bluuebunny/crossref_metadata_2025_split huggingface dataset:
Terra Nova - The Flow Assurance Challenge
Authors: Stephens P. , Sheorey U. , Isenor R. , Ewida A. 
Published: October 2008

Abstract
The Terra Nova field is the second largest oil field discovered to date in the Jeanne d'Arc basin on the Grand Banks, with recoverable reserves of approximately 370 million barrels. The field, located in approximately 94 m of water 350 km East-Southeast of St John's, Newfoundland and 35 km Southeast of the Hibernia field, will be developed utilizing subsea flowlines from four drill centres tied back to an FPSO.
This paper discusses the design approaches adopted to meet the principal flow assurance challenges for the subsea facilities. These are:Hydrate formation: the minimum seabed ambient temperature is -2 °C.Wax formation: the design is based on stabilised crude having a wax content of 9.0 %, a pour point of 12 °C and a wax appearance temperature of 46 °C. The wax dissolution temperature is 70 °C.The implications of turret disconnection: the buoy along with all the risers can be released to allow the FPSO to move off-station to avoid icebergs.
The owners of the Terra Nova field are Petro-Canada (29 %), Mobil Oil Canada Properties (22 %), Husky Oil Operations Ltd. (17.5 %), Norsk Hydro Canada Oil and Gas (15 %), Murphy Oil Company Ltd. (12 %), Mosbacher Operating Ltd. (3.5 %) and Chevron Canada Resources (1 %). The operator of the field is Petro-Canada, and the FPSO vessel constructor is Daewoo of Okpo, South Korea.
The participants in the Terra Nova Project Alliance include Petro-Canada (and seconded owner personnel), Coflexip Stena Offshore Newfoundland Ltd., Shawmont Brown and Root, Halliburton Energy Services, FMC Offshore Canada Inc, PCL Industrial Constructors Inc. and Doris Conpro Ltd.
First oil from Terra Nova is targeted for January 2001.

Introduction
The Terra Nova development is based on a subsea tieback with flexible fowlines/risers to a Floating Production, Storage and Offloading (FPSO) vessel, with crude oil transported to market by shuttle tankers. The FPSO has a storage capacity of 970,000 barrels of oil and supports topsides process and utility equipment with a gross operating weight of 12,200 tonnes. The topsides facilities are designed for a maximum overall oil production rate of 23,880 Sm3/d (150,000 bbl/d), produced water rate of 21,000 Sm3/d (132,000 bbl/d), water injection rate of 28,600 Sm3/d (180,000 bbl/d) and gas injection rate of 7.36 MSm3/d (260 mmscfd). Following separation to meet the specifications for TVP of 75.8 kPa at 50 °C and BS&W of &lt;0.5 % by volume, crude is transferred to the storage tanks located in the vessel hull where it is maintained above the wax appearance temperature at all times. The overall field schematic (base case development) is shown in Figure 1 and a simplified topsides process flow diagram is shown in Figure 2.
The base case subsea development scenario incorporates 14 production wells and 10 water/gas injection wells. Gas lift facilities are provided on 12 of the 14 production wells.
Operational Experience with the FPSO Ocean Producer
Authors: Thompson Richard 
Published: October 2008

Abstract
This paper describes and analyzes the operational experience of an FPSO (floating production, storage and offloading system) that has been onstream offshore West Africa for over eight years. The FPSO was designed for efficient production of smaller and marginal oil fields. It was converted on a stringent budget at an U.S. Gulf Coast shipyard and has been operated so as to be cost-effective at production rates ranging from 10,000 bopd to less than 5,000 bopd. Despite the economic constraints that have characterized its operation, it has achieved excellent results for safety and for overall vessel and process system uptime.
This paper discusses the design of the FPSO, it's operating history and operational results. The operating philosophy and procedures are examined in detail to illuminate their relationship to the successful results that have been achieved.
The operations philosophy, systems, procedures, and safety programs that are in place to help achieve the safety, uptime, and OPEX goals are presented. A case history of the FPSO is also presented.

