bluuebunny/crossref_metadata_2025 huggingface dataset:
Coral and Estrela do Mar: The Development of a Marginal Field in Brazil
Authors: Portella Ricardo B. , de Souza Lima Heitor A. , Projemar S.A. , Guimarães Carlos Roberto , Munksgaard James  Nascentes
Published: October 2008

Coral and Estrela do Mar are two oil fields located in Santos Basin, 180 km offshore Southeast Brazilian coast, in water depths of 150 m, that are being explored by a consortium composed by Petrobras, Queiroz Galvão Perfurações, Starfish Oil & Gas and Coplex Petroleo do Brasil.

The field exploration is based on a stationary oil production unit and on a floating storage and offloading unit. Based on a public BID, Petrobras, the leader of the consortium, selected the Brazilian operators Petroserv and Transpetro to provide a semi-submersible platform and a FSO and their operation respectively.

Santos Basin area is a quite unexplored region in the South of Brazil with very few offshore resources. The key issue of the project was the very short time schedule available and the necessary high degree of confidentiability needed for the system due to absence of resources on the field vicinity combined to the fact that this area is located in the middle of an important ocean biological reservoir.

This paper describes the engineering work performed for the development of the oil field that was based on the upgrade of the semi-submersible platform Atlantic Zephyr that received an oil process plant with 20,000 bpd capacity, a new helideck, new drain and firefighting systems, a flexible risers system, a ROV platform and stability blisters and on the conversion of the F.S.O Avaré, a 28,000 dwt oil tanker that received an innovative DICAS mooring system, an oil import riser, a helideck, a new deck crane and an offloading system. Even being a low cost project, the development of Coral and Estrela do Mar meets some remarkable achievements. The short time required to start the oil production, the simplicity of the concepts used for the field development, the environmental aspects involved and the mooring systems using torpedo piles are some of the aspects that give to this field a very special position on the Brazilian oil industry.

Introduction

The recent oil exploration activity in Brazil has been mainly noted in the international scenario due to giant projects for the exploration of the large oil fields discovered in the Campos Basin. Marlim field with P37, South Marlim with P40 and P38, Roncador with P36, Barracuda with P43, Caratinga with P48 and Albacora East with P50 are some of these remarkable projects that demand giant floating units.

Coral and Estrela do Mar, two marginal fields located in Santos Basin on the South part of the country, constitute a completely different scenario on the oil exploration activity in Brazil.

As the offshore oil production in this region is still incipient and the logistic infrastructure almost does not exist, the project needs to be simple, reliable and cost effective. To achieve these goals, it was prepared and approved a development plan for the simultaneous exploration of two fields based on a floating production unit, an oil storage unit and oil export shuttle tankers.
HT/HP Pipe-in-Pipe Snaked Lay Technology - Industry Challenges
Authors: Hooper J. , Maschner E. , Farrant T.
Published: October 2008

The Penguins Field is located in the most northern waters of the United Kingdom Sector of the North Sea, approx. 250km NE of the Shetland Isles, Scotland. The pipeline comprises 66km of Pipe-in-Pipe (PIP) in water depths peaking at 170m. The HT/HP pipeline navigates a sinuous route through boulder fields, isolated rock embedment and clay outcrops, around subsea facilities and over several crossings, in regions subject to moderate fish trawling activity.

The highly insulated PIP system was installed in a snaked configuration to achieve significant CAPEX reduction over the very few viable alternatives, such as trench and rockdump. The snakelay design pre-determines a lateral buckling response that relieves the high expansion forces in the operational pipeline, whilst controlling the level of combined loading the PIP system experiences.

The DNV 2000 Limit State design code was utilized in conjunction with the HOTPIPE Guideline to demonstrate pipeline system robustness. The HOTPIPE Guideline is not currently in the public domain, but the principles adopted therein are described in public domain papers.

This paper describes the Detailed Design process for the PIP system, and outlines the associated testing programs. The main emphasis will be given to the application of snaked lay technology, which enabled accurate pre-setting of the lateral buckle initiation sites, as evidenced by the post-operational surveys of the pipeline.

This successful application of PIP snaked lay will help bolster industry confidence at a time when the number of potential subsea applications of this technology is increasing.

Introduction

Field Description and Layout.

The Penguins field is a subsea satellite that is 66km north of its host, the Brent Charlie (Brent C) platform, in the Northern North Sea. Its location relative Scotland and Norway, is shown in Figure 1.

The cluster of four fields was developed using five subsea drilling centers (DCs). Manifolds are positioned at four of them. A single production pipeline is used to tieback the DCs in a "daisy-chain" to the BC platform, crossing two umbilicals, three operational pipelines and one decommissioned pipeline. The pipeline consists of two PIP sizes: 10.75"/16" between DC2 & DC3, and 16"/22" from DC3 to BC, via DC4 & DC5.

