bluuebunny/crossref_metadata_2025_split huggingface dataset:
The cost efficiency of the new marine seismic technology.
Authors: Berteussen Karl-Andreas 
Published: October 2008

Abstract
In this presentation we describe marine 4C seismic. We will present our opinion as to where and how this technology will be applied and how it will affect the industry in the future. Finally we try to evaluate its cost efficiency. In particular for high cost environments, like deep water fields, we conclude that it is indeed very cost efficient in that it moves the risk from long term and often costly drilling to short term and in this context relatively inexpensive seismic.

Introduction.
In the 19th century, we found oil by seepage, in the 20th century by drilling and in this century we will find it by geophysics. The background for this statement is the progress that has been made in geophysics, in particular with the now well established 3D technique. In addition there are a number of new seismic techniques being introduced like 4D, 4C, and VC. Behind these sometimescryptic acronyms, lie a considerable amount of investments in equipment and experiments.
Opinion surveys evaluating which technologies have had the greatest impact on the industry, typically ends up with seismic at-or near the top. Still, there is generally a feeling that these new seismic methods have taken more time than expected to become established products. Why is the industry so slow in adapting these methods?
I believe that sea bottom 4-component seismic is the best example to use in this discussion. Possibly marine 4D is a hotter topic in many ways, but I feel here the roles are fairly simple; i.e. to the extent 4D is repeated marine streamer, the "tools", like acquisition and processing are basically ready and free to be used by the oil companies. Of course there are some important aspects as to how to interpret these data, but that is not a cost intensive topic.
Then 4D might develop into the "electrified oil field", i.e. fixed installations. In that case both the technology and the business models are so immature that it is too early to judge the cost efficiency and the impact on the industry. For VC (Vertical Cables in the sea) we are evaluating the results of surveys already done. If they are found positive enough this will be applied as ordinary, although very high resolution P-wave data for particular problems.
As mentioned, at the moment I therefore feel that the best case to evaluate this on is 4C seismic. This technology has come so far in its development that we already can make an assessment as to its possible impact on the industry. The list of achievements is impressive and we also know relatively well what the cost of applying this technology will be. By now we should therefore be able to make a judgement, is this just being pushed by technology-fanatics or is it really a cost efficient method that the industry should apply on a large scale?
In the following I will describe marine 4C seismic.
Meren Field, Nigeria: A 4D Seismic Case Study
Authors: Lumley D.E. , Nunns A.G. , Delorme G.E. , Adeogba A.A. , Bee M.F. 
Published: October 2008

Abstract
In 1996 Chevron Nigeria Ltd. acquired a repeat 3D seismic survey over the Meren Field, offshore Nigeria, for time-lapse seismic reservoir monitoring purposes. By comparing the 1996 survey with a Chevron legacy 3D survey dating from 1987, the time-lapse 4D seismic images show evidence of significant reservoir fluid changes during the 9-year interval1. A detailed 4D seismic interpretation of the Meren E-05 reservoir sand in Block 2, based on horizon amplitude extractions from the 1987 and 1996 cross-equalized seismic cubes, is consistent with well production histories at 22 of the 24 wells that penetrate the reservoir. The remaining 2 well inconsistencies are possibly due to limited seismic resolution. 1D seismic modeling from Meren well logs shows that waterswept oil zones can decrease in impedance and seismic amplitude by as much as 40% from original oil-full conditions. Using the modeling results to calibrate the seismic images to the well production data, map estimates of injected water and bypassed oil are created. The 4D seismic interpretation suggests that water from two injectors has very preferential channel-flow characteristics, indicating a strong stratigraphic flow-unit overprint on the reservoir not previously discernible from well data alone. In addition to identifying pathways of injected water flow, the 4D seismic interpretation has identified three areas within the E-05 that may contain major bypassed oil reserves, and has better defined the leaking or sealing nature of reservoir faults.