Introduction
The FPSO Ocean Producer has been in operation in West Africa since December, 1991. During that more than eightyear period, the Oceaneering vessel crew has experienced no Lost Time Accidents (LTA). Since 1994, the Ocean Producer has processed over 10,000,000 barrels of oil while maintaining 99.9% uptime. The safety record and uptime achievements have been maintained while operating costs were constrained to allow continued operations at oil production rates of less than 5,000 bopd.
The FPSO Ocean Producer was originally designed and built to treat 15,000 bfpd of heavy oil with up to 80% water cut.1 She was put into service in 1991 for Amoco Gabon Gombe Marin Company and remained in Gabon until the end of October, 1993. At that time, she underwent minor modification and moved to Angola where she is currently under contract to Sonangol P & P processing light crude oil.
The FPSO Ocean Producer was converted from the 78,000-dwt crude oil tanker M. T. Baltimore Sea for FPSO service at the Gombe Beta field offshore Gabon, West Africa. The Gombe Beta field failed to produce up to expectations, and Amoco sold its interest to Kelt Energie in 1992. The FPSO remained on location on a month-to-month basis producing at very low rates. In September 1993, the Ocean Producer was contracted to Sonangol P & P for Kiabo field, Block 4, Angola. This was the first (and still the only) direct contract of a floater to an operating unit of a West African national oil company.
Following its release from Gombe Beta field, the Ocean Producer sailed to Capetown, South Africa, for minor modifications and refurbishment. She then proceeded to Kiabo field, arriving only 57 days after departure from Gabon.
Original proven reserves for the Kiabo field was on the order of 5,000,000 barrels, with some upside potential. To date, The Ocean Producer is still in operation in the Kiabo field and has recovered over 10,000,000 barrels.
On The Coupling Terms In The Low-Frequency Viscous Reaction Forces Of Moored Tankers In Deep Water
Authors: Wichers Johan , Ji Chunqun 
Published: October 2008

Abstract
Due to the restricted water depth of experimental facilities one has to rely more on computational tools for the design of turret and spread moored tanker based FPSOs in deep water. These tools have to be as accurate as possible.
The mechanics to compute dynamically mooring lines and risers are understood. By means of potential theory the first order tanker motions and wave drift forces with and without current can be adequately computed nowadays, see for instance Ref. 1.
Besides the low-frequency (lf) wave drift forces also the lf viscous reaction forces (damping) exist in still water and current. The lf reaction forces/moment induced by the lf motions in the horizontal plane are mostly dominated by viscosity and hardly to compute.
By means of model tests the viscous forces in the separate surge, sway and yaw modes of motion were measured in still water and in a current field, see for instance Ref. 2. The importance of the coupling terms due to the combined modes of motions, however, is not known.
By means of a lf large stroke mechanical oscillator prescribing combined motions on the tanker hull the coupling terms were investigated in still water and in current. The results will be presented in the paper.

Introduction
In order to compute the lf motions of a moored tanker the equations of the lf motion have to be established. Most of the maneuvering models are based on the model as for instance presented by Abkowitz, Ref. 3. In this model the maneuverability is described by means of linear and nonlinear derivatives of the hydrodynamic forces and moments by perturbation models.
Contrary to normal maneuvering applications (high speed, high rate of turn and relative small drift angles) specific requirements have to be fulfilled for a moored tanker e.g.:large drift angles (0-360 degrees)small values of drift velocities (combined low frequency tanker motions in still water or in a current field)small values of oscillating rate of turnrelatively large transverse motionsin steady state in a current field the hydrodynamic forces have to correspond with the steady current loads.
These requirements do not satisfy the model of Abkowitz. The full equations of the lf motion as applied for a moored tanker in still water and in a current field should be established. A present formulation is presented. Starting in an ideal and irrotational fluid the equations of motion as given by Norrbin (Ref. 4), taking into account the Munk-moment (Ref. 5) can be established. In real fluid, however, viscosity is involved. The viscosity modifies the Munk-moment and introduces additional resistance forces (d'Alembert paradox).
By means of model tests using a lf large stroke oscillator the viscous forces in the separate surge, sway and yaw modes of motion can be determined. A comprehensive description is given in Ref. 2.
Moored tankers in general, however, perform fish tailing motions. A fish tailing motion consists of a combined motion in the horizontal plane.
Seismic Repeatability Benchmarks
Authors: Grion Sergio , Keggin James , Ronen Shuki , Caldwell Jack 
Published: October 2008

Abstract
The effects of various parameters on repeatability can be considered in making decisions on acquisition and processing parameters. For this reason we apply repeatability benchmarks based on the RMS difference of two data sets to various repeat marine seismic data. The datasets considered here come from two different areas, Foinaven and Viking Graben. We have two vintages of 3D Streamer and OBH data from Foinaven ('95 and '98) and 2D multi-component data, with and without cable redeployment, from Viking Graben.
The repeatability study of these data sets provides quantitative measurements of the effects of acquisition parameters, data processing and survey matching methods.

