchers to understand hydrate-based slurry mixtures and propose some comparisons with the handling of mineral based slurry mixtures and nuclear waste slurry mixtures to formulate a concept of stable flow without plugging.
System Response During Short- and Long-Term Gas Production from a Gas Hydrate Deposit at the Site of a Planned Field Test in the Ulleung Basin of the Korean East Sea
Authors: Moridis George J. , Kim Jihoon , Reagan Matthew T. , Kim Se-Joon 
Published: June 2014

Abstract
We investigate by means of numerical simulation the coupled flow and geomechanical system behavior during gas production from an oceanic hydrate accumulation at the site of a planned field test at the Ulleung basin in the Korean East Sea. We study the system response at two time scales: a short period (14 days) that corresponds to the duration of the planned field test, and a prolonged production period that continues to the point of hydrate exhaustion and/or reservoir abandonment. The data describing the geologic model and the system properties were obtained from earlier geophysical studies and the analysis of cores obtained from experimental wells at several locations in the Ulleung Basin. Gas hydrate accumulations at this site typically occur in deep water (2157 m) but close to the ocean floor (with their tops 140 mbsf), and are usually characterized by alternating mud (nearly hydrate-free) and sand (hydrate-rich) layers. The layered stratigraphy and the presence of mud layers preclude the use of horizontal wells and necessitate vertical wells. The analysis of the short-term production tests focuses on the expected gas production rate and the possibility of subsidence during the limited time of the planned test. The long-term study aims to address the issue of feasibility of long-term production from the hydrates at the test site in terms of production rates and the geomechanical stability of the well assembly and of the reservoir. We investigate several well operation regimes. We evaluate the sensitivity of the system to various flow, thermal, and geomechanical properties, and we account for the interdependence of flow and geomechanical properties. We estimate possible subsidence under production and we determine the conditions that have the potential to lead to wellbore and formation failure, thus defining the envelope of well operations and production conditions that maximize safe gas production.
API Subcommittee 17 "Subsea Production Equipment" - Development of Industry Standards for Subsea Systems
Authors: Bednar John M. 
Published: June 2014

The use of subsea production system technologies to produce hydrocarbons from deepwater environments worldwide continues to grow dramatically. Accordingly, industry's ability to utilize standardized subsea equipment designs and procedures can enhance the ability to do so in a safe, cost-effective, and reliable manner. API Subcommittee 17 " Subsea Production Equipment" (SC17) has maintained an evergreen effort to develop and maintain these subsea standards by providing the following:? A forum for industry discussion? A platform on which to foster consensus? Task groups that volunteer to generate respective documents? Multi-disciplined support from industry experts? An interface network with regulatory agencies to facilitate subsequent acceptance.
The continually evolving nature of subsea-related technologyposes a challenge to the SC17 membership to identify the need for new standards as the individual subsea-related technologies mature.
Provided below is an overview of the suite of documents that reside within the SC17 portfolio of standards, with special emphasis on those documents that are currently evolving. Also provided is a description of the API organization and processes that are employed in developing new standards and regularly updating/revising existing standards.
Lateral Buckling of Pipelines in Deepwater GoM
Authors: Hoor Azadeh , Singh Shilpa , Baxter Finlay , Jesudasen Sandeep , Zeng Wilson , Simpson Neil , Watson Ryan , Krishnappa Nag 
Published: June 2014

Abstract
The majority of the deepwater pipelines operating in the Gulf of Mexico (GoM) carry hydrocarbons at a high pressure and temperature resulting in the system's thermal expansion. In order to relieve the high stresses due to thermal expansion, these pipelines are designed to use buckle triggers in order to buckle laterally at pre-determined locations. Since these assets are expected to last a few decades, it is imperative that a robust long-term integrity management program is in place to effectively operate these pipelines, monitor their long term performance, verify design assumptions and thus, reduce any potential risks.
As a part of BP's comprehensive In Water Integrity Management (IWIM) program, three pipelines were surveyed during a 2012 Multi-Beam Echosounder (MBES) survey campaign. The surveys checked for buckle initiation, buckle locations and obtained accurate buckle shapes to allow subsequent integrity assessments to be performed. Ten out of ten planned buckles formed across the three operational pipelines; a mixture of sleepers and buoyancy modules initiated these buckles at pre-determined locations. Smaller buckles were also observed at unplanned locations in the pipeline system. These pipelines terminate at subsea structures situated at the ends of the pipelines. In order to track the pipeline's long-term global movement; the end displacements at these structures were recorded as well.
During its operation, a pipeline system will be shut-down and re-started multiple times, thus creating a series of thermal cyclic loadings. In order to ascertain the long-term performance of the pipelines under such sustained thermal loading cycles, a Finite Element (FE) model is built using the pipeline data, seabed bathymetry and other environmental conditions. The FE model is calibrated using the recorded 2012 MBES survey in-service pipeline lateral buckling profiles. The calibrated FE model generates axial stress ranges at critical locations (buckle crown); these stress ranges are subsequently used to perform fatigue analyses. The estimated fatigue damage is used to forecast the pipelines' long-term fatigue performance, which will determine the future inspection and monitoring plans.
This paper presents an overview of the 2012 MBES Survey conducted on three of BP's operational pipelines as well as the subsequent FE and fatigue analyses performed to assess the long-term integrity within lateral buckles.
Efficient Drilling of Ultra-HPHT Wells in the Gulf of Thailand
Authors: Araujo Joy , Kaotun Keittipong , Dumrongthai Panupun , Adrian A 
Published: June 2014

Development of gas fields in the Gulf of Thailand requires drilling and production from reservoirs that are at static temperatures above 200 °C. Safe and economic production from these ultra-high-pressure/high-temperature (HP/HT)fields is crucial to deliver on gas contracts that support the region's economic activity. The operational limit of equipment used to drill these wells, such as measurement-while-drilling (MWD) and logging-while-drilling (LWD) tools, is 175 °C. If the electronic components, elastomers, and sensors in these tools are exposed to high temperatures, the reliability of the tool is significantly decreased, and therefore it requires extensive time-consuming maintenance.
The lack of technology enabling MWD/LWD tools to operate reliably in a high-temperature environment increases well construction risks. Important questions such as " can we reach the target successfully" or " are the anti-collision requirements fulfilled" cannot be answered reliably. High-temperature equipment is therefore key: it allows maintaining the directional trajectory as well as obtaining real-time downhole measurements to confirm successful well placement.
New technologies have been developed and qualified during the last decade that enable electronics, sensors, and elastomers to operate in these HP/HT environments with the same level of reliability as that in what is nowadays considered " normal environmental conditions." Anew MWD tool has been designed utilizing these novel technologies. The tool can operate reliably at 200 °C and 207 MPa, providing real-time direction and inclination surveys, azimuthal gamma ray, annular and internal pressure while drilling, and shock and vibration measurements.
An operator in the Gulf of Thailand used this new MWD technology to drill wells in these ultra-HP/HT reservoirs without the need to stop operation due to temperature limitations. Savings of one-half day per well have been achieved. Reliability and maintainability were proven by executing four runs above 180 °C, where the maximum operating temperature recorded by the tool was 193 °C and total operating hours without the need for maintenance between runs was more than 250 hours. With 50 to 75 wells per year to be drilled above 175 °C, this operator now has access to a new workflow that can save 25 to 37 days of drilling per year. These time savings translate into considerable savings in rig spread rate and the ability to bring production online earlier.