Figure 1 Penguin Field Location (Available in full paper)

An Overall Heat Transfer Coefficient (OHTC) of 0.7 W/m2K was specified as a target for the 66km PIP System. This was part of the flow assurance strategy for management of field shutdown and start-ups to limit temperature decay for a given shutdown period. It was also related to wax (which may become a concern towards the end of the field life) and hydrates (the formation region is approached during the last few years of production).

As well as providing electrical and hydraulic power, the 6" umbilical routed from Brent C to the subsea manifolds has provision for methanol, corrosion, scale, wax, and asphaltene inhibitors, to meet whatever needs may arise for field flow assurance.
Study of Chain Slippage for Embedded Anchors
Authors: Neubecker S.R. , O'Neill M.P.
Published: October 2008

There are several different anchor types that rely on the point of application of the chain being below the seabed. These can include anchor piles, suction caisssons, and driven or suction installed plate anchors.

Subsequent to installation in the vertical direction, the mooring chain may be pretensioned to a nominal level in the horizontal direction, cutting through the soil to some extent. During the life of the floating installation, mooring loads will be experienced that are generally greater than the pretension level, and this brings about additional movement, or slippage, of the chain through the soil.

There are currently few guidelines in the public domain regarding the selection of a pretension level that is appropriate for any given installation. This paper will present normalised charts that allow for a quick and simple evaluation of chain slippage versus load, as a function of chain size and soil strength profile.

Introduction

It is generally accepted that drag anchors are the only types of anchor that require a specific amount of pretension on the mooring line during installation. This is to ensure that the anchor penetrates to a sufficient depth to generate the required anchoring resistance. As a consequence of having been pretensioned, the mooring system is generally proved and little additional movement or slippage of the system should result.

Conversely, pile anchors are not required to be pretensioned as they can be designed to have a sufficient factor of safety against geotechnical failure under the extreme loads once installed, and therefore movement of the anchor can be prevented.

In recent times the geotechnical efficiencies of embedding the point of attachment of the mooring line (on pile and plate anchors) have been exploited. This can occur in layered soil profiles, particularly with soft soil over hard soil, where it is beneficial to locate the anchor padeye near the strong stratum. Suction anchors installed into soft soils also typically have an embedded padeye (located about two thirds down the pile) to ensure the load is applied near the centre of resistance of the soil.

Embedment of the anchor padeye results in a situation where significant movement or slippage of the mooring line can occur in the in-place condition as environmental loads are experienced. Yet design codes do not call for a specific level of pretension to mitigate or account for this. It is generally left to the designer to determine the sensitivity of the mooring system to slippage of the mooring line (which can result in greater excursions of the vessel and overstressing of flexible risers) and to pretension the mooring line accordingly.

This paper aims to present a parametric analysis of the development of load as the mooring line cuts through the soil, enabling selection of an appropriate pretension load as a function of allowable line slippage.
Matterhorn Project
Authors: Hurel Jean-Pierre , van der Linden Cornelis
Published: October 2008

This paper addresses a description of the Matterhorn Project as introduction to five other more detailed technical papers on drilling, dry tree design, platform construction, SCR & pipeline design & installation for the same project

The Matterhorn Field located in Block Mississippi Canyon 243 (MC 243) was discovered in 1999 by the well EEI MC 243 #1. It is developed with a SeaStar® TLP designed and built by Atlantia Offshore Limited (Atlantia) under an EPCI Contract with TOTAL E&P USA INC. (Total). First production occurred on Nov 11, 2003, 28 months after project sanction.

Introduction

The Matterhorn Field is located in the Gulf of Mexico in Block Mississippi Canyon 243 (MC 243) by 2,816 ft of water. The block MC 243 is located about 30 miles SE of the Mouth of the Mississippi River and about 100 miles SE of New Orleans (Louisiana).

The Matterhorn field is developed with a SeaStarÂ® TLP with dry trees and it is the first dry tree TLP designed by Atlantia Offshore Limited. Total E&P USA INC. has a 100% ownership in Matterhorn.

The platform design flowrate is 33,000 BOPD and a 55 MMcfd with a field life of 20 years.

Seven future dry tree wells and one sub-sea water injection well were drilled between December 2001 and October 2002 by the dynamically-positioned semi-submersible drilling unit ENSCO 7500. Most wells are high angle, shallow kick off deviated well reaching in some case 70 deg of deviation.

The TLP has been engineered and built by Atlantia under a lump sum EPCI contract. The 84 ft diameter hull was built at Keppel FELS shipyard in Singapore while the 140 ft × 140 ft, 6,000 t deck has been built at the Gulf Marine Fabricators (GMF) yard in Ingleside (TX).

