bluuebunny/crossref_metadata_2025_split huggingface dataset:
Life-Cycle-Cost-Based Design Criteria for Gulf of Mexico Minimum Structures
Authors: Botelho Dirceu , Petrauskas Chuck , Vannan Mani , Mackey Vance , Lang Buddy 
Published: October 2008

Abstract
Chevron engineered four different structural concepts for two fields in different locations and different field economics, and for three different design criteria: 100-, 50-, and 25-year return periods. The structural concepts considered are primarily used in the offshore industry for marginal field development. The objective of the study was to evaluate the impact of designing these structures based on field economics by maximizing the expected net present value (NPV) of the project revenue streams over the life of the field, or equivalently, by minimizing the total cost of the project over the life of the field. In either case not only initial capital costs are considered, but also costs associated with maintenance during the project life, and costs associated with a potential failure of the structure.
The study concludes that, depending on the economics of the field, the optimum design criteria may be more or less stringent than the current 100-year criteria recommended in the 20th edition of API RP2A1.

Introduction
In order to improve the economics of developing small/marginal fields, Chevron carried out a study to identify and select, among existing production platform concepts, the ones that would optimize the development of fields in 130 ft. and 200 ft. of water. The study aimed not only at selecting the concept with the lowest initial capital cost among existing concepts, but also at defining the optimum platform design criteria on the basis of maximizing the expected NPV of the field development over a range of different production scenarios.
The study was divided into three main phases:Information gathering and selection of four alternatives;Preliminary design of alternatives and narrowing choices to two alternatives;Risk-based economic analyses and selection of the preferred alternative.

Phase 1 Results
In the first phase of the study the development scenarios and production requirements were defined. In addition several different criteria were defined to help weigh the strengths and weaknesses of each of the concepts being considered. At a minimum each structure would have to support:5 wells;a small deck with enough space to handle a coil tubing or wireline unit;a test separator and a well header;a small crane;a boat landing; anda minimum helideck.
The locations considered were Eugene Island Block 238 in 130 ft. of water, for which a 7 year development scenario was considered, and Main Pass Block 133 in 200 ft. of water, for which a 5 and a 22 year development scenarios were considered. Table 1, summarizes the production schedules for each of these scenarios, and Table 2 provides information on the economic assumptions.
A total of 29 platform concepts were considered, with the selected top four concepts being:Mantis II,LINX,STAR, andTripod.
The tripod considered here differs from traditional tripods in that one of the legs is vertical, and considered to hold one of the five wells. Figures 1 depicts three of these concepts.
Six years experience with an erosion based sand monitoring system at the Tordis field.
Authors: Braaten Nils A. , Johnsen Roy 
Published: October 2008

ABSTRACT
The production of sand particles in oil wells can result in severe problems with regard to erosion in valves or bends as well as possible collapse of the reservoir, and filling up of separators. This paper will discuss the erosion based sand monitoring system, and how this has helped the Tordis field operator to operate within optimized, but safe production limits to avoid these problems. The system has operational experience from the last seven years and field data will be presented. The paper will also show data from laboratory tests. And a new temperature and pressure gauge which is included with the probe is also discussed. Finally, the latest erosion correlation model developed together with the Norwegian oil company Norsk Hydro will be discussed. This model gives the correlation between the probe erosion and other critical components in the system, e.g. bends.

INTRODUCTION
The production of sand and solids in oil and gas can represent a major problem in terms of erosion damage. Sand production can also lead to a degradation, or in the worst case, a collapse of the reservoir. Unexpected breakdown of the reservoir and water breakthrough can occur, resulting in increased sand content of the well fluid. Process equipment could also fill up due to the settling of sand. In addition to the safety and production technical aspects of unwanted/uncontrolled sand production, the active use of proper on-line sand monitoring equipment will also have a cost reducing impact since piping tolerances with respect to erosion may be reduced.
Sand control has in the past been sought mainly through downhole techniques like screens/gravel packs. A gravel pack will, however, limit the production capacity from the reservoir, and it has also been seen to fail with drastic consequences. In addition, the cost of a gravel pack operation can make it desirable to seek other solutions. The system presented in this article allows continuous monitoring of the status of sand production and erosion in any type of well, and will serve both as a safety device, and as a tool for optimizing and controlling the oil/gas production. An on-line sand monitoring system can also lower capital expenditures.
By reducing the production system tolerance with respect to erosion. During testing before a well is put into normal production, and at later stages, maximum sand free rate (MSFR) tests with on line sand monitoring can be performed to establish the maximum acceptable production rates. However, downhole conditions can change over time resulting in sand production. This leads to a requirement for continuous sand monitoring.
This paper describes experience from use of an erosion based sand detection and monitoring system. Due to the high sensitivity of the device, any significant sand concentration in the produced fluid/gas will be detected. In addition, the erosion rates read directly from the probe elements can, using direct correlations, be used to quantify the erosion in the piping system itself.
Khazzan Dubai 1: Design, Construction and Installation
Authors: Chamberlin R.S. 
Published: October 2008