Introduction
The oil and gas industry is using various types of time-lapse seismic data for 4D analysis to monitor reservoir changes. The most common data type is surface towed streamer data, which may have inconsistent parameters between base and monitoring surveys. Another type of time-lapse data is from seabed sensors.
We apply the NRMS (Normalized RMS) repeatability benchmark to various repeat marine seismic data sets. This benchmark is based on the relative difference between each of two compared data sets. Another often-used repeatability benchmark is Predictability (Ref. 3). In this paper NRMS is computed at various steps of a matching procedure during which the amplitudes of each pair of data sets are matched and phase and time shifts between the two data sets are compensated. NRMS is evaluated both in the time and frequency domains, to determine the effects of acquisition and processing parameters both globally and for different frequency bands. Besides NRMS, for time lapse survey design the needed parameter is the Noise to Signal Ratio (NSR); NSR should be lower than production effects on seismic data. We estimate NSR from Normalized RMS.

Repeatability benchmarks
The repeatability benchmark used here are based on the RMS difference of two data sets normalized by the average RMS energy of the two parent data sets. We call this benchmark Normalized RMS (NRMS). Given two data sets A and B, NRMS for traces aj and bj would be:
Mathematical equation (1) (Available in full paper)
where j denotes trace location and i time samples, i=1,...,Nt.
The lower bound of the NRMSj is of course zero in the case that aj = bj. The upper bound is 2. If traces ajj and bj are not related, but have the same average amplitude, it can be shown that the expected value of the NRMS is ?2.
Once NRMS is computed, it can be shown that the Noise-to-Signal Ratio (NSR) is:
Mathematical equation (2) (Available in full paper)
This expression for NSR is strictly valid only if in data sets A and B noise has the same variance and signal has the same power. NSR tends to infinity when the two data sets are made of random noise and is 0 when data sets A and B are equal.
Equations (1) and (2) are computed in the time domain but NRMS and NSR can also be computed in the frequency domain, applying (1) and (2) to the Fourier transform of ajj and ajj.
Marine Challenges Encountered by a Small Mine on the Maine Coast
Authors: Beck Frederick M. 
Published: October 2008

ABSTRACT
Callahan Mining Corporation is currently mining copper and zinc ore from an open pit mine on the edge of Penobscot Bay in Marne. The open pit occupies an area once largely covered by a salt water pond. The mining operation utilizes conventional mining and milling techniques and in this respect perhaps could not be considered a true marine mining operation. However, many obstacles had to be overcome due to the proximity of the ocean beforethe mine could be brought into production. Problems with which inland mines do not have to contend are faced daily. These include effluent control, marine mud stability, salt water encroachment, reclamation, and exploration.
The ore deposit stratiform massive sulfide body in early Paleozoic volcanics. The principal ore minerals are sphalerite and chalcopyrite with minor galena. Associated minerals include chlorite, talc, and carbonate. The deposit was discovered in 1880 at low tide by a clam digger. Surface ore outcrops were entirely below high tide. The mine was developed and mined from three shafts. Apparently the deposit became unprofitable in about 1887. A re-evaluation in 1964 by the Callahan staff prompted the present open pit operation. Production is currently at the rate of 700 tons per day.
Exploration for additional are deposits is complicated by the presence of saltsaturated mud in estuaries and salt water covering geologically favorable prospecting ground. Many conventional inland exploration techniques are useless near these areas.
The ocean presence has added substantially to the mining costs, thus narrowing the profit margin. New techniques must be developed by the mining industry to cope with oceanographic problems. Some of thesechallenges are being met at Cape Rosier and can be applied to future mining ventures faced with similar marine problems.

INTRODUCTION
The Penobscot Mine on the Maine coast is not a "marine mining" operation in the strictest sense. For the most part, conventional techniques of mining and milling are in use and the ocean is a nuisance. However, by being located at the sea-land interface, there are a number of factors which influence the operation which would not be encountered inland. The engineering chal1enge of dealing with the shallow estuary were relatively easily mastered. The challenge to mineral exploration still exists and is a subject of continuing effort. The nation's sea-land interface is probably one of the most popular and valuable multiple use areas in the country. In Maine it has scenic beauty, is sought after for summer homes, provides food and shelter during parts of the life cycles of innumerable marine species, and is the basis for commercially important coastal fisheries. It is an area high on most lists for environmental protection. It is natural that the addition of another "user" to this area would be resisted, particularly when that user represents an industry which has a past record of environmental abuse.
General Characteristics of Currents in the Deepwater Gulf of Mexico
Authors: DiMarco S.F. , Reid R.O. , Jochens A.E. , Nowlin W.D. , Howard M.K. 
Published: October 2008

Abstract
Currents were generally surface intensified, with speeds reaching ~200 cm/s in association with energetic events such as passage of a Loop Current Eddy or intense atmospheric storm. A minimum in current speed occurred at about 800-1000 m depth. But maximum speeds can reach 120 cm/s at about 2000 m. Bottom intensification was present. Horizontal spatial decorrelation scales were smaller in the transverse direction than longitudinal.