Two 16 mile pipelines (10 in and 8 in) were installed in April/May 2003 by Technip Offshore Construction, Inc. (TOCI) dynamically-positioned reel-ship Deep Blue. These pipelines are connected to the platform by 10 in and 8 in Steel Catenary Risers (SCR).

The platform is linked to the sea bottom by six 32 in tendons installed in June/July 2003. The hull and deck were installed in July/August 2003.

The 1,000 HP Nabors Offshore Corporation (Nabors) Super Sundowner XVI work-over rig has been installed on the platform using the platform cranes. This unit, after running the seven 10 in risers connecting the existing wellheads to the platform is presently performing the well completion which should last until Mid 2004.

The project was sanctioned in July 2001, the TLP was installed in August 2003 and first production was achieved on November 11, 2003.

Development Plan

Total has a 100% interest in block MC 243 in which the Matterhorn Field is located. The water Depth at the TLP location is 2, 816 ft.

The main producing sands are Plio-Pleistocene age ranging in depth from 3,000 ft to 7,500 ft below mud line. The Matterhorn Field was discovered early 1999 by the well EEI MC 243 # 1, which was drilled as an offset well to the well Conoco MC 243 #1 which discovered gas in 1990 in the deep E horizon (~10,000 ft).
Na Kika - Novel Development in Record Water Depth
Authors: Luyties W.H. , Freckelton T.P.
Published: October 2008

The Na Kika Development is located in record water depths in the US Gulf of Mexico. The project, a joint effort by Shell and BP, is a subsea development of five independent fields tied back to a centrally located host facility. The subsea infrastructure consists of 10 wells connected via three 25-mile flowline loops, 23 flowline sleds, and 50 miles of umbilicals to the semi-submersible shaped host with topsides facilities for fluid processing and pipelines for oil and gas export to shore. A sixth field will be tied back in 2004, and the host and subsea infrastructure is designed and built for other tiebacks to enablefurther development in the area.

This novel co-development is the result of an 18-year effort to discover sufficient reserves to support a development, understand the complex geology of the area, identify an economical development system, and design, construct, and install the system. In addition to the usual issues surrounding a $1.4B development, Na Kika faced and overcame numerous other execution challenges, including aggressive cost and schedule targets, application of new technology, regulatory issues, HSE management, a difficult contracting climate, and a protracted installation campaign during an active hurricane season. As a final challenge, the Na Kika Joint Operating Agreement required a transfer of Operatorship from Shell (Development Operator) to BP (Production Operator) upon production of the first well.

First production from Na Kika was achieved on November 26, 2003.

Novel Co-Development

The Na Kika Development is located approximately 140 miles southeast of New Orleans in water depths ranging from 5,800' to 7,000 feet. The project is a subsea development of five independent fields - Kepler, Ariel, Fourier, Herschel, and E. Anstey - tied back to a centrally-located, permanently-moored floating development and production host facility situated on Mississippi Canyon Block 474. Shell E&P Americas (Shell) and BP are joint owners (approximately 50% each) of the five primary Na Kika fields. The Kepler, Ariel, and Herschel fields are predominately oil while Fourier and East Anstey are predominately gas.

A sixth field, Coulomb, a gas field owned by Shell and Petrobras, is in a water depth of approximately 7,600' and will be tied back to the host facility as well.

The five Na Kika fields can be considered small to medium sized ranging in size from 20 to 100 MMboe, with the largest being the Kepler field. None of the fields on its own could be developed economically with the technology available today. In fact, the total recoverable hydrocarbons from the Na Kika development are approximately 300 MMboe. Although this, in total, is a reasonable amount of hydrocarbons for a development in the deepwater Gulf of Mexico, given the complexity of a multi-field subsea development in record water depth, Na Kika can be considered a marginal development. For detailed information on the Na Kika subsurface, see Ref. 1 (OTC 16699).
Improvements Achieved in the Project of FPSO P-50
Authors: dos Santos Aldemir Bonfim , Henriques Carlos Cunha Dias , Pimenta José Maria Mario Hollanda Alvares
Published: October 2008

In the last 10 years, Petrobras has converted 8 existing tankers to operate as FPSOs/FSOs in Campos Basin, offshore Brazil. The lessons learned from the conversion of those Units highlighted the importance of taking into consideration the concepts of constructability and clean arrangement in the design of FPSOs.

The project of FPSO P-50 was developed with those concepts in mind and then, the philosophy of the following main systems was changed from previous FPSO projects:Cargo and ballast systems: Use of individual submerged cargo pumps, eliminating the cargo pump room and the communication between the cargo tanks;Sea water lift system for water injection: Use of electric submerged pumps;Fire Fighting System: Use of Diesel hydraulic fire water pumps with submerged hydraulic driven booster pumps;Offloading system: Use of reels to store the offloading hose, instead of a chute system;Marine systems: Development of a new arrangement concept for the main deck marine systems pipe rack;Mooring System: Use of a spread mooring concept instead of turret system and use of free fall piles to anchor the FPSO. The intention of this paper is to describe the modifications made in those systems, explaining the reasons to adopt them and stressing the benefits brought to the project.

