bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maintaining Late-Life Production From Long Offset Subsea Gas Wells
Authors: Becnel Miles , Steib Don , Wegener Stephen , Linder Jacobs , Beg Najam 
Published: October 2008

Abstract
The ability to maintain late-life production from long offset sub sea gas wells is very much dependent on the well stream's ability to reduce flow line pressure by effectively sweeping liquids from the flow line. This paper reviews the application and results of utilizing a gas ejector on long offset sub sea gas wells to enhance recovery. Although this document focuses on a sub sea application of this technology, gas ejectors can also be utilized on any low pressure well. The use of this device should be seriously considered when applicable. Its interchangeable internals allows the same device to be utilized through a wide range of productions and pressure regimes and can be relocated as needed.
Post-installation data has shown that the installation of the gas ejector has performed as per the stated design and is a technically feasible and cost effective means to recover additional reserves from low pressure wells. It is particularly attractive where an existing high pressure gas source is available.
The authors consider this the first application of this type in the Gulf of Mexico and since installation have received inquiries about potential applications for other Gulf of Mexico assets.

Introduction
The Gemini field is located in Mississippi Canyon Block 292 in 3400 feet of water. See Figure 1. The field was discovered in 1995 and production commenced in 1999. The original development consisted of three sub sea wells tied back to the Viosca Knoll host facility via two 27 mile long flow lines. Since first production, reservoir pressure and production rates have decreased to the point where the reservoir's natural ability to adequately sweep the flow line of liquids no longer exists. As a result it was predicted that the field would cease production unless a method to lower flow line pressure and reestablish a means to sweep the flow lines was developed. Several options were considered and a gas ejector was selected as the preferred alternative. This paper describes preinstallation operations, other options considered and design considerations specific to the Gemini facilities. In addition pre- and post-installation production and pressure history are presented.

Pre-installation Operations
Prior to the installation of the gas ejector, the Gemini wells flowed through a sub sea manifold where they could be routed into either of two 27 mile long 12" flow lines. Originally, production volumes required the utilization of both flow lines, but, eventually the declining production created the need to flow both wells into the same line. This continued until the pressure and corresponding velocity in the single line became inadequate to effectively sweep the liquids from the line. The resulting liquid hold-up in the long line caused excessive pressure drop and high manifold pressure, causing the wells to load-up with fluid.
From P-34 to P-50: FPSO Evolution
Authors: Henriques C.C.D. , Brandão F.E.N. 
Published: October 2008

Abstract
PETROBRAS started to use ship-shaped processing and storage vessels (FPSOs) for offshore production in 1979, through the installation of a process plant over the deck of the P.P. Moraes oil tanker (later renamed to P-34). In April 2006, the P-50, PETROBRAS' latest and most complex FPSO, ever, started production in Albacora Leste Field.
In these last 25 years, the concept and design of our FPSOs suffered a large transformation, from the simplified production plants for up to 50,000 bpd used in the late 70s, through the large FPSOs converted in the mid-90s, up to the concept adopted in P-50 project.
In this project, the concepts of modularization and selfcontained equipment packages allied to the life enhancement strategies adopted to guarantee an operational life in excess of 25 years, lead to a design that can be considered "top-of-class" for converted FPSOs.
In this paper it will described how the design of PETROBRAS' FPSOs evolved highlighting the modifications made in the design of P-50 main systems.

Introduction
PETROBRAS has a long history of using ship-shaped production units in its offshore projects starting in the end of the 80's. Table 1 shows the list of our FPSOs in design, construction or operation and the FPSOs that were demobilized. At present, we have 11 FPSO/FSOs in operation, and we can divide the history of those Units into 3 phases, as can be graphically seen in figure 1 that shows the number of FPSO/FSOs that entered production in each year, since 1987:Phase I: In this period, from 1979 up to the beginning of the 90s, FPSOs were used mainly as Early Production Systems;Phase II: This period, up to the end of 90s, comprises the boom of FPSO construction and installation in the Campos Basin;Phase III: In this phase, the use of FPSOs was consolidated and a second generation of units was built, taking into account all the experience gathered in the first wave of FPSOs from the second phase.
Nowadays we can see that a new FPSO Phase is beginning, with the development of P-57 project, our first newbuilt designed FPSO.

