bluuebunny/crossref_metadata_2025_split huggingface dataset:
Spectral and Cycle-Counting Fatigue Damage Estimation Methods for Steel Catenary Risers
Authors: Power Thomas L. , Maniar Dilip R. , Garrett David L. , Phifer Ed H. , Vogiatzis John P. 
Published: October 2008

ABSTRACT
Estimating fatigue damage under wind-driven sea loading is of primary importance in the design of steel catenary risers (SCRs) serving floating hosts. For design, the wind-driven sea is modeled as a stationary random process. The resulting dynamic stress in the SCR is also a stationary random process. Spectral methods provide closed-form fatigue damage estimates in terms of statistics for stationary random stress processes. Rainflow cycle counting provides an alternative damage estimation approach that is generally applicable and requires simulation of stress time series. The rainflow approach requires more computation than spectral methods. Damage estimates using the rainflow method may be lower than spectral damage estimates; however, a substantial amount of simulation may be required to quantify the difference.
This paper considers fatigue damage in SCRs attached to both tension-leg platform and semi-submersible hosts. Spectral and cycle-counting estimates are generated and compared. Accuracy of the estimates is discussed, and guidelines for damage estimation are presented. It is demonstrated that the differences between spectral and cycle-counting estimates of lifetime fatigue damage arise primarily from assumptions made regarding the spectral shape of the stress processes of interest.

INTRODUCTION
SCRs accommodate floating host motions through self-flexure. Since host motions persist over the lifetime of the SCR, the task of estimating fatigue damage under wind-driven sea loading is of primary importance in the design of SCRs serving floating hosts. This paper investigates three basic approaches to this task:Spectral damage estimation using results of frequency-domain analysis (Rayleigh and bimodal)Rainflow cycle counting of stress time histories obtained from time-domain analysisRainflow cycle counting of stress time histories created from frequency-domain analysis results
Cycle-counting techniques require the simulation of stress time histories. The accuracy of the resulting fatigue damage estimates depends on the amount (and accuracy) of simulation. Practical computational efficiency considerations have led to the development of spectral methods that match cycle-counting damage estimates for certain forms of stress spectra. Spectral fatigue damage estimation procedures represent powerful and efficient tools for estimating fatigue damage caused by stationary random stress processes because they relate fatigue damage to the statistics of the stress process using a closed-form relationship and do not require creation of stress time histories. The spectral approach will overestimate damage (relative to cycle-counting estimates) when the spectral shape of the process is more broad-banded than the form assumed in developing the spectral procedure.
Two Field Studies Demonstrate That New LDHI Chemistry is Effective at High Water Cuts Without Impacting Oil/Water Quality
Authors: Alapati Rama R. , Lee Jeremy , Beard David 
Published: October 2008

Abstract
The second generation new anti-agglomerate low dosage hydrate inhibitor (AA-LDHI) chemistry is greater than 99% oil soluble and has proven performance to prevent hydrate blockages in both wet-tree and dry-tree applications. This new chemistry has been successful in field applications of water cuts up to 80%. The first generation AA-LDHIs are known to perform at low water cuts, such as less than 40%, and cause poor produced oil/water quality.
Hydrate crystals formed during a flowing condition and/or shut-in condition could form a hydrate blockage and result in a production shut-down. The remediation of such a hydrate plug involves lost revenue, risk for the safety of the personnel and a potential negative impact on the environment. The subcooling involved in deepwater applications is usually higher than 25°F, which would require the use of an AA type LDHI which can protect the production systems up to 50°F subcooling.
Two case studies, one for a wet-tree well and one for a dry-tree well will be presented. The results show a significant decrease in the total oil and grease (TOG) levels in the produced water and percent BS&W in the produced oil. The data will include the performance results, TOG data for long periods of time, toxicity/environmental testing data and shut-in/restart history.
A major benefit of this new chemistry is that the produced water quality is improved compared to the first generation chemistry in field applications. The oil-soluble nature of the new chemistry makes the produced water less toxic and can reduce the chemical costs involved in produced water polishing. The new chemistry can extend the production life of the wells by allowing it to produce at higher water cuts. Given the high crude oil sale price, the new chemistry could add significant value to the producers while not affecting the produced water quality.