Meren Field, Nigeria
The Meren Field is located southeast of Lagos, Nigeria about 10 miles offshore in 50 feet of water. Meren is one of the largest and most prolific producing oil fields in the area. There are six major fault blocks, each block containing up to a dozen productive reservoir sands, with more than 40 total producing sands. The total estimated original oil in place is 1.8 billion barrels, of which about 750 million barrels have been produced to date. Recovery factors are typically high in reservoirs with good pressure maintenance through water injection or aquifer support. Meren was discovered in 1965 and first production began in 1968. Over 80 producer and injector wells have been drilled to date. Current production from the field is about 85,000 barrels of oil per day. The productive sands range in depth from 4,800 to 9,500 feet. The reservoirs are part of a set of sand-shale retrograde/prograde near-shore depositional sequences. Many of the reservoirs, but not all, are below bubble point and have gas caps that have enlarged or decreased during production, which can complicate 4D seismic monitoring of oil and water. The oil is fairly live seismically at Meren with a solution GOR on average of 400 scf/stb. This gives a good compressibility contrast with reservoir brine that is advantageous for seismic monitoring of oil-water saturation fronts.

Seismic Data Acquisition
The first Meren 3D seismic survey was shot in 1987 as a Digiseis survey.
A New Technique for Acoustic Data Analysis
Authors: Nelson Joseph L. 
Published: October 2008

INTRODUCTION
A new technique for the spectral energy analysis of acoustic data taken during bottom and subbottom profiling surveys will be described. This technique is intended to be an additional tool for the evaluation and analysis of subbottom data.
Single frequency acoustic systems [sonars] are widely used for bottom and subbottom profiling in shallow and deep waters. The system consists of a pulsed transmitter, a transducer or transducers for coupling acoustic energy into and out of the water, a receiver and a display such as a graphic recorder.
A single transducer may be used as both the transmitter and receiver, or separate units can be employed. Transducers may be mounted to a ship's hull, or in towed vehicles [fish].
The echoes from the bottom and subbottom features are displayed on the recorder for immediate evaluation, and can also be recorded on magnetic tape for further processing.
It is the purpose of the new analysis technique to extract additional information from these echo signals to allow more accurate identification of features and properties of the bottom and subbottom.
This method, when used in conjunction with bottom sampling and coring operations, can establish the basic reference datums for a computer-aided automatic analysis system. When fully operational, this system with automatically identify subbottom materials and geologic features.
The data display of conventional profiling recorders will be reviewed and then the basis of the new technique will be presented. The new display resulting from the energy analysis will be examined using acoustic signals from several sources, and the basic computer aided analysis system will be described.

ACOUSTIC PROFILING

Basic System Charts
Classically, the data gathered from subbottom surveys is presented as a profile chart shown in Fig. 1. These records are interpreted and analyzed relying on prior experience in reading the records) and correlation with core borings is used to identify specific materials.
The abscissa [horizontal axis] is the linear distance along the survey track and is a function of the speed of the transducer over the bottom. The ordinate is the time for the echo to return to the receiving transducer and is calibrated in depth [feet or fathoms] of the reflection below the transducer. The depth calibration is based on a sound velocity in water. The depth calibration is corrected for the two-way travel of the sound energy from transducer to bottom to transducer.
The intensity of the echo is a function of both the reflecting material and the acoustic properties of adjacent strata. Therefore) in order to completely identify a particular subbottom layer) it is necessary to evaluate the echo from that layer of interest in conjunction with the echoes from overlying material. These echoes are qualitative indications of the acoustic parameters of the strata. The analysis and interpretation of these parameter must start from scratch, due to the lack of any established standards against which new data can be evaluated.
60 Days to Success (Critical Program Management)
Authors: Scott R.A. , Duell Ken 
Published: October 2008

Abstract
This paper will describe the fast track method utilized by senior management of both EEX and Cal Dive to meet very critical scheduling requirements for the abandonment of the Garden Banks 388 (Cooper) Field in 2100 feet of water. Being the first deepwater abandonment, several ground-breaking procedures were employed, which included innovative economic considerations as well as challenging operational and contractual hurdles. The procedures utilized at Garden Banks 388 can be employed on certain abandonment projects where there is a requirement for production to be run up to the time limit of regulatory periods prior to shut in and removal of the facility. Commencement of the offshore activities utilizing well-proven traditional methods while specific procedures for each phase of the works is implemented independently. By limiting the number of personnel in the decision making and approval process, by instilling flexibility and excellent communications between the contractor, operator and regulatory parties a project can be moved forward with confidence on a true fast track basis. This enables offshore operations to commence prior to all of the typical project elements being in place and allows for rapid infield decisions and change in operational procedures when required