ABSTRACT
In early August, 1969, a 15,000-ton, bottomless offshore oil storage tank was completed on the shore of the Trucial Coast of the sheikdom of Dubai. The successful launching, towing and submerging of the tank were spectacular operations receiving world-wide attention. These operations, however, were preceded by extensive research and development programs to answer the many questions surrounding a new or different structure. These include tests of crude and salt water, handling of sludge, model test work and development of construction and installation techniques.

INTRODUCTION
Khazzan Dubai #1, a 500,000barrel oil storage tank, placed in service December, 1969, is located sixty miles offshore in154 feet of water. The structure, the first of its kind, stores oil produced from the Fateh Field. Dubai Petroleum, a wholly owned subsidiary of Continental Oil Company, operates the field for its partners, Dubai Marine Area Ltd. (Compagnie Francaise des Petroles and British Petroleum), Deutsch Erdol-Aktiengesellschaft, Dubai Sun Oil Company and Continental Oil Company. Hispanoil has now replaced British Petroleum as a partner of the DUMA group.
The 15,000-ton structure (Figure 1) is 270 feet in diameter and over 200 feet in height. It has no bottom and operates on the water displacement principle. It is always full with either water or oil or a combination of the two. Filling is accomplished by placing oil in the tank above water. The additional weight of the oil on the water creates an imbalance in pressure which forces the water out of the tank through openings in the wall.
The unusual structure requires special construction techniques which enable it to be built onshore, launched and towed some sixty miles to its offshore location. The launching, towing and submerging were spectacular operations that created worldwide interest throughout the industry. Behind the success of the structure, however, were many years of meticulous study and research.
A new structure such as this brings up unique and special operating conditions which must be considered. These include salt pickup by the oil and sludge buildup at the oil/water interface.
Gaging techniques must be used to remotely monitor the oil/water interface, divert the incoming stream once the tank is filled or shut down the pumps once the tank is empty. Certain operating advantages are expected: free water will automatically precipitate to the water below the oil/ water interface, decreasing the salt content of the crude, and large buildup of wax or heavy ends at the interface can be removed by pumping when the tank is stripped out.
The open sea location where the tank is installed gives ample opportunities for wind to generate large waves (over 39 feet in height with 10-second periods). Coupled with storm-driven currents, these waves create tremendous forces on the oil storage tank. These large forces are resisted by an anchorage system consisting of 36" ? steel piles cemented into the sea floor.
Wave Theoretic Approaches to Multiple Attenuation: Concepts, Status, Open Issues and Plans, Part 1
Authors: Berkhout A.J. , Verschuur D.J. , Weglein A.B. 
Published: October 2008

Abstract
Surface-related and internal multiple removal can be applied in a model driven and a data driven way. A unified description has been proposed that relates both types of wave theory based algorithms. Special attention is given to the removal of internal multiples.

Introduction
A multidimensional inversion algorithm for the removal of surface-related and internal multiples was proposed by Berkhout (1982). Essential in his formulation is that any subsurface model can be handled and, above all, that the data acquisition properties are taken into account. The latter turns out to be an absolute necessity for success on field data.
In his doctoral thesis, Verschuur (1991) successfully demonstrated on field data that the inverse source wavelet can be estimated by making use of a least-squares subtraction process. Recently, Weglein et al. (1997) proposed an algorithm to remove internal multiples with the aid of the multiple scattering theory. Important in this proposal is that no knowledge of the subsurface is required.