Introduction
Hydrate management is a critical aspect of deepwater oil and gas production facilities. Producing wells and flowlines are susceptible to hydrate formation and ensuing blockage if they meet certain criteria. These criteria are the presence of natural gas and water at elevated pressures and low temperatures. The temperature below which hydrates can form increases with increasing pressure and can be as high as 86°F (Kelland 2006). Once formed, the hydrate blockage can take anywhere from a couple of days to months to dissociate, resulting in decreased revenue to the producer due to lost production and other costs associated with the dissociation. The remediation of a hydrate plug poses a significant risk to the safety of the personnel involved and for a potential negative impact on the environment. Dissociating a hydrate plug can cause pipeline/flowline rupture which could injure personnel and release hydrocarbons into the environment.
Four Critical Needs to Change the Hydrate Energy Paradigm From Assessment to Production: The 2007 Report to Congress by The U.S. Federal Methane Hydrate Advisory Committee
Authors: Sloan E. Dendy , Brewer Peter , Charter Richard , Dutta Nader , Johnson Arthur , Jones Emrys , Juenger Kimberly , Kastner Miriam , Mahajan Devinder , Masutani Stephen , Swenson Robert , Whelan Jean , Wilson Scott , Woolsey Robert 
Published: October 2008

Abstract
This work summarizes a two-year study by the U.S. Federal Methane Hydrate Advisory Committee recommending the future needs for federally-supported hydrate research. The Report was submitted to the US Congress on August 14, 2007 and includes four recommendations regarding (a) permafrost hydrate production testing, (b) marine hydrate viability assessment, (c) climate effect of hydrates, and (d) international cooperation.

Introduction
A secure supply of natural gas is a vital goal of the U.S. national energy policy because natural gas is the cleanest and most widely used of all fossil fuels. The relative cleanliness of natural gas, (with the lowest CO2 emission per unit of heat energy of any fossil fuel) in combination with the magnitude of potential reserves, dictates that a comprehensive assessment of domestically available resource be undertaken and included in the national portfolio. Both as a fuel and a feedstock, a secure and reasonably priced supply of natural gas is important to industry, electric power generators, large and small commercial enterprises, and homeowners.
Because each volume of solid gas hydrate contains as much as 164 standard volumes of methane, hydrates can be viewed as a concentrated form of natural gas equivalent to compressed gas but less concentrated than liquefied natural gas (LNG). Natural hydrate accumulations worldwide are estimated to contain 700,000 trillion cubic feet (TCF) of natural gas, of which 200,000 TCF are located within the United States. Compared with the current national annual consumption of 22 TCF, this estimate of in-place gas is enormous. Clearly, if only a fraction of the hydrated methane is recoverable, hydrates could constitute a substantial component of the future energy portfolio of the nation (Figure 1). However, at the present time recovery poses major technical and commercial challenges.
Such numbers have sparked interest in natural gas hydrates as a future potential, long-term source of energy, as well as concerns about any potential impact the release of methane from hydrates might have on the environment. Other countries that import most of their energy, such as India and Japan, are outspending the United States on hydrate science and engineering R&D by an order of magnitude, may bring this resource to market as much as a decade before the United States. It is clear, however, that verifying the role of methane hydrates in global climate change is critical because of the fact that methane has a greenhouse warming potential 21 times that of CO2. A better understanding of the pivotal role that hydrates might play in the global climate could influence U.S. policy choices related to global warming mitigation decisions.
Geomechanics in Integrated Reservoir Modeling
Authors: Settari Antonin , Sen Vikram 
Published: October 2008

Abstract
This paper will discuss the current state of reservoir geomechanics and consider several areas of reservoir development and management where geomechanical influences are important. In order to better integrate our workflows, coupled simulation is often used to exchange parameters between individual modules that are typically run in standalone mode for reservoir flow simulation, seismic modeling or geomechanical modeling. This paper will discuss coupled geomechanics and flow simulation to illustrate several impacts of reservoir depletion (e.g. compaction and subsidence, stress arching in the overburden and casing shear in the wells) and examine the connection between geomechanics and geophysics and areas where coupling of these disciplines can benefit exploration and production. Two generic examples are presented - one representing North Sea chalk reservoirs and the other representing deepwater turbidites.
Reservoir compaction and resulting subsidence are well known examples of geomechanical behavior. During depletion, the reservoir pressures decrease and effective stresses increase. The rocks deform through a combination of elastic (recoverable) and inelastic (permanent) strain, with plastic deformation occurring primarily as the stresses increase beyond the compaction limit or "collapse" stress. The deformation creates a "compaction drive" (additional pressure support) in the reservoir that can improve recovery. However, one must also deal with the undesirable effects - the environmental impact of subsidence, possible fault reactivation, and integrity of wells crossing faults etc. - and geomechanics allows us to evaluate these effects.
In other applications, incorporating geomechanics in the interpretation of repeat 4D seismic surveys improves our ability to isolate and resolve the signatures of variations in fluid saturations. Finally, the primary concern in drilling and completion engineering is wellbore stability during drilling and well integrity during the producing life of the well. The heterogeneity of stress changes in layered reservoirs and overburden due to depletion-induced differential reservoir compaction poses specific technical challenges e.g. casing shear deformation - and geomechanics plays an important role in modeling studies associated with the evaluation of such challenges.
Compact Electrostatic Separation Process
Authors: Taggart Davis Lew , Sams Gary W. , Wallace Harry G. , Manen David 
Published: October 2008