Discussion
In 1998, EEX Corporation (EEX) was facing a challenge that no one in the oil industry had faced before, the decommissioning and abandonment of a producing field (Figure 2) in water depths of 2,100 feet and deeper. EEX management reviewed their options on how to move on this formidable task. Should they hire an engineering company to work up the plans? Should they study it at EEX, come up with detailed plans and bid out the detailed work? EEX knew what had to be done. As the Nike-ism says "Just Do It!"
EEX had already begun the regulatory process in August 1998 and as of March 1999 the Minerals Management Service (MMS) permits had not been finalized or approvals granted for the project. Management at EEX knew that the permits would be granted but it was a matter of time when it would happen. EEX's hope was to remove the Floating Production Facility (FPF) and Free Standing Riser (FSR) before the hurricane season reached its peak in late August or early September.

Selection of the Main Contractor
The task seemed overwhelming but EEX had a secret weapon on their side... Trust. EEX management had decided up front that they were going to handle this project different from how other companies in the deepwater areas would handle it. Their trusting and open discussions with the MMS were working well at advancing the permitting process. Couldn't they use the same tact to get the plans for the fieldwork put together and executed? Management thought it was worth a try. EEX management and staff met to determine the essential needs for the project.
Troll Pilot Control System: Advanced Control System for a Subsea Separator
Authors: Baggs Chris , Kent Ian , Allen John 
Published: October 2008

ABSTRACT
This paper describes the design of a subsea control system for control and monitoring of a subsea water separator, for use by Norsk Hydro in the Troll field, offshore Norway. The separator uses a gravity separator to extract water from produced fluids. The water is then re-injected into a disposal well, via a subsea variable speed pump.
The control system comprises topside computers and fibre optic communication, together with a subsea control module for control of separator valves and monitoring of pressure, temperature and separator water level sensors. The system operates in a closed loop, with water level measurements resulting in control of the water injection pump speed.
Key feature is fibre-optic communication at 1.5 MHz, primarily for immunity from interference from the pump electrical supply, operating in half duplex mode on a single fibre. Full redundancy is provided for all electrical and optical equipment including sensors with 4 redundant communication channels.
The level sensors use a combination of technologies to give accurate and reliable, long-term measurements in the hostile separator environment.
A redundant high-speed general-purpose Fieldbus (DC power and communication) is provided subsea for connection of complex sensors (level sensor) plus others as required in the future.
Topside computers, which are fully integrated with the Troll C facility network, provide analysis of the data from dual level sensors, to detect the Interfaces between water, oil and gas, in the presence of emulsions and foam. This is used to control the pump speed in order to maintain a constant water level in the separator.
The equipment began integration and land trials in the last quarter of 1998, and was installed subsea in September 1999.

INTRODUCTION
The Troll field in block 31/2 and 31/5, 100 km west of Bergen, contains large quantities of oil and gas, together with significant amounts of water. It was decided therefore to install a subsea separator in order to avoid installing additional topside processing equipment and to maximise useful flowline capacity. Figure 1 shows the location of the installation and a diagram of the subsea arrangement, together with some basic field details.
The separator is a self-contained seabed unit, based on ABB Offshore Systems' SUBSIS technology and is located between two conventional production manifolds and the Troll C platform.

PROCESS SYSTEM
A simplified P&ID of the separation process is shown in figure 2. Essentially water, oil and gas flow into a large gravity separator tank, where the water sinks to the bottom and the oil floats on top, with gas filling the void at the top. The oil and gas flows over a weir plate and flows on to the Troll C platform under the driving pressure of the wells. The water is drawn out of the bottom of the tank and is injected into a disposal well by a large 1.6 M Watt subsea pump. Figures 3 and 4 show the pump and overall separator assembly.
Corrosion Control In the Splash Zone
Authors: Richardson Murl R. 
Published: October 2008

ABSTRACT
Offshore platforms, by the very nature of their existence in salt water, are vulnerable to corrosion. A particularly troublesome area of this costly phenomenon is the portion of the platform legs or risers exposed to the direct lapping of the waves at water level: the splash zone.
There are several methods by which metal corrosion can be controlled, including complete isolation of metal from the harmful elements which attack it. Several oil-producing companies have already demonstrated the effectiveness of a relatively indestructible neoprene cover on offshore platform legs to seal off the splash zone from corrosive attack.
The primary purpose of this report will be one of information. I propose to show the reasoning behind my company's selection of neoprene as the best possible isolator for platform legs and risers.
This will be accomplished by a discussion of some of the development work done in this area, including laboratory tests, and on-the-job installation tests. Also included will be a discussion of the economic advantages of using neoprene for corrosion control.
Since a good bond between metal and rubber is of prime importance in isolating the legs, I will discuss the aspects of rubber-to-metal adhesion, with special emphasis on surface preparation of the metal, application of the cement and rubber, and the vulcanization process itself.
It is anticipated that the information contained in this report is only the beginning of the contribution of neoprene coverings to the technology of offshore production in the future.