Model for surface-related multiple reflections
We start with the basic equations for surface-related multiples in terms of the matrix-vector notation (Berkhout, 1982):
(Mathematical equations available in full paper)
Figure 1: Forward model for primaries (z&gt;z0) and surface-related multiples, the multiple-generating surface being defined by z0=z0 (x,y). (Available in full paper)

Model for the multiple removal process
From equation (1b) it follows that the surface-related multiples are given by
(Mathematical equations available in full paper)
From equations (2a) and (3b) we may conclude that the prediction filter for surface-related multiples is a complex one:It is not only a multi-channel filter, it is also a multi-record filter;Each trace of the multi-record filter represents a scaled primary response of the subsurface.
Hence, for complex subsurfaces the filter may become very complex. In Figure 2 the prediction of surface multiples for one specific source-receiver pair is visualized:
(Mathematical equation available in full paper)
where the source is at xj and the receiver at xi. The inner product of the two vectors in equation (4) describes a summation of the two wavefields along the surface locations. Note that the receiver locations of the data are combined with source locations of the prediction operator. Note also that the prediction lag of Fpr is given by the shallowest multiplecontributing reflector.
Figure 2: Prediction of surface multiples in a data driven approach: the data is used as multiple prediction operator in a spatial convolution along the surface coordinates. (Available in full paper)
A New Approach to Capex and Opex Reduction: An Integrated System for Remote Tie-Ins and Pipeline Repair
Authors: Corbetta G. , Cruden R. 
Published: October 2008

Abstract
The industry move towards deep water is constantly demanding for the development of new and innovative technologies, as well as reduction in costs, to let most of the new reservoir discoveries to be financially attractive. As a result, the demand for designs, which could led to savings in both CAPEX and OPEX is steadily increasing.
As part of their continuos growth, Sonsub International has developed and tested a new system (Brutus) dedicated to the remote tie-in of rigid lines in large water depth. The main design parameters are that it operates to 3000 meters water depth, handles up to 24" diameter pipe and is capable of connecting pipe by using flanges, clamp or collect connectors - as well as special connectors such as Morgrip.
The system will be used during summer 2000 to perform diverless tie-ins of a 16" pipeline and, prior to this, a complete set of shallow water trials will be carried out. Furthermore, the system has also been proposed as a pipeline repair system, due to its working philosophy and Sonsub's knowledge and experience within this field (DSRS - Diverless Sealine Repair System).
This paper will briefly introduce the Brutus system and present the result of the wet trials. Also, the system's pipeline repair capabilities and methodology will be outlined. Consideration about the integrated approach and its advantages with respect CAPEX and OPEX will be given, together with a general analysis comparing the benefit of this concept versus existing tie-ins and/or repair systems.

Introduction
The possibility of utilizing a common system during the completion of a field (CAPEX) and also during its lifetime (OPEX) is a very interesting option, especially for medium/deep waters developments requiring innovative and diverless technology.
Having a large experience in both remote connection technology and repair of either rigid or flexible lines, Sonsub felt that a common approach to both the above topics would be a major step towards cost saving and standardization of equipment for deep water field developments.
As a result of the above, and following the development of both the DSRS (Ref. 1) and the BRUTUS system (refs. 2 & 3), Sonsub has now developed a new concept. The concept is based on the combination of the above systems and will allow Sonsub to offer a single approach to tie-in and repair operations with proven diverless technology.

The DSRS

Background
The DSRS is a development of the original Pipeline Repair System (PRS), first tested in 1992.
A succession of shallow water trials of the various subsystems has allowed optimization of the individual and overall designs.
The final solution is now a "low force" modular concept, which offers the following benefits:It is independent of surface equipment;Low force;In the event of bad weather, the ROV can be recovered and the site temporarily abandoned;Operates using readily available work class ROVs;Can be deployed rapidly from a ROV support vessel;
Proposal for Ocean Drilling Program Research on Gas Hydrate in the Gulf of Mexico
Authors: Sager William W. , Kennicutt Mahlon C. 
Published: October 2008