Introduction

Albacora Leste Field Project:

The Albacora Leste field (Figure 1) was discovered in March 1986 by the wildcat 1-RJS-342A. This 600-km2 field lies 125 kilometers off the coast of Rio de Janeiro, at water depths from 800 to 2,000 meters. The field is comprised primarily of Miocene turbidite sandstones (Ref. 1).

The Field Development will comprise 16 subsea production wells producing 180,000 bopd through individual bundles (Figure 2) to the FPSO P-50 located at 1,240 meters water depth. The water injection, totalizing 35,000 cubic meters, will be achieved through 15 subsea wells. P-50 (Figure 3) is a former VLCC that is currently under a process of conversion to a production Unit.

After processing and treatment in the FPSO, the oil will be stored inside the tanks and later exported to shore via shuttle tankers. The compressed gas will be exported through a 10- inch gas pipeline up to a subsea PipeLine End Manifold (PLAEM) that will be connected to an existing fixed platform through a new 20-inch diameter pipeline. From this fixed platform, the gas will be sent to shore through the existing gas network pipeline.

FPSO Projects In Campos Basin:

The first mono-hull floating production Unit to operate in 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. In 1979, a 60,000 bpd process plant was installed on the ship to allow it to operate in the Garoupa field. In 1987, P.P. Moraes was relocated to Albacora Field. The system operated continuously from September 1987 up to March 1993 with no significant downtime (Ref. 2, 3 and 4).
The Influence of Passing Ships on Ships moored in Restricted Waters
Authors: Pinkster J.A. , Ruijter Michel N.
Published: October 2008

Ships moored in harbours are subjected to hydrodynamic forces due to other ships passing nearby. Such forces induce motions of the moored ship which may hinder loading/discharging operations or cause damage to the mooring system. These forces, sometimes known as suction forces, are associated with the primary pressure system around the sailing vessel which acts upon the moored ship. In this paper some of the aspects which play a role in effects due to passing ships will be treated. In order to do so, two computational methods developed by the first author to predict the low frequency forces due to a passing ship will be used. The first of these is based on implementation of the so-called 'double-body' flow method previously introduced by other authors.

The second, newly developed, method applied in this paper predicts passing ship effects also taking into account free surface effects due to the passing ship and the additional forces these exert on the moored ship. Results of both computational methods are compared. Full scale tests were carried out by Svasek Hydraulics and MARIN on behalf of the Port of Amsterdam. These tests involved, among others, measurement of the mooring forces of a fully loaded barge during the passage of large vessels in the Noordzeekanaal which joins the Port of Amsterdam to the North Sea. Results of these measurements are compared with computations. Finally, an unusual case involving the generation of solitary waves by a vessel in a canal is treated.

Introduction

Passing ships create disturbances in the water which result in forces on other ships and floating structures. Such hydrodynamic forces can result in high mooring forces and unacceptable motions of the moored vessels. In extreme cases, mooring lines of ships have parted which in one case, see NTSB report [1], resulted in loss of life and total loss of the moored ship due to fire. Such cases are extremely rare but hinder and damage due to passing ship effects are a regular feature of life along the waterways and in harbours. With the increasing awareness of and decreasing tolerance relative to personal injuries, environmental impacts and damage to facilities and ships, more attention is being focussed on evaluation of such effects whenever major changes are made with respect to the vessels plying the waterways (larger, faster), the waterway geometry or traffic volumes.

At the Delft University of Technology research has been conducted into methods to predict the effects of passing ships on moored vessels. Such effects have in the past concentrated on suction effects associated with the primary or "doublebody" flow around the passing vessel. See, for instance, King [2]. By definition, this means that real free-surface effects, i.e. surface wave propagation effects, are not accounted for. The reason for basing the effects of passing ships on double-body flow models is that generally such ships are moving at low Froude number values, even when viewed in relation to the waterdepth.
Eugene Island 322 'A' Drilling Platform Decommissioning After Hurricane Lilli
Authors: DeFranco S.J. , Fitzhugh J.T. , Locke H.A. , O'Connor P.E. , Straub T.J. , Morahan D.J.
Published: October 2008

This paper describes the cause of failure of BP's Eugene Island 322 'A' (EI-322 A) Drilling platform during Hurricane Lilli and BPâ??s response to this event. BP's project team planned and implemented temporary strengthening of the platform so that well decommissioning could take place in a safe and environmentally sound manner during the peak of the 2003 hurricane season. Well decommissioning was successfully completed by November 2003. BP's health, safety, and environment (HSE) values were strictly adhered to throughout the project with zero injuries or environmental events.