Evolution of FPSO Concept in Brazil

Phase I:
In the Campos Basin, the first CALM buoy was installed in the Enchova Field, in 1978 in order to allow the mooring of an oil tanker to receive the production from a drilling rig in a pilot production system.
The first mono-hull floating production unit to operate in the Campos Basin (and one of the first FPSOs in the world) was the former tanker P.P. Moraes. This 33,000 dwt tanker was built in 1959, and, in 1975 it was jumboized to 54,000 dwt. Then, in 1979, a 60,000 bpd process plant was installed in P.P. Moraes to allow it to operate in the Garoupa field, moored by a tower-yoke system as can be seen in figure 2. In 1980, the tower failed from fatigue at the ballast tank, and a CALM buoy was then installed in the field, to moor the P.P. Moraes FPSO through a soft yoke (figure 3).
Sand Transport Modeling in Multiphase Pipelines
Authors: Danielson Thomas J. 
Published: October 2008

Abstract
Prediction of the critical flow rate that will result in sand bed formation in multiphase flow is a critical aspect of multiphase production. Many correlations have been developed for solids transportation in multiphase flow; however, all of them treat the multiphase flow in an ad hoc way that does not respect the complexity of the phenomenon. Further, many approaches rely on correlations that have been developed for much higher solids loading than would occur in oil and gas production. In this paper, first a correlation for liquid-solid transport is developed, based on data taken in the SINTEF STRONG JIP. A good fit to both sand bed height and measured pressure drop is obtained. A critical aspect of the model is the assumption that there is a critical slip velocity between the sand and liquid which remains relatively constant over a wide range of flow velocities. Second, the particle diameter is used to augment the surface roughness. A critical velocity correlation is developed, based on solid and fluid properties, and pipe diameter. An essential feature of the model is that the critical slip between the liquid and solid phases is unaffected by the presence of gas. Good fit to the data is obtained. A sand model is developed using OLGA2000 which does a good job in fitting sand hold-up against the experimental data. Such a model can be used to predict sand bed formation potential in field lines.

Introduction
Sand is often produced out of the reservoir in both onshore and offshore production systems, particularly in reservoirs that have a low formation strength. Sand production may be continuous, or sudden - as when a gravel pack fails. In the case that no downhole sand control is done, or that a sandcontainment strategy fails, a sand-management strategy must be employed, with operations designed to tolerate a certain amount of sand production. Deposition of sand beds poses several risks, including increased frictional pressure losses, increased risk of corrosion due to microbial attack under the sand bed, and increased risk of equipment failure due to sand. Sand transport in near-horizontal pipelines has four main regimes, depending on the fluid flow rate. Below a critical velocity, sand will drop out of the carrier fluid and form a stable, stationary sand bed. As the sand bed builds over time, the fluid above the bed is forced into a smaller cross-sectional area, causing the fluid velocity to increase. When the velocity reaches a critical value, sand is transported in a thin layer along the top of the sand bed. A steady-state is reached, such that the sand eroded from the top of the bed is replaced by new sand production from upstream. At higher velocities, the sand bed begins to break up into a series of slow-moving dunes, with sand particles transported from the upstream to the downstream side of the dune. As the flow velocity increases still further, the dunes break up entirely, and the sand forms a moving bed along the bottom of the pipe.
Physical Properties of Mass Transport Complexes in the Ursa Region, Northern Gulf of Mexico (IODP Expedition 308) Determined From Log, Core, and Seismic Data
Authors: Dugan B. , Flemings P. B. , Urgeles R. , Sawyer D. , Iturrino G. J. , Moore J. C. , Schneider J. 
Published: October 2008