Abstract
Crude oils from mature fields are routinely associated with high water cuts and high operating costs. High water cuts increase the process heat requirements, chemical requirements, overall vessel volumes, equipment footprints and weights. If a significant quantity of water can be removed at lower temperatures, the subsequent production equipment size, weight and cost can be reduced or eliminated. A method to accomplish this ambitious separation goal is being developed by NATCO.
This separation process includes a compact treatment vessel that combines electrostatic coalescence and separation in either a series or parallel process. The vessel design permits both capacity expansions as well as performance improvement by the addition of more coalescing / separating stages. The overall oil-water separation process includes a series of processing steps for:Free gas removalPreliminary free-water separationElectrostatic water coalescenceOil dehydration, andSeparated water treatment.
This paper will concentrate on steps 3 and 4 of this 5-part scheme.
In laboratory equipment using a pipe vessel, NATCO has processed up to 3000 bfpd/ft2 of fluids and achieved an 85 - 95% water removal from oil streams containing as much as 40% water. This compact separation technology has the potential to be applied to either surface or subsea facilities. Using this compact electrostatic separation technology in a subsea environment can provide huge process and economic advantages in deep water applications.

Introduction
Weight and space are at a premium in the offshore environment. The compact electrostatic separator combines several advantages to work well offshore. The separator vessel is " pipe size??; therefore it has a small footprint and weight. In addition the operation is simple with minimal and conventional controls.

Description of Electrostatic Technologies Evaluated

Alternating Current (AC)
Alternating Current (AC) is an older Electrostatic Dehydration technology. The AC process used here applies an alternating electric field at 60 Hz. The voltage can be varied to optimize the emulsion oscillation, which causes the water droplets to deform and accelerates their coalescence. See Figure 1.

Bimodal AC
Bimodal AC is a newer technology that utilizes a higher AC carrier frequency. The potential is modulated between lower and higher voltages at a slower frequency. This additional modulation facilitates additional drop coalescence.
Overcoming Weight Transfer Challenges in Complex, Shallow, Extended Reach Wells on Alaska's North Slope.
Authors: Thomas Randy Lee , McKeever Stephen O. , Hartwig Dennis D. , Egedahl David B. , Patton John , Holtzman Keith , Smith Lee 
Published: October 2008

Abstract
The complex wells currently being constructed to develop the West Sak Field on the North Slope of Alaska (Figure 1) are approaching the limits of extended reach drilling technology (Figure 2). Due to the shallow vertical depth and long horizontal departure of these wells, the ability to effectively transfer weight while drilling and running tubulars can be very challenging. This paper discusses the reasons those challenges exist, and the tools, techniques and learnings employed over the past seven years to successfully solve weight transfer challenges in this remote, environmentally sensitive area, including steerable motor assemblies, rotary steerable drilling assemblies, collaborative planning, on site drilling engineers, torque and drag reduction devices, fluid additives, vibrating down hole tools, and liner running with multiple trips. These learnings enabled the recent drilling and completion of a West Sak well with a total measured depth of 19,750 feet at a vertical depth of 3,055 feet. This well, with a horizontal departure of 18,472 feet and two laterals with lengths in excess of 7,500 feet, has a departure to depth ratio in excess of six.

Background
The West Sak field is within the Kuparuk River Unit on the North Slope of Alaska (Figure 1). The West Sak heavy oil sands contain highly viscous oil due to the low gravity of the crude (10 to 22 degrees API) and the low reservoir temperatures (caused by both the extreme northern latitude and the shallow (3,000 to 4,000 vertical feet) burial depth below 1,800 feet of permafrost in the overburden.) The West Sak reservoir has three primary sandstone targets: the " A2??, the " B?? and the " D?? intervals. The West Sak sands are " very-fine?? to " fine?? grained, single and amalgamated sandstone/siltstone beds. Geologic challenges while drilling include numerous fault crossings along the wellbore (Figure 3) as well as random encounters with calcite-cemented spheroids, also known as concretions (Figure 4). The concretions are much harder than the reservoir sand, having compressive strength of 25,000 pounds per square inch (psi) versus 500 psi for the reservoir sand. These concretions drill much more slowly than the adjacent sand which accelerates wear on the bit, the bottom hole assembly, and the drill string. This difference in hardness can also cause the drill bit to deflect off of the concretions resulting in unwanted severe doglegs. Such doglegs make it difficult to maintain directional control, increase torque and drag, and can cause down hole tool damage.
Geohazard Challenges of the Woodside OceanWay LNG Development, Offshore Southern California
Authors: Hogan Phillip Joseph , Lane Andrew , Hooper James , Broughton Aaron , Romans Brian 
Published: October 2008