Introduction

Hurricane Lilli passed through the Gulf of Mexico in early October 2002. At its peak, the storm reached Category 4 on the Safford-Simpson scale with maximum sustained winds exceeding 140 mph. The stormâ??s eye passed through the Eugene Island 322 block. In the days immediately following the storm, BP learned that the EI-322 A Drilling platform was leaning and had sustained severe damage to the deck and bridge.

The EI-322 'A' platforms are typical of TAMPA complex (Hancock and Peavey, 1975) that was widely used by Amoco from the late 1960s until the early 1990s. The TAMPA concept consists of two, adjacent, four pile platforms linked by a relatively large bridge. The main function of the TAMPA was to replace one large 8-pile platform, which was typical of that time, with two significantly lighter platforms. One of the TAMPA platforms serves as a drilling/quarters platform with on-board rig capability while the other platform provided tender support during drilling operations. Post drilling, the tender platforms were converted into the production facility. The bridge supported the production flow lines as well as several small buildings.

The EI-322 'A' platforms were installed in 235 feet of water by Amoco in 1978. The primary design criteria for the facilities were a 70-foot 13-second wave, zero current, and a 125 mph wind. The design drag (Cd) and inertial (Cm) coefficients for the Morison equation were 0.65 and 1.35 respectively. These design values are more conservative than the API RP2A 9th Edition recommended Cd, Cm values of 0.6 and 1.5 respectively thereby exceeding the design basis check in API RP 2A Section 17. A preliminary wind-wave-current hindcast of Hurricane Lilli indicated that the storm generated a 56-foot maximum wave (Driver, 2002) in the EI-322 block, which is significantly lower than the original design criteria.

Figure 1 is a photograph of EI-322 'A' drilling before Hurricane Lilli. Figure 2 shows the complex after the hurricane. The top deck translated approximately 85 feet from its original position causing extensive structural damage to the deck and deck legs. Figure 3 shows a closer view of the buckled A-1 leg (NW location). For reference, Figure 4 shows the orientation of the EI-322 'A' complex as well as the leg nomenclature. The B-1 leg almost totally separated from the deck as is shown in Figure 5.
Scientific (and Unscientific) Petroleum Supply Forecasting
Authors: Lynch Michael C.
Published: October 2008

In the past few years a number of publications have asserted that world oil production is near peak due to geologically derived scarcity. Although these analysts purport to be scientific, they are in fact merely curve fitting. Within a fixed, geologically homogenous basin it is possible to model discovery sizes. But at the national level, political factors such as fiscal regimes, access to perspective areas, technological challenges in different basins, and the economics of given plays tend to be determining. At the global level, demand determines production while politics heavily influences discoveries. That most of these analysts rely heavily on unproven-or disproven--assumptions is indicative of the quality of their research.

In fact, forecasting of both discoveries and supplies is extremely difficult, because of the uncertain nature of field size and because of the heavy influence of individual national economic conditions-infrastructure as well as fiscal regimes-and heavy restrictions on drilling by the private sector. Scarcity can be very roughly estimated by looking at a number of factors, including costs and reserve values, discovery size, drilling density, and well productivity, and none of these supports the alarmist views of a peak in world oil production over the next decade or two.

The importance of petroleum to world economy can hardly be overstated and is not at issue, nor is the importance of the adequacy of future oil supplies. But consideration of these topics should be based on real evidence and hard research rather than polemics. Much of the writings of the past few years, while aimed at a general audience, have not added to our knowledge of the subject and have often been misleading. There is a significant body of research on petroleum supply behavior, but much of it is ignored in the current debate.

All that's old made new again

A number of the arguments being heard have been around for quite a long time, including the general concern about resource depletion, fears of the inadequacy of capital to meet investment needs, as well as worries about concentration of petroleum resources in unstable areas. The fact that these concerns have never had any operational value does not mean they can simply be ignored. Nor does the fact that many mistakenly have predicted resource exhaustion for decades mean that current warnings should be ignored, rather they should be considered carefully in the context of past failures.

Unquestionably, there are numerous articles by industry insiders describing the difficulties and challenges which the explorationist faces when trying to find and produce oil. But the fact that it may be getting harder to find a given amount oil, or that capital needs may be growing, does not really tell us much about long-term oil production. It usually indicates a desire for tax breaks, or an appeal for more capital or easier access to prospective areas, rather than concerns that supply is about to peak. Similar warnings have been made for decades, without proving valid or relevant.
The Iron Grip of Depletion
Authors: Zagar J. , Campbell C.J.
Published: October 2008

When we recognize that oil and gas were formed in the geological past, we admit that they are subject to depletion. Production in any place has to start at zero on discovery and end at zero on exhaustion, reaching a peak in between. Yet, such an understanding confounds classical economics, which holds that there can be no shortage in an open market and that one resource is seamlessly replaced by a substitute as need arises.