Abstract
Mass transport complexes (MTCs) in the Ursa region (northern Gulf of Mexico) are identified by their low seismic reflectivity, increased resistivity, increased bulk density, high shear strength, and decreased porosity. We integrate seismic, logging while drilling (LWD), and core data to identify MTCs and to characterize their physical properties. The seismic signature of MTCs includes high amplitude reflections at their bases and low amplitude, and often non-continuous, internal reflections. Resistivity increases in MTCs (up to 10%) creating a contrast with overlying and underlying, nondeformed sediments. Increased resistivity correlates with increased bulk density and visual observations of increased deformation. We interpret that increased density results from consolidation associated with shear deformation. This creates different resistivity-density relations for MTCs and non-failed sediments. Undrained shear strength measured on cores increases by as much as 20% in MTCs where resistivity and density are high. Consolidation during shear deformation also decreased permeability of mudstones in this basin. The combination of rapid deposition and low permeability may have contributed to shallow overpressure in the Ursa region.

Introduction
Mass transport complexes (MTCs) are sedimentary bodies that have experienced downslope migration and various degrees of internal deformation. Previous studies have evaluated the geometry and stratigraphy of MTCs using 2D and 3D geophysical data [e.g., 1,2]. Other studies have related the distribution and size of MTCs to natural disasters associated with submarine slope failures. In few instances natural disasters have been observed as direct result of slope failures. The 1929 Grand Banks tsunami was caused by an earthquake-induced submarine landslide that damaged oceanic infrastructure and caused deaths onshore [3]. In 1998, an earthquake-triggered MTC produced a tsunami that killed &gt;2000 people on Papua New Guinea [4]. In addition to human fatalities, submarine landslides have also caused direct damage to coastal facilities (e.g., the Nice airport, France [5], and Finneidfjord, Norway [6]). Detailed physical and sedimentological characterizations of MTCs have allowed the oil industry to better identify hydrocarbon reservoirs and seals [e.g., 7] and has been used to evaluate physical properties that may impact shallow infrastructure [8].
Optimization of Tension Level and Stinger Length for Offshore Pipe line Installation
Authors: Daley Gregory C. 
Published: October 2008

ABSTRACT
Offshore pipelines have been installed for a period of' some 10 to 20 years using a variety of methods. This paper presents a new analysis method for the optimization of certain operation parameters in laying continuous pipe under tension from a barge. This method of optimization is now being used by one of the major offshore contractors. The solution is given by matching geometrical parameters through graphical overlays of network charts obtained by a computerized finite element iterative solution the solution is based on the requirement that the tension level be optimized with respect to either the minimum stinger length or the maximum average radius of curvature of the stinger.

INTRODUCTION
The problem that this paper deals with is that of laying oil and gas-pipeline offshore (Fig. 1). The problem consists of, how one might place the pipeline on the sea floor without kinking or buckling the pipe. This is done by ensuring that the stress is always below some allowable stress; for example, 80 percent of yield stress. The stress is proportional to the bending moment. Typically, the stress induced by the bending moments is an order of magnitude to two orders of magnitude larger than the stress induced by either the tension level at which the pipe is being pulled or the hydrostatic pressure of the sea water.
In order to relieve the bending moment in the sag bend (and thereby reduce the stress) the pipe is pulled by a tensioning device, typically capable of producing a horizontal tension level, H, ranging from 0 to 120,000 lb.
As the pipe comes off the barge, it rests in a flexible buoyant support called the stinger. The stinger of length, S1, is partitioned off into a series of tanks and each tank can be filled with either water or air. The stinger, therefore, has some average radius of curvature, p. other methods of varying stinger curvature exist such as varying support roller heights with respect to the stinger.
The other operational parameters are the entrance angle, a, of the pipe coming into water off the barge; the rigidity of the pipeline, EI; the submerged weight per unit length, q, of the pipe j' and the depth of the water, WD. The contractor has control over the tension, H; the stinger radius of curvature, p; and until the stinger has, been built, the length, S1, of the stinger.
It should be pointed out that, prior to this system, the analysis was accomplished'by fixing all seven of the variables, solving for the moment as a function of arc length using a complex computer program, and checking each moment. If one of the moments happened to be greater than the allowable, then one or two or three of the parameters were adjusted, based on "engineering intuition".
In-Situ Pore Pressure at IODP Site U1324, Ursa Basin, Gulf of Mexico
Authors: Long H. , Flemings P.B. , Germaine J. , Dugan B. , Sawyer D. 
Published: October 2008