EARLY DEVELOPMENTS
Corrosion by the sea and nature is an everyday occurrence, and many techniques have been tried in attempting to control this corrosion, but until lately none have been relatively successful.
In 1965, we at Oil States Rubber Company were asked by a major oil company to attempt to solve the problem. Our approach was to completely isolate the metal from the corrosive tendency of the sea by the use of a synthetic rubber. The various synthetic rubbers were studied to find the best material that could be used in the given application.
The main requirements considered were:bondabilityresistance to sea water,resistance to oxygen and ozone,good tear strength, andabrasion resistance.
Two types of synthetic rubber met these requirements: neoprene and ethyleneproylene terpolymer.
(In that same year. 1965, Oil States' first corrosion control material was applied to a riser and still is in service and showing no bad effects from the elements and no cracking upon inspection.)

THE ALTERNATIVES
Ethylene-propylene terpolymer, which has an ASTM designation of EPDM, was ultimately eliminated. Although this material held up good in testing, there were difficulties encountered in the buildup process. It did not have enough building tack, at the time, to allow us to use it in production. This EPDM rubber was relatively new, then, and little was even known about its performance in sea water.
Dry-Tree Semi for Brazil and Gulf of Mexico
Authors: Often Ola , Ludwigson Robert , Carlsen Henning 
Published: October 2008

Abstract
A large number of dry tree concept's have been proposed to the offshore industry over the last few years for application in deepwater fields in the Gulf of Mexico, West Africa and Brazil. Looking into the details of these concepts, they all to a varying degree apply new and unproven technology that will increase project risk when brought to first use.
PGS Offshore Technology has over the last 3 years developed the Dry Tree Semi or DTS, which limits the cost and risk aspects of unproven technology by using a standard semi-submersible hull with top-tensioned risers suspended by large volume buoyancy cans. A Norwegian patent has been awarded, and US and international patents are pending for the riser support system developed for the DTS, which comprises a light weight truss tower placed in the centre of the hull. Conventional sliding or roller bearings provide lateral support to the buoyancy cans inside the riser support tower. The DTS concept avoids the disadvantage of dry tree concepts with riser tensioners, which rapidly loose payload capacity in deep water because of the increasing weights of the riser system. Compared to SPAR alternatives, the DTS has a substantially better steel weight to payload ratio. Also, installation costs are considerably reduced since offshore lifting and mating operations are not required.
At the OTC 2000 (ref. /1/), a DTS platform concept for West Africa was presented. This paper presents a DTS platform concept, primarily for use in the Gulf of Mexico, but also suitable for deepwater applications offshore Brazil.

Introduction
During the last two decades there has been a general trend towards higher oil recovery factors, and platform based or dry completed wells have a distinct advantage over subsea developments in this respect. There are a number of reasons for this, including amongst others, pressure drop in flowlines and limits on completion size, but even more importantly the cost and risk of performing subsea interventions. The latter reduces in practice the frequency of the whole range of recovery-enhancing measures such as logging, testing, reallocation, stimulation, recompletion etc.
The CAPEX costs for current platform designs with dry well completions increase however dramatically in deep water. The cost balance often tips the scale towards an FPSO and subsea development rather than the current dry completion unit alternatives, which are mainly TLP or mini-TLP in medium to deep water and Spar type platform in deep to ultra deep waters.
The most prolific deepwater exploration areas are currently West Africa, Brazil and Gulf of Mexico, ranging from benign to moderately harsh environments. The motivation for the DTS (Dry Tree Semi) development during the last 3 years has been to significantly reduce the cost of dry tree solutions for these main markets, starting with West Africa, which was subject for a paper presented at the OTC 2000 (ref. /1/). Subsequently, work has continued to extend the DTS application to Brazil and Gulf of Mexico (GoM).