With modern methods, engineers can determine the size of an oilfield accurately, so there should be no particular technical difficulty in determining where we are on the depletion curve. The problem is in the reporting. In plain language, Proved Reserves, mean Proved-so-Far for financial purposes, not necessarily describing the full field. The consequential "Reserve Growth" gives the misleading impression that more is being found than is the case. Todetermine our position on the depletion curve we need the right numbers and the right dates of discovery, and we need to define carefully what to measure. Oil from a free flowing well is not the same as hydrocarbon extracted from a tar sand.

If we could hire detectives to smoke out the real 2002 data for what we can call cheap and easy Conventional Oil (excluding tar sand and heavy oils, deepwater and polar oils, and NGL from gas fields), we would probably find that the World has found about 1770 billion barrels. Of that, about 870 Gb are left. Extrapolating discovery shows about 130 Gb more to find. We are therefore close to the half-way mark when production must begin to decline, reflecting the peak of discovery in the 1960s. Furthermore, what is left is most unevenly distributed. It is as simple as it is disturbing. The last Century was driven by a cheap and abundant supply of oil- this Century won't be.

Introduction

Discovery of conventional oil peaked in the mid-1960s. Since the early 1980's production has out-paced discoveries by nearly 150 Gb-roughly one and a half times the reserves of Iraq. Today, even with advances in technology and including deep water developments, only one barrel is found for every three barrels produced. With declining discoveries and increasing demand, the debate within the industry is if world oil production is nearing peak and may in fact be on plateau.

Conventional vs. Non-conventional Oil Reserves

It is common practice to distinguish conventional from nonconventional hydrocarbons. The family of hydrocarbons is a large one. Each member has its own endowment in Nature, its own characteristics, costs, and depletion profile. It is obvious that you can deplete light oil flowing 20,000 barrels a day from a Middle East well much more quickly than you can extract oil from a heavy tar sand in Canada. About 95% of all oil produced to date-and 90% of todayâ??s production-comes from this group of hydrocarbons called conventional oil. It will continue to dominate supply until well past peak.
Statistics of Ocean Wave Groups
Authors: Nolte K.G. , Hsu F.H.
Published: October 2008

Statistical parameters are derived that describe the occurrence probability for the number and height of consecutive waves in a group, which are large compared to the average wave height. Such wave groups can create extreme forces in mooring lines of large vessels. All of the parameters that describe the statistics of wave groups can be derived from the energy spectrum representing the sea state, if the energy spectrum is assumed to contain only a narrow band of wave frequencies. Good agreement was found between the theoretical expressions derived in this paper and actual wave data.

INTRODUCTION

It has been shown by Hsu and Blenkarn1 that the long period sway motion and peak mooring line force observed in a model study of a barge resulted from the combined action of a sequence of consecutive high waves in the rand Oil: wave train. Such a sequence of waves will be referred to as a wave group. Independent model tank tests conducted by Remery and Hermans2 substantiated the findings presented in Ref. 1. It is anticipated that the action of wave groups may also be important in other types of ocean engineering systems that are subjected to horizontal motions with periods much longer than the period of individual waves. Such systems could include dynamically positioned vessels. In the analysis and design of such systems it would be prudent to check whether the action of wave groups could subject the systems to motions beyond those calculated on the basis of individual waves. One can either use recorded wave groups measured in the sea, or wave groups generated in a model tank as a basis to perform such a check. There are also available electronic and numerical methods to simulate ocean waves. However, in order to make proper engineering decisions, one would need to know whether the occurrence of such wave groups is a common or rare event. More specifically, one would require a probabilistic description of the basic characteristics of wave groups in order to assess the likelihood of a system to survive.

The purpose of this paper is to develop tools with which one can characterize the statistics of wave groups in terms of occurrence probabilities. No attempt is made in this paper to illustrate how such statistical tools could be used in practical engineering. It is believed that development of rational procedures to utilize such tools for specific problems can best be developed by individual users.

THEORETICAL DERIVATIONS

In this paper a wave group will be defined in terms of the envelopes of wave crests and troughs as shown in Fig. 1. The distance between the crest envelope and the trough envelope will be called the height envelope, whereas the distance between the crest envelope and the mean water surface will be called the amplitude envelope. The height envelope indicates the change of wave heights. Similarly, the amplitude envelope indicates the change of wave amplitude. In reality, ocean waves are not symmetrical as is implied by the term, amplitude.
General Elastic Inversion, Orange Basin Case Study
Authors: Berge T.B.
Published: October 2008

General Elastic Inversion is a specific inversion process that is designed to combine both ?Vp (pseudo compressional interval velocity) and ?Vs (pseudo shear interval velocity) volumes in a straightforward and meaningful way to emphasize pore fluid type. The calibrated results are simple and values nonarbitrary. Good data seismic quality and high fold are preferred, and a good quality dipole sonic curve from an area well can be used for calibration but is not required.