Abstract
Geotechnical data, geochronologic data, and high resolution seismic data collected for Woodside's OceanWay Secure Energy LNG project allow an improved understanding of the tectonic and sedimentary processes in Santa Monica Bay and Basin, and identification of geologic hazards.
The proposed facilities are located in a deepwater basin near the collisional transform boundary of the Inner California Continental Borderland (ICB) Province with the Western Transverse Ranges (WTR) Provinces. This area is characterized by complex interactions between blind thrust faults underlying the Los Angeles Basin and strike slip faults related to the northwest motion of the Pacific Plate relative to North America. Active faults and folds crossing the proposed pipeline route present a ground rupture and deformation hazard on the continental slope.
Active sediment transport processes and high sediment accumulation rates are documented on Hueneme submarine fan in Santa Monica Basin (SMB). High-resolution seismic-reflection profiles across Ocean Drilling Program (ODP) borehole 1015 in the basin plain provide a well-dated chronostratigraphic record. Turbidity currents in Santa Monica Basin are sand-dominated, and have increased in sediment volume per event in the latest Holocene. Whilst some turbidites likely result from El Niño-Southern Oscillation (ENSO) storm events, others are believed to have been triggered by seismically-induced strong ground motions.
The potential exists for surface folding and fault rupture, seismically induced strong ground motions, and turbidity currents to affect the proposed pipeline within the lifetime of the project. These geohazards will be mitigated through appropriate analyses, risk studies, and engineering design of the OceanWay facilities, allowing safe and secure importation of natural gas to the West Coast of the USA.

Introduction
Proposed LNG developments in deepwater offshore the West Coast of the United States face new challenges, both on technical issues such as facility engineering and from natural geologic processes. Many recent high-profile deepwater developments continue to encounter major geological hazards (geohazards) on an increasing scale worldwide.
Woodside Natural Gas, Inc. (Woodside) proposes to import LNG to Southern California via a Deepwater Terminal in SMB. SMB is one of several basins in the ICB, a tectonically active area along the plate boundary between the Pacific and North American Plates (Figure 1). A 56-km submarine pipeline will bring the gas ashore via a horizontal directional drill borehole at a landfall in the coastal portion of the Los Angeles Basin (Figure 2). Detailed feasibility and siting studies were performed in 2005 and 2006 to assist in the selection of the optimal location of the OceanWay Project. This paper summarizes geohazards identified during the 2006 geophysical and geotechnical surveys.
Integration of Solid Modeling Into Real-Time Navigation
Authors: Davis Jonathan Peter , Beck Richard D. , Butcher Ron , Nodine Mark  K. , Clarke James P. , Simpson Richard , Benitez Luis , O Leary John E. , Smith Perry 
Published: October 2008

Abstract
The Downed Platforms project deals with seven platforms containing 59 wells which were toppled during Hurricane Katrina in water depths ranging from 86 to 135 feet. Visibility at these depths in these locations is limited at best. As part of an effort to extend the ability of remote operated vehicles (ROV) to work in low visibility, solid models of downed platforms were built and were exported into a form which could be used in the real-time navigation system for offshore vessel, ROV and diving operations. The paper will discuss:Zero Visibility Operations - The Initial ConceptSubsea Model DevelopmentNavigation System DevelopmentIntegrating the Model with Navigation for Field DeploymentROV Control System IntegrationModel Maintenance
The paper will describe techniques which could be applied to subsea navigation in complex environments, where model based positioning can deliver operational efficiencies. Key elements of this system are the structural model and the deployment of navigation system components to ensure accurate and high update rate positioning.
The paper will present results from various stages of field work. While many technologies presented in the paper are pre-existing, the integration of all systems to enable continued operations in zero visibility represents a new application. The application of these technologies increased the operating envelope for the ROV, enhanced co-ordination and safety of activities in the field and in the project and presented significant advances in subsea positioning, control and navigation.

Background
The 2005 hurricane season was the most active on record and hurricanes Katrina and Rita inflicted major damage to Gulf of Mexico (GoM) production facilities on the outer continental shelf (OCS). Seven platforms were completely destroyed in the Grand Isle 41/43/47 field, or " downed??. All platforms located in the Grand Isle (GI) and West Delta (WD) lease areas are in water depths from 86 to 135 feet. The locations were GI 40B, GI 40F, GI 41A, GI 47C, GI 48D, WD 69C, and WD 69K (Figure 1), which are all within 20 to 35 miles west of the centerline track of Hurricane Katrina.