Abstract
Gas hydrate traps large quantities of hydrocarbon gasses on the continental margins and have potentially important effects on sedimentary geology, climate, slope instability, the carbon cycle, and offshore oil production. The Ocean Drilling Program (ODP) has expressed interest in coring gas hydrate in a variety of environments, including a mature petroleum basin. This article describes a proposal submitted to ODP for a Gulf of Mexico gas hydrate drilling cruise to address this goal. The Gulf is a unique gas hydrate environment because hydrocarbon gas flow is focused along faults which control the location and concentration of hydrate occurrence. As a result, massive gas hydrate deposits occur all the way to the seafloor, in contrast to widely-disseminated layers buried by a few hundred meters as found in many other settings. The drilling proposal targets hydrocarbon seep sites where gas hydrates occur at the seafloor. It is planned that 5–7 locations will be drilled in 1-2 transects at two sites, one at the upper edge of the gas hydrate stability zone (550–600 m depth) and another deeper, where the hydrate layer is thicker and more stable (1000-2000 m depth). At each drilling location, three holes are planned: one to collect core for stratigraphy and conventional sampling, one to fill gaps in the record of the first hole and allow pressure samples and heat flow measurements, and one to acquire logging-while-drilling data. Four sites on the northern Gulf of Mexico slope have been identified for further investigation. Two of these sites are planned for drilling, the others as alternates. One site, at a mud volcano on the border of Garden Banks leaseblocks 424 and 425, typifies a major, active, high flux seep in the shallow gas hydrate zone. The other shallow zone site is at the boundary of Green Canyon blocks 184 and 185 and includes the well-known "Bush Hill" hydrate mound. A site at the border between Mississippi Canyon blocks 852 and 853 is a major seep site in deeper water depths, whereas another located in Atwater blocks 381, 382, 425 and 426 is a deep site inferred to have lesser flux. Currently the proposal is under review by ODP advisory panels, and if approved, it could be drilled in 2002 or 2003.
Table 1. Gas hydrate research team (Available in full paper)

Introduction
Gas hydrates are ice-like compounds in which hydrocarbon gas molecules become trapped within a lattice of water molecules under high-pressure and low-temperature conditions (Sloan, 1990). The proper combination of pressure, temperature, and gas concentration is often found on the upper continental slope. As a result, gas hydrate is found worldwide on continental margins (Kvenvolden, 1993). In many places, the gas is biogenic methane, derived from microbial degradation of organic matter in the upper sediment column. The gas migrates upward and collects into a widelydisseminated hydrate layer located a few hundred meters below the seafloor.
FPSO Integrity: JIP on FPSO Fatigue Loads
Authors: Bultema Stephen , van den Boom Henk , Krekel Max 
Published: October 2008

Abstract
The hull forms used for FPSOs and trading tankers look very similar. So similar in fact that it may appear that one could use the same design and design methods for both vessels. Both vessels will be subject to extreme and fatigue loading and both will have a similar design life. But each will have different design requirements and therefore different designs.
The trading tanker spends most of its life moving oil from one location to another, in either one of two draft conditions, ballast or laden. They are dry-docked at regular intervals for maintenance, inspection and if necessary repair.
FPSOs are stationary, i.e. they have zero forward speed, the vessel's draft is continuously changing, the maintenance and inspection is done in situ, and they are not usually dry-docked.
These apparently subtle differences, see Table 1, in design requirements are not so subtle with respect to the load differences, both short term and long term for the two designs. This difference is the driver for the FPSO Integrity Joint Industry Project.
The JIP was established to obtain fatigue load information on an FPSO through full-scale measurements. The main goals were as following.Develop of a computational model for fatigue loadingEvaluate current practice.Have the Classification Societies conduct a comparative study, andRecommend a fatigue method for use in design of FPSOs.
The work in this JIP is being further enhanced through a sister JIP "FPSO Fatigue Capacity" being administered by DnV. By combining the results of the two JIPs, the industry is gaining a better knowledge of the fatigue loads and fatigue resistance on FPSOs. Predictive methods are being developed to calculate the fatigue lifetime of FPSOs and this is leading toward more reliable systems.

Introduction
In the upstream oil industry it can be generally said that all ideas are bred, birthed and reared from within. In order to maintain this axiom it often means that nothing gets implemented in the upstream sector unless they have thoroughly analyzed and tested it and meticulously prepared proper standards and specifications. The idea of using an oil trading tanker as a floating production, storage and offtake unit is one solution that breaks the rule. It is a crossbreed, a marriage between upstream and downstream, a child of unsuspecting parents. It arrived in time to feed a hunger in the industry to expand operations into the seven seas. It looked positively prefect; it was a solution waiting on a problem. In the enthusiasm to apply the solution not all areas of design and design methods were assessed. The industry has now reached a stage where they are asking the question whether or not shipping standards are applicable to FPSO designs.
The design rules for trading tankers developed through time by trial and failure. In the past, the rules did not recognize fatigue was not a primary issue in ship structure design. In many FPSO cases this is not suitable.