In essence the process has 2 steps and proper execution of both is required to get good results. The first step is generation of the ?Vs and ?Vp volumes and the second step is the combination and re-projection of the ?Vp and ?Vs volumes.

A critical step is generation of the ?Vs volume which must be done in the pre-stack domain. The objective is to estimate converted-wave shear amplitude at different offset angles. On problem is that some methods result in only a linear transform of the P-wave amplitudes which will not produce a separation of gas and water cases in the P and S crossplot domain. We present a rigorous 'full Zoeppritz' solution involving ray-tracing that provides meaningful, nonlinear calculation of what the converted shear-wave amplitudes by offset would have been had they been recorded. In essence, the S wave AVO is modeled.

Secondly the P and S reflectivity volumes are inverted, scaled to pseudo-velocity, and then calibrated to well control. The resulting ?Vp and ?Vs volumes are combined and reprojected to produce a 'fluid' volume and a 'porosity' volume. The process is simple enough in concept that we propose it as a general solution to Elastic Inversion. Like the Fluid Factor (Smith and Gidlow, 1987) and Rp-Rs (Castagna and Smith, 1994) methods it combines both volumes by summation of Vp and Vs.

Examples are from the giant Ibhubesi gas fields offshore the Republic of South Africa in the Orange River Basin,Fig. 1, Location of Ibhubesi Gas Field, offshore the West Coast of the Republic of South Africa. (Available in full paper) however this method has been used in other area, both land and marine, with excellent predictive results.

Introduction to the Inverse Problem

What is Inversion? The name implies it is an inverse method, that is-one that has multiple possible solutions. This is the opposite of the forward method, where the conditions and experiment are known and the results are measured and repeatable. The results are always the same and the experiment may be repeated. With the inverse method (and more specifically the 'Inversion' used here,), the results and experiment are known and we are asked to solve for the original conditions. While it is true that there are multiple solutions, that is different geologic conditions may give rise to the same measurement, usually the practical possibilities may be narrowed. Most geological problems are in fact inverse procedures and understanding this relationship is both simple and profound, as non-uniqueness imposed by the inverse method is the fundamental reason for risk and uncertainty in Geology and Geophysics.
Does Our Prestack Data Support the Assumptions of Prestack Imaging and Inversion?
Authors: Calvert Rodney
Published: October 2008

The earth is heterogeneous at all scales. Our seismic reflection data is the result of waves that have traveled up and down through many heterogeneous layers. The data distortion caused by this is not corrected by current processing techniques and invalidates many of the assumptions we use interpret it.

We have developed a method to image through severely distorting overburden by placing geophones under it.

Introduction

When we compare the images from two surveys over the same area, as we might for 4D analysis, we find they are not at all equal. Even after trying to match them by scaling and a transfer filter their difference will generally be as great as the data itself. Clearly both of these images cannot be correct!

4D work has shown us that it is very difficult to repeat seismic data. The principle cause of non-repeatability is not obvious things like changes in source signatures or receiver coupling; transfer filters can readily fix these effects. We find that small geometry changes such as moving a shot or receiver a few meters gives us different data.

This means that unless we use fixed acquisition geometry our results are not reproducible. The effects turn out to be large. We will use the term "distortion" to describe the focusing, defocusing, scattering and local reverberation effects of transmission through heterogeneous layers. We are trying to do the equivalent of looking through multiple layers of toilet glass.

Our current seismic methods do not correct for this. PSDM only corrects for the long wavelength effects captured in our simplified velocity models. As we shall see, in 4D, if we closely repeat our geometry in two surveys we can difference or divide out the effects of distortion and systematic noise when we estimate the change signal. Our 3D one off data we do not have this luxury. This is the reason why good 4D data pairs can enable us to see reservoir changes where the reservoir may not be recognized on 3D. It is clear that our prestack data is distorted.

Thus our data does not support the simple idea that our imaged traces T(t) may be given byT(t) = Rxyz(t, ?) * w(t) + N (1) where Rxyz(t, ?) is the reflectivity at x,y,z for reflection angle ?, and w(t) is the wavelet. This equation, the basis for most inversions, AVO and quantitative must be generalized to account for distortion.

Our work suggests that it will never be practical to entirely correct surface data for overburden distortion and impossible for severe targets, for instance under karst topography, basalt or rugged salt bodies.