Introduction
Over 8 million hours of current records were assembled as part of the Gulf of Mexico Deepwater Physical Oceanography Reanalysis and Synthesis of Historical Data Study, sponsored by the Minerals Management Service (MMS). Data assembled were from the area bounded by the shelf edge (approximately the 200-m isobath) of the northern Gulf of Mexico and the 25°N latitude line. Data extended from the sea surface to the sea floor in water depths from 200 m to over 3000 m. Additionally, a seven year (1993-1999) circulation model run was completed using the high-resolution University of Colorado Princeton Ocean Model (CUPOM) for the Gulf of Mexico1. Current records and the output of the CUPOM run were examined to characterize currents and estimate horizontal scales of deep flow in the Gulf of Mexico.

Results
The characterization of the currents was examined using the observational data base. Because of a lack of concurrent observational data with adequate spatial resolution, the horizontal scales were estimated using the CUPOM output for 1993.

Observations.
All current records of good quality were compiled to show the percentage of time that unfiltered currents exceeded various speed thresholds as a function of depth ranges. Because currents below about 800 m in the Gulf generally are nearly barotropic, and because deep observations are scarce, we used the large depth range of 1200 m to the sea bed to obtain a reasonable sample size for the deep layer. Results indicate that currents above 200 m exceed 75 cm/s about 2% of the time and 100 cm/s almost 1% of the time. The fastest currents are near surface and percents for all speed bins decrease rapidly with depth above 800 m. Currents below 800 m are normally rather coherent in the vertical, sometimes with bottom intensification. Below 1200 m the currents exceeded 40 cm/s about 0.6% of the time, which is greater than for the depth interval of 800–1200 m; this is evidence of bottom intensification.
For each current record, a current rose and persistence table were produced. These can be examined to study the effects of energetic current events, such as occur with passage of the Loop Current, associated eddies, or hurricanes and other intense atmospheric storms. For example, mooring I1 was deployed for MMS in water depth of 2001 m in the northcentral Gulf just south of the Sigsbee Escarpment.
Visualization of Oil, Gas, and Water in the Subsurface
Authors: Anderson Roger N. , Boulanger Albert 
Published: October 2008

Abstract
Tracking the flow of oil, gas, and water in real-time while reservoirs are being drained is now possible through the emergence of rugged downhole sensors, the Internet, high bandwidth satellite and fiber communications and rapid middleware wrapping of software applications. The question is what information delivers economic return on the investment required. The good news is that all along the value chain, prices are coming down because of commercial pressures from outside the energy business. For example, Direct PC will likely drop the cost and increase the bandwidth of satellite communications to remote locations by an order of magnitude over the next few years.

Application
The manufacturing process by which we produce energy is being reinvented like we have never before experienced in this business. The oil and gas field of the future will be part of a much larger Information Technology (IT) network. Each field will be a wired, internet-connected, real-time monitored, remotely controlled, electronic venture. Each well, pipeline, rig, production platform, compression facility, and even the pumpers themselves, will have a IP (Internet Protocol) address. Any browser on any laptop in the company (with proper password protection) can log onto the myoilcompany.com URL at any time of the day or night -- from anywhere in the world -- and visualize production, well test, logging, and other real-time measurements coming from the 4D monitoring of field performance.

Results and Observations
However, there are fundamental reasons why such an integrated IT system for the oil and gas field is a difficult mission for the energy industry to pull off successfully. Principal among them is that the "last mile," as it is called in the communications industry, (the field connectivity to the manufacturing facility itself) is about as difficult an IT environment as could be imagined. Other IT savvy manufacturers around the globe also deal with multiple vendors, millions of customers, and millions of parts as we do, but our SITE of manufacture of energy products is NOT usually in a metropolitan area with communications infrastructure in place. Instead, it is found in whatever water depth or remote geography (usually rural) the oil and gas happens to be discovered beneath. And then, of course, the "very last mile" to the resource itself is under the ground and cannot be visited, or even imaged clearly.
Not only must energy companies deal with a constantly changing set of IT vendors and bandwidth constraints from field to field, but each must be specified from the start to operate continuously for 30+ years, as part of an internetconnected portfolio. In the future, oil and gas fields will form an information grid with other fields, pipelines, land, and seaborne traffic, refineries and storage facilities, etc. that form the complete enterprise of the company (Figure 1).