Abstract
We measured pore pressures with two pore pressure penetrometers at IODP Site U1324 in Pleistocene sediments of the Ursa Basin, Gulf of Mexico, directly offshore from the Mississippi Delta. Between the seafloor and 300 meters below the seafloor (mbsf), overpressures reach 80% of the hydrostatic effective stress (?=0.8=(u0-uh)/(?v-uh) In this interval, only low permeability mudstones are present. Beneath 300 mbsf, ?* is approximately 0.2 and the sediments are composed of interbedded mudstone, siltstone, and very fine sandstone. We interpret that the lower relative pressures beneath 300 mbsf are caused by the higher permeability of these sediments. Penetrometer deployments ranged from 30 minutes to 90 minutes, which was not enough time for the measured pressure to dissipate to the in-situ pressure. To estimate the in-situ pressure, we used two inverse time extrapolation techniques: 1/?t, and1/t. We use a theoretical soil model to show that the 1/?textrapolation provides a desirable accuracy in much shorter amount of time than the 1/t extrapolation.

Introduction
Overpressures, pore pressures in excess of hydrostatic pressure, have been observed in sedimentary basins around the world 1. Knowledge of the distribution of overpressure is critical to explore, drill, and produce hydrocarbons 2, 3. Overpressures drive pore water flow 4, impact large-scale structural development 5, and affect the state of stress 6.
In young, cool, sedimentary basins, overpressures are generated in low permeability mudstones due to their inability to drain as they are loaded by sedimentation or deformation. Although the pressure is generated within the mudstone, it is most often measured in permeable formations adjacent to the mudstone 3. Recently, the petroleum industry has extended geotechnical techniques to measure pore pressure within mudstones through the use of pore pressure penetrometers in the borehole to depths of many hundred of meters 7–9. This exciting technique provides direct measurements of pore pressure in low permeability rocks and in some locations it has documented very high pore pressures immediately beneath the seafloor 7.
When the penetrometer is pushed into the formation below the bottom of the hole (BOH), a pressure disturbance is created. The time that it takes to disipate this pressure depends on the probe diameter and the hydraulic diffusivity of the sediment. In ocean drilling, the time available for downhole tool measurements is expensive and limited. In this environment, in-situ properties must be interpreted from partial dissipation records. If detailed soil properties are available, the in-situ pressure and diffusivity of the sediment can be inferred from modeling of soil behavior for different penetrometer geometries 10–14. However, in many cases soil properties are not available, or there are insufficient resources to pursue soil modeling. In these cases, in-situ pressure is inferred from a simple extrapolation approach.
Ormen Lange Onshore Processing Plant
Authors: Kjeldsen Audun 
Published: October 2008

Abstract
The Ormen Lange Plant at Nyhamna consists of well stream processing, gas export compression and condensate offloading to tankers. The gas from the field is conditioned to dew point and heating value according to European specifications, then routed into the export pipeline to Easington, UK, via the leipner field.
Condensate recovered from the well stream is stabilized and stored in a custom-built rock cavern before being shipped from the terminal. Gas and liquid products are metered to fiscal standards before being exported. The process facilities at Nyhamna consist of two gas conditioning and dehydration trains, three export compressor trains and one condensate stabilization train. The plant processing capacity is 70 million standard cubic metres per day (MSm3/d) of sales gas at an initial arrival pressure of 90 bar. Maximum condensate production is estimated to be 7000 Sm3/d.
Before construction could start, a massive civil works task was performed, blasting more than 2 million m3 of rock in order to prepare the plant site and build storage caverns. The construction and installation of steel structures, buildings, pipes, cables and equipment continued throughout 2006, while in 2007 the main task will be to test out the plant before starting production.
By May 2007, the plant will be just weeks away from hot testing, after a three-year construction period with up to 3500 workers during the peak period at Nyhamna. This paper describes how Hydro as operator has undertaken this massive construction task - building one of Norway's largest processing plants - and what this has required in terms of project management. It also includes a short description of how collaboration with the local community has been achieved.
Fig. 1 Island of Gossen, site for the Ormen Lange onshore plant. (available in paper)

Introduction
Nyhamna, on the west coast of Norway in the county of MØre and Romsdal, was selected as the site for the Ormen Lange onshore processing plant. The Ormen Lange installations have been planned, designed and built according to Norwegian legislation and regulations. Hydro's requirements for HSE work have formed the basis for the HSE goals and requirements that have been set.
HSE acceptance criteria were established with regard to the risk posed to the safety of individuals, society, the environment, health, and working environment, as well as the risk of losing material assets. Subsequent HSE analyses document that the plant meets all Authority, Partner and Hydro requirements to Health, Safety and Environment.
The development of the plant has been based on proven and robust technology. The Ormen Lange project has a strong focus on energy efficiency and the reduction of emissions and discharges in order to minimize environmental impacts. Principles of BAT (Best Available Technology) and ALARP (As Low As Reasonably Practical) have been applied.
The calculated gas production availability of the plant, based on historical industry experience databases and operations experience will exceed 97 % once stable production has been established
Soil-Wave Tank Studies Of Marine Soil Stability
Authors: Doyle E.H. 
Published: October 2008

ABSTRACT
Soil instability occurred off the Mississippi River Delta during hurricane Camille due to large wave induced bottom pressures. This paper discusses the effect of such waves on soft clayey soils.
In particular, the paper is based upon the results acquired from a large model tank which was constructed to study the effect of surface water waves on a clay soil under controlled conditions. The primary motivation for the tank studies was to provide a qualitative means by which an engineer could evaluate the progress of instability under wave loading.
Within the scope of the tank study, soil displacement patterns were observed with depth and related to field conditions. Investigations were made into the effects on the soil continuum of wave height and period, soil shear strength, slope variations, and repeated wave loading. Measurements of wave height and period, bottom pressure, and in-situ soil shear strength were obtained to evaluate simple analytical methods for predicting instability.

INTRODUCTION
The sediments of the Mississippi River have strongly influenced the continental shelf offshore Louisiana. The present Birdfoot delta complex began less than 500 years ago and has been building seaward at rates up to 350 feet per year. 1 The accumulation rate of the sediments has exceeded the rate at which the deposits can dissipate the buildup of excess pore water pressure. As a result, the soils around the Birdfoot complex are very soft and underconso1idated. 2, 3 The weak soils in combination with continuing deposition and environmental forces lead to a dynamic system of delta building. The purpose of this paper is to discuss one of these dynamic processes, namely, wave induced soil instability. This phenomena is initiated by waves of sufficient height and period which produce significant pressures at the seafloor. If the surface waves exert enough pressure, the soil may become unstable. Some areas of the Mississippi Birdfoot complex are susceptible to wave induced soil instability, particularly where weak soils are subject to the effects of hurricane - wind generated waves. 4, 5 This paper is based on the results of soilwave tank studies of wave induced soil instability. The primary motivation for constructing the tank was to obtain firsthand observational experience on the effect of waves on soft soils.

Basis for Tank Tests
The phenomena of hurricane - wind generated waves creating soil instability was generally unknown prior to research by Shell Oil Company. Henkel,6 for example, published a slip-circle method of analysis after completing his work as a consultant to Shell in 1970. Scott and Zuckerman7 in their 1970 review of slope instability in the ocean floor briefly reported Henkel's work.