The solution for these difficult cases has to involve new acquisition and processing. We have developed, what we call a Virtual Source technique, which allows us to simply generate a known and controllable downward radiating source below the problem heterogeneities. The penalty for this technique lies in placing geophones below the problem heterogeneities. Drilling and sensor technologies now make this method technically feasible.
A Wave CI imatology for U.S. Coastal Waters
Authors: Thompson Edward F. , Harris D. Lee
Published: October 2008

Over the past 20 years, the Coastal Engineering Research Center has operated wave gages along the Atlantic, Pacific, and Gulf coasts of the U. S. Cumulative wave height distribution functions for ten gage locations have been studied in the format of the exponential distribution. One complete year of data, at six observations per day, appears to give a reliable wave height distribution up to the 1% level of occurrence. Wave data from shipboard weather reports have been compared to wave gage data and found to be of some use in describing long term summaries of coastal wave height conditions.

INTRODUCTION

Ocean wave sensors, operating in the harsh environment of coastal waters, record a complex phenomenon which is not easily interpreted. The simplest analysis approach is to characterize wave conditions from each record by a single wave height and wave period. The Coastal Engineering Research Center (CERC) has accumulated a body of wave data of this type determined from pen and ink records. These data, despite their limitations, contain useful wave climatology information. Reports from shipboard observers provide a body of less precise wave information for offshore waters.

WAVE GAGE DATA

Since 1948, CERC has been operating wave gages at various locations along the coasts of the United States (Figure 1). Gages have been placed and maintained in water of depths from 3 meters (10 feet) to 30 meters (100 feet) below Mean Sea Level, but most data have been taken in water from 3 meters to 8 meters (25 feet) deep. For each gage location, data have been recorded over a period of time ranging from a few months to over 15 years.

Most wave data were obtained with the step resistance type gage (a staff gage) described by Williams (1969). For many years the step resistance gage was the only type of surface wave gage which operated with consistency in the ocean environment. Recently other reliable surface gages have become available. One type, which interferes less than the step gage with the waves, is the continuous wire gage. A comparison of objective wave height estimates (Esteva and Harris, 1970) based on simultaneous records from these two gage types has shown that estimates of significant wave height from the step gage records are on the order of a foot or 20% higher than the estimates obtained from the continuous wire gage records (Figure 2, from Harris, 1972). Wave height estimates from pressure gage records reported by Esteva and Harris, corrected to surface conditions, agree well with height estimates from the continuous wire gage.

Pen and ink wave records, usually 7 minutes long, were recorded every 4 hours at gage sites until May, 1966; since then, data from some gages have been transmitted directly to CERC via telephone line. These data are recorded at the CERC laboratory in the form of pen and ink records and, in digital form, on magnetic tape. In July, 1971, most gage stations were modified to obtain pen and ink records every 6 hours, to coincide with synoptic weather charts.
From removing to using multiples
Authors: Berkhout A.J. , Verschuur D.J.
Published: October 2008

In the last decade much progress has been made to remove multiples from seismic data. So far, multiples have been considered as noise and, therefore, after the removal process multiples are thrown away. In this paper, we will show that multiple reflections contain a wealth of information that should be used in seismic imaging.

Introduction

In the history of multiple removal, algorithms have been based on two differentiating properties: moveout and predictability. If primaries and multiples show different moveout behavior, algorithms are available that allow separation of primaries and multiples in a transform domain. A weak point of moveout algorithms is that they become less effective in the situation of complex wavefields (think of nonhyperbolic wavefronts), or when the moveout of primaries and multiples are alike (e.g. deep data).

Predictability has always been important in multiple removal. In the early days of seismic processing (the 1960's), single trace statistical prediction was very successful (Robinson, 1957). In the early 1980â??s prediction-error filtering has been given a wave theoretical base, providing a unified theory for surface-related and internal multiples (Berkhout, 1982). It has increased the effectiveness of multi-channel prediction-error filtering significantly (Verschuur, 1991). Nowadays, multiple removal algorithms are to a large extend presented by wave theory based multi-channel prediction-error filters.

Recently, a third direction in the theory of multiple removal was proposed that is inspired by the double focusing process as it occurs in seismic migration (Berkhout, 1997). The new theory is based on the so-called focal transform. Forward focal transformation transforms primary energy into its focal point around zero time. After an imaging step, the result is input to the inverse focal transform leading to the desired multiple-free output. First results indicate that combined prediction and imaging may lead to the next paradigm shift in multiple removal.

Figure 1: a) Feedback model for primary reflections (m > 0) and surface-related multiples, the multiple-generating boundary being given by z0=z0(x,y) and the downward reflection operators of this boundary being represented by the columns of the matrix R^(z0). b) One basic element of the weighted convolution process for surface-related multiples, visualized in terms of simple raypaths (m > 0). (Available in full paper)

Removal of surface-related multiples, the prediction approach

The so-called feedback model shows that prediction of multiples requires a weighted convolution process with the primary response (Berkhout, 1982). If an estimate of the primary response is available, the convolution process becomes iterative. The convergence turns out to be fast, even if one starts with the total dataset as primary estimate (Verschuur and Berkhout, 1997). Let us reconsider the feedback model, using the detail-hiding operator notation (see also